Talos Energy (TALO) 10-K 13 Mar 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Mar. 06, 2019	Jun. 30, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Trading Symbol	TALO
Entity Registrant Name	Talos Energy Inc.
Entity Central Index Key	0001724965
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		54,155,805
Entity Public Float			$ 281,311,750

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 139,914	$ 32,191
Restricted cash	1,248	1,242
Accounts receivable
Trade, net	103,025	62,871
Joint interest, net	20,244	13,613
Other	19,686	12,486
Assets from price risk management activities	75,473	1,563
Prepaid assets	38,911	17,931
Inventory		840
Income tax receivable	10,701
Other current assets	7,644	2,148
Total current assets	416,846	144,885
Property and equipment:
Proved properties	3,629,430	2,440,811
Unproved properties, not subject to amortization	108,209	72,002
Other property and equipment	33,191	8,857
Total property and equipment	3,770,830	2,521,670
Accumulated depreciation, depletion and amortization	(1,719,609)	(1,430,890)
Total property and equipment, net	2,051,221	1,090,780
Other long-term assets:
Assets from price risk management activities		345
Other well equipment	9,224	2,577
Other assets	2,695	706
Total assets	2,479,986	1,239,293
Current liabilities:
Accounts payable	51,019	72,681
Accrued liabilities	188,650	87,973
Accrued royalties	38,520	24,208
Current portion of long-term debt	443	24,977
Current portion of asset retirement obligations	68,965	39,741
Liabilities from price risk management activities	550	49,957
Accrued interest payable	10,200	8,742
Other current liabilities	22,071	15,188
Total current liabilities	380,418	323,467
Long-term debt, net of discount and deferred financing costs	654,861	672,581
Asset retirement obligations	313,852	174,992
Liabilities from price risk management activities		18,781
Other long-term liabilities	123,359	103,559
Total liabilities	1,472,490	1,293,380
Commitments and contingencies (Note 11)
Stockholders' Equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of December 31, 2018 and December 31, 2017
Common stock $0.01 par value; 270,000,000 shares authorized; 54,155,768 and 31,244,085 shares issued and outstanding as of December 31, 2018 and December 31, 2017, respectively	542	312
Additional paid-in capital	1,334,090	493,952
Accumulated deficit	(327,136)	(548,351)
Total stockholders' equity (deficit)	1,007,496	(54,087)
Total liabilities and stockholders' equity	$ 2,479,986	$ 1,239,293

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
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	54,155,768	31,244,085
Common stock, shares outstanding	54,155,768	31,244,085

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Total revenue		$ 891,288	$ 412,828	$ 258,754
Operating expenses:
Workover and maintenance expense		64,961	32,825	24,810
Depreciation, depletion and amortization		288,719	157,352	124,689
Accretion expense		35,344	19,295	21,829
General and administrative expense		85,816	36,673	28,686
Total operating expenses		638,159	367,528	339,433
Operating income (loss)		253,129	45,300	(80,679)
Interest expense		(90,114)	(80,934)	(70,415)
Price risk management activities income (expense)	[1]	60,435	(27,563)	(57,398)
Other income		1,012	329	405
Net income (loss) before income taxes		224,462	(62,868)	(208,087)
Income tax expense		(2,922)
Net income (loss)		$ 221,540	$ (62,868)	$ (208,087)
Net income (loss) per common share:
Basic		$ 4.81	$ (2.01)	$ (7.99)
Diluted		$ 4.81	$ (2.01)	$ (7.99)
Weighted average common shares outstanding:
Basic		46,058	31,244	26,036
Diluted		46,061	31,244	26,036
Oil and Gas Properties
Operating expenses:
Direct lease operating expense		$ 145,988	$ 109,180	$ 124,360
Insurance		15,342	10,743	13,101
Production taxes		1,989	1,460	1,958
Total lease operating expense		163,319	121,383	139,419
Oil Revenue
Revenues:
Revenue		781,815	344,781	197,583
Natural Gas Revenue
Revenues:
Revenue		73,610	48,886	42,705
NGL Revenue
Revenues:
Revenue		$ 35,863	16,658	9,532
Other
Revenues:
Revenue			$ 2,503	$ 8,934
[1]	The Company paid cash settlements of $111.1 million, and received cash settlements of $23.8 million and $172.2 million for the years ended December 31, 2018, 2017 and 2016, respectively.

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT) - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-In Capital	Retained Earnings (Accumulated Deficit)
Balance at Dec. 31, 2015	$ 120,895	$ 258	$ 398,033	$ (277,396)
Contributions from Sponsors, net	91,891	54	91,837
Equity based compensation	2,287		2,287
Net loss	(208,087)			(208,087)
Balance at Dec. 31, 2016	6,986	312	492,157	(485,483)
Equity based compensation	1,795		1,795
Net loss	(62,868)			(62,868)
Balance at Dec. 31, 2017	(54,087)	312	493,952	(548,351)
Cumulative effect adjustment	(325)			(325)
Sponsor Debt Exchange	102,000	29	101,971
Stone Combination	731,964	201	731,763
Equity based compensation	6,404		6,404
Net loss	221,540			221,540
Balance at Dec. 31, 2018	$ 1,007,496	$ 542	$ 1,334,090	$ (327,136)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)		$ 221,540	$ (62,868)	$ (208,087)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion expense		324,063	176,647	146,518
Impairment		244	260	218
Amortization of deferred financing costs and original issue discount		4,253	2,383	5,996
Equity based compensation, net of amounts capitalized		2,893	875	1,083
Price risk management activities (income) expense	[1]	(60,435)	27,563	57,398
Net cash received (paid) on settled derivative instruments		(111,147)	23,834	172,182
Settlement of asset retirement obligations		(112,946)	(32,573)	(23,689)
Changes in operating assets and liabilities:
Accounts receivable		(786)	(9,132)	(20,096)
Other current assets		(2,624)	(4,441)	(3,040)
Accounts payable		(48,825)	2,409	(68,042)
Other current liabilities		32,044	46,364	51,240
Other non-current assets and liabilities, net		15,171	4,732	4,442
Net cash provided by operating activities		263,445	176,053	116,123
Cash flows from investing activities:
Exploration, development and other capital expenditures		(240,914)	(155,177)	(113,032)
Cash (paid) received for acquisitions, net of cash acquired		278,409	(2,464)	(85,886)
Net cash provided by (used in) investing activities		37,495	(157,641)	(198,918)
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt		(25,257)	(1,000)
Proceeds from Bank Credit Facility		319,000	10,000	15,000
Repayment of Bank Credit Facility		(54,000)	(15,000)	(10,000)
Deferred financing costs		(17,002)
Payments of capital lease		(12,952)	(12,412)	(5,267)
Contributions from Sponsors				93,750
Distributions to Sponsors				(1,859)
Net cash provided by (used in) financing activities		(193,211)	(18,412)	91,624
Net increase (decrease) in cash, cash equivalents and restricted cash		107,729		8,829
Cash, cash equivalents and restricted cash:
Balance, beginning of period		33,433	33,433	24,604
Balance, end of period		141,162	33,433	33,433
Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities		100,664	40,626	13,832
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized		53,476	47,994	55,254
LLC Bank Credit Facility
Cash flows from financing activities:
Repayment of Bank Credit Facility		$ (403,000)	$ (15,000)	$ (10,000)
[1]	The Company paid cash settlements of $111.1 million, and received cash settlements of $23.8 million and $172.2 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Formation and Basis of Presenta

Formation and Basis of Presentation	12 Months Ended
	Dec. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Formation and Basis of Presentation	Note 1 — Formation and Basis of Presentation Formation and Nature of Business Talos Energy Inc. (“Talos” or the “Company”) is a technically driven independent exploration and production company with operations in the United States (“U.S.”) Gulf of Mexico and offshore Mexico. The Company’s focus in the U.S. Gulf of Mexico is the acquisition of deep water assets with existing infrastructure and the exploration, exploitation and development of such assets in key geological trends. Offshore Mexico provides high impact exploration opportunities in an oil rich emerging basin. The Company uses access to an extensive seismic database and its deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. Talos Energy Inc. was formed in connection with the previously disclosed business combination between Talos Energy LLC and Stone Energy Corporation (“Stone”) that occurred on May 10, 2018, pursuant to which Talos Energy LLC and Stone became indirect wholly owned subsidiaries of Talos Energy Inc. Talos Energy LLC Talos Energy LLC was formed in 2011 and commenced commercial operations on February 6, 2013. Prior to February 6, 2013, Talos Energy LLC had incurred certain general and administrative expenses associated with the start-up of its operations. On February 3, 2012, Talos Energy LLC completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”, and together with the Apollo Funds, the “Sponsors”) and members of management pursuant to which the Company received a private equity capital commitment. Stone Combination On May 10, 2018 (the “Closing Date”), the Company (f/k/a Sailfish Energy Holdings Corporation) consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), by and among Stone, the Company, Sailfish Merger Sub Corporation (“Merger Sub”), Talos Energy LLC and Talos Production LLC, pursuant to which, among other items, each of Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of the Company (the “Stone Combination”). Prior to the Closing Date, the Company did not conduct any material activities other than those incident to its formation and the matters contemplated by the Transaction Agreement. On Closing Date, the following transactions, among others, occurred: (i) Stone underwent a reorganization pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and a direct wholly-owned subsidiary of the Company (the “Merger”) and each share of Stone’s common stock outstanding immediately prior to the Merger (other than treasury shares held by Stone, which were cancelled for no consideration) was converted into the right to receive one share of the Company’s common stock, par value $0.01 (the “Common Stock”) and (ii) the Sponsors contributed all of the equity interests in Talos Production LLC (which at that time owned 100% of the equity interests in Talos Energy LLC) to the Company in exchange for an aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”). Concurrently with the consummation of the Transaction Agreement, the Company consummated the transactions contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among the Company, Stone, the Talos Issuers (defined below), the various lenders and noteholders of the Talos Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% Senior Notes due 2022 (“9.75% Senior Notes”) issued by Talos Production LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to the Company in exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Debt Exchange”); (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (“11.00% Senior Secured Notes”) and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Secured Notes due 2022 issued by Stone (“7.50% Stone Senior Notes”) for $137.4 million aggregate principal amount of 11.00% Senior Secured Notes. Substantially concurrent therewith, the Company consummated an exchange offer and consent solicitation, pursuant to which the holders of the 7.50% Stone Senior Notes, excluding the 7.50% Stone Senior Notes held by the Franklin Noteholders and the MacKay Noteholders, exchanged their 7.50% Stone Senior Notes for 11.00% Senior Secured Notes and a cash payment, and a solicitation of consents to proposed amendments to the 7.50% Stone Senior Notes. Approximately $81.5 million in aggregate principal amount of the 7.50% Stone Senior Notes were validly tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Stone Senior Notes remained outstanding as of the Closing Date. As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange Agreement (the “Transactions”) the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Closing Date. Basis of Presentation and Consolidation The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include each subsidiary from the date of inception. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods are reflected herein. The Company has evaluated subsequent events through the date the consolidated financial statements were issued. Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, the historical financial and operating data of Talos Energy Inc., which covers periods prior to the Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC and does not reflect the assets, liabilities and results of operations of Stone. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Stockholders’ Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos Energy Inc. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. The Company has one reportable segment, which is the exploration and production of oil and natural gas. Substantially all the Company’s long-lived assets, proved reserves and production sales are related to the Company’s operations in the United States. Recently Adopted Accounting Standards Revenue Recognition On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers Revenue Recognition Extractive Activities – Oil and Gas – Revenue Recognition. 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 applied the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. 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. Under previous accounting guidance, the Company used the entitlement method to account for sales and production. Under the entitlement method, revenue was recorded based on the Company’s entitled share of production with any difference recorded as an imbalance on the consolidated balance sheet. Upon the adoption of ASC 606, 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. The change in accounting method from the entitlements method to the sales method resulted in an immaterial cumulative-effect adjustment to stockholders’ deficit on the date of adoption. Production Handling Fees. Under previous accounting guidance, the Company presented certain reimbursements for costs from certain third parties as other revenue on the consolidated statement of operations. Upon the adoption of ASC 606, the reimbursements are presented as a reduction of direct lease operating expense on the consolidated statement of operations. The impact of the reclassification for the year ended December 31, 2018 was immaterial . Recently Issued Accounting Standards Leases. In February 2016, the FASB issued ASU 2016-02, This ASU supersedes the lease requirements in Topic 840, , and requires that a lessee recognize a right-of-use asset and lease liability for leases that do not meet the definition of a short-term lease. The right-of-use asset and lease liability are to be measured on the balance sheet at the present value of the lease payments. For income statement purposes, ASU 2016-02 retains a dual model requiring leases to be classified as either operating or finance within the Company’s consolidated statements of operations. Lease costs for operating leases are recognized as a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. For finance leases, interest expense is recognized on the lease liability separately from amortization of the right-to-use asset. ASU 2016-02 does not apply to leases for oil and natural gas properties, but does apply to equipment used to explore and develop oil and natural gas reserves. This ASU is effective for fiscal years beginning after December 15, 2018, including the first quarter of 2019. The Company will adopt this standard using the modified retrospective method applied to all leases that exist on January 1, 2019. Talos made certain elections allowing the Company not to reassess contracts that commenced prior to adoption and to not recognize right-of-use assets or lease liabilities for short-term leases. Upon adoption, the Company expects the right-to-use asset and lease liability reported on the consolidated balance sheet to be material. The Company is finalizing the implementation of the changes to business processes, systems and controls to support accounting and disclosure requirements of this ASU.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Summary of Significant Accounting Policies	Note 2 — Summary of Significant Accounting Policies Below are the Company’s significant accounting policies. Cash and Cash Equivalents The Company presents cash as cash and cash equivalents on the Company’s consolidated balance sheets. The Company considers all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost, which approximates fair value. Accounts Receivable and Allowance for Uncollectible Accounts Accounts receivable are stated at the historical carrying amount net of an allowance for uncollectible accounts of $8.7 million at December 31, 2018 and $5.9 million at December 31, 2017. The Company establishes provisions for losses on accounts receivable with other parties if it believes that it will not collect all or part of the outstanding balance. On a quarterly basis, the Company reviews collectability and establishes or adjusts the Company’s allowance as necessary using the specific identification method. Prepaid Assets Prepaid assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”). The deposits are the Company’s estimated ONRR royalties payable within thirty days of the production rate. On a monthly basis the Company adjusts the deposit based on actual royalty payments remitted to the ONRR. Revenue Recognition Upon the adoption of ASC 606, revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. See Note 1 Formation and Basis of Presentation for additional information. 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. In August 2016, the Company entered into a capital lease for the use of the Helix Producer I (“HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy, and recorded a $124.3 million capital lease asset. Since the HP-I is utilized in the Company’s oil and natural gas development activities, the asset is included within proved property and subject to the ceiling test calculation described below. Due to the inclusion within proved properties, the HP-I is depleted as part of the full cost pool. See Note 11 — Commitments and Contingencies Capitalized costs associated with proved reserves are amortized on a country by country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least quarterly. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash impairment expense on the consolidated statement 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 utilize 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. The ceiling test computation did not result in a write-down of the Company’s oil and natural gas properties during the years ended December 31, 2018, 2017 and 2016. 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. The Company recognizes transportation costs as a component of direct lease operating expense when it is the shipper of the product. Such costs were $12.5 million, $10.3 million and $9.1 million in the years ended December 31, 2018, 2017 and 2016, respectively. Other Property and Equipment Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures, computer hardware and software. Acquisitions, renewals and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years. Other Well Equipment Inventory Other well equipment inventory primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When this inventory is supplied to wells, the cost of this inventory is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants. The Company’s inventory is stated at the lower of cost or net realizable value. The Company recorded $0.2 million, $0.3 million, $0.2 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in workover/maintenance expense, during the years ended December 31, 2018, 2017 and 2016, respectively. Fair Value Measure of Financial Instruments Financial instruments generally consist of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments. Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows: Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement. Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions, and are significant to the fair value measurement. Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows: Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost). Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models). Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. Asset Retirement Obligations The Company is required to record its asset retirement obligations at fair value in the period such obligations are incurred with the associated asset retirement costs being capitalized as part of the carrying cost of the asset. The Company’s asset retirement obligations consist of estimated costs for dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and natural gas properties. The estimate of the asset retirement cost is determined, inflated to an estimated future value using a ten year average of the Consumer Price Index and discounted to present value using the Company’s credit-adjusted risk-free rate. Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values. Price Risk Management Activities The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. Commodity derivatives are recorded on the consolidated balance sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in price risk management activities income (expense) in the consolidated statements of operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes. The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company then utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable. Income Taxes Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. In connection with the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to U.S. federal and state income taxes. The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the consolidated balance sheets. The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations. The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expense, respectively. Earnings Per Share Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of restricted stock units (“RSUs”), performance share units (“PSUs”) and outstanding warrants. See Note 9 — Earnings Per Share Share-Based Compensation Certain of the Company’s employees participate in its equity based compensation. The Company measures all employee equity based compensation awards at fair value as calculated using an option pricing method for valuing such securities on the date awards are granted to its employees and recognize compensation cost on a straight-line basis in the Company’s financial statements over the vesting period of each grant according to ASC 718, Compensation—Stock Compensation. During 2018, the Company issued RSUs and PSUs to certain employees and non-employee directors. The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity, but is remeasured at each reporting period for awards classified as a liability. The Company records share-based compensation, net of actual forfeitures, for the RSUs and PSUs in general and administrative expense on the consolidated statement of operations, net of amounts capitalized to oil and gas properties. See Note 7 — Employee Benefits Plans and Share-Based Compensation RSUs. Share-based compensation is based on the market price of the Company’s Common Stock on the grant date and recognized over the vesting period using the straight-line method as the requisite service period is fulfilled. PSUs. Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over the vesting period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of Common Stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the Company’s total shareholder return (“TSR”) relative to the TSR achieved by a specified industry peer group. Share-based compensation related to PSUs is recognized as the requisite service period is fulfilled, even if the market condition is not achieved Concentration of Credit Risk Consisting principally of cash and cash equivalents, restricted cash, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk. Cash and cash equivalents and restricted cash 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, the majority 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 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, 2018 2017 2016 Shell Trading (US) Company 65 % 80 % 68 % Phillips 66 18 % ** ** Chevron U.S.A Inc. ** ** 14 % ** 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, 2018
Business Combinations [Abstract]
Acquisitions	Note 3 — Acquisitions Business Combination Combination Between Talos Energy LLC and Stone Energy Corporation The Stone Combination qualified as a business combination and was 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 sheet at their fair values as of the acquisition date, May 10, 2018. 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. On May 10, 2018, the Company consummated the Transactions contemplated by the Transaction Agreement and Exchange Agreement, pursuant to which, among other things, Talos Energy LLC and Stone became wholly-owned subsidiaries of the Company. The combination was executed as an all-stock transaction whereby the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Closing Date. The purchase price of $732.0 million is based on the closing price of Stone common stock and common warrants immediately prior to closing. The following table summarizes the purchase price (in thousands, except per share data): Stone Energy common stock - issued and outstanding as of May 9, 2018 20,038 Stone Energy common stock price $ 35.49 Common stock value $ 711,149 Stone Energy common stock warrants - issued and outstanding as of May 9, 2018 3,528 Stone Energy common stock warrants price $ 5.90 Common stock warrants value $ 20,815 Total purchase price $ 731,964 The Company incurred approximately $88.6 million of transaction related costs, of which, $32.5 million was expensed and reflected in general and administrative expense on the consolidated statement of operations. The remaining $56.1 million was the result of (i) $9.3 million in work fees paid to holders of the 11.00% Senior Secured Notes reflected as a debt discount reducing long-term debt on the consolidated balance sheet and (ii) $46.8 million in fees for seismic use agreements for change in control provisions and reflected in proved properties on the consolidated balance sheet. While the Company has substantially completed the determination of the fair values of the assets acquired and liabilities assumed, the Company is still finalizing the fair value analysis related to oil and natural gas properties acquired by Stone prior to Closing. The Company anticipates finalizing the determination of the fair values by March 31, 2019. During the third and fourth quarters of 2018, certain adjustments were recorded to reflect new information obtained subsequent to recording the preliminary allocation of the purchase price. Income tax receivables decreased by $5.5 million, trade receivables increased by $1.0 million, other long-term liabilities increased by $2.7 million and unproved properties increased by $7.2 million. Had these adjustments been recorded as of the acquisition date, May 10, 2018, there would have been no corresponding impact to net income subsequent to the acquisition. These adjustments are reflected in the preliminary purchase price allocation table below. The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on May 10, 2018 (in thousands): Current assets (1) $ 372,760 Property and equipment 883,490 Other long-term assets 18,928 Current liabilities (130,062 ) Long-term debt (235,416 ) Other long-term liabilities (177,736 ) Allocated purchase price $ 731,964 (1) Includes $293.0 million of cash acquired. The fair values of current assets acquired includes trade receivables and joint interest receivables of $43.3 million and $3.5 million, respectively, which the Company expects all to be realizable. Revenue and net income attributable to the assets acquired in the Stone Combination during the year of December 31, 2018 was $332.9 million $148.5 million, respectively. Pro Forma Financial Information (Unaudited) The following supplemental pro forma information (in thousands, except per common share amounts), presents the consolidated results of operations for the years ended December 31, 2018 and 2017 as if the Stone Combination had occurred on January 1, 2017. The unaudited pro forma information was derived from historical statements of operations of the Company and Stone and adjusted to include (i) depletion and accretion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect the debt transactions contemplated by the Exchange Agreement and (iii) general and administrative expense adjusted for transaction related costs incurred. This information does not purport to be indicative of results of operations that would have occurred had the Stone Combination occurred on January 1, 2017, nor is such information indicative of any expected future results of operations. Year Ended December 31, 2018 2017 Revenue $ 1,013,184 712,648 Net income (loss) $ 274,577 (100,980 ) Basic and diluted net income (loss) per common share $ 5.07 $ (1.86 ) Material, non-recurring adjustments included in pro forma net income (loss) above consist of historical Stone results adjusted to exclude a divestiture of oil and natural gas properties during 2017. Asset Acquisitions Each of the acquisitions below qualified as an asset acquisition that requires, among other items, that the cost of the assets acquired and liabilities assumed to be recognized on the balance sheet 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 Whistler Energy II, LLC On August 31, 2018, the Company completed the acquisition of all the issued and outstanding membership interests of Whistler Energy II, LLC (“Whistler”) from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds, for $52.6 million ($14.8 million, net of $37.8 million of cash acquired). The $37.8 million of cash acquired consists of $30.8 million of cash collateral posted by Whistler and released by third party surety companies at closing and $7.0 million of cash on hand for working capital purposes. Through the acquisition, the Company acquired all of Whistler’s oil and natural gas assets located in Green Canyon Block 18, Green Canyon Block 69 and Ewing Bank Block 988, including a fixed production platform on Green Canyon Block 18. The Company also assumed the associated asset retirement obligations. The Company refers to the acquisition of all the issued and outstanding membership interests as the “Whistler Acquisition.” The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on August 31, 2018 (in thousands): Current assets (1) $ 45,337 Property and equipment 35,344 Other long-term assets 66 Current liabilities (4,261 ) Asset retirement obligations (23,862 ) Allocated purchase price $ 52,624 (1) Includes $37.8 million of cash acquired and trade receivables of $3.2 million, which the Company expects all to be realizable. Acquisition of Additional Working Interest in the Phoenix Field On December 20, 2016, the Company purchased an additional 15% working interest in the Phoenix Field from Sojitz Energy Venture Inc. (“Sojitz”) for approximately $85.8 million in cash and the assumption of certain asset retirement obligations, subject to customary post-closing adjustments. The purchase price was funded by a $93.8 million ($91.9 million, net of $1.9 million of transaction fees) contribution from the Sponsors. Additionally, the Company entered into a contingent consideration arrangement in the form of an earn-out equal to 5% of the acquired property’s monthly net profit if its realized oil price is greater than $65.00 per Bbl in a given month. The maximum payout under the earn-out is $10.0 million and it has an indefinite life pursuant to the purchase and sale agreement. The Company refers to the acquisition of assets from Sojitz as the “Sojitz Acquisition.” Through December 31, 2017, the Company recorded $2.5 million in post-closing adjustments related to activity between the effective date and closing date of the acquisition. The following table presents the allocation of the purchase price (inclusive of post-closing adjustments) to the assets acquired and liabilities assumed, based on their relative fair values, on December 20, 2016 (in thousands): Proved properties $ 77,967 Unproved properties, not subject to amortization 11,133 Other short and long-term assets 2,380 Asset retirement obligations (3,242 ) Allocated purchase price $ 88,238

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2018
Oil And Gas Property [Abstract]
Property, Plant and Equipment	Note 4 — Property, Plant and Equipment Proved Properties. The Company’s interests in oil and natural gas proved properties are located in the United States, primarily in the Gulf of Mexico deep and shallow waters. The Company follows the full cost method of accounting for its oil and natural gas exploration and development activities. In August 2016, the Company entered into a capital lease for the use of the HP-I and recorded a $124.3 million capital lease asset. Since the HP-I is utilized in its oil and natural gas development activities, the asset is included within proved property, subject to the ceiling test calculation described below, and is depleted as part of the full cost pool. Pursuant to SEC Regulation S-X, Rule 4-10, under the full cost method of accounting, the Company’s capitalized oil and natural gas costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. The Company performs this ceiling test calculation each quarter utilizing SEC pricing. During 2018, 2017 and 2016, the Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties. At December 31, 2018, its ceiling test computation was based on SEC pricing of $69.42 per Bbl of oil, $3.08 per Mcf of natural gas and $29.50 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, costs associated with certain exploratory wells in progress and capitalized interest. Unproved properties also include costs associated with the two blocks (Block 2 and Block 7) awarded on September 4, 2015 to the Company together with Sierra Oil & Gas S. de R.L de C.V. (“Sierra”) and Premier Oil Plc (“Premier”), the (“Consortium”), located in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states, by the National Hydrocarbons Commission (“CNH”), Mexico’s upstream regulator. In September 2018, the Company entered into a transaction (the “Hokchi Cross Assignment”) with Hokchi Energy, S.A. de C.V. (“Hokchi”), a subsidiary of Pan American Energy (“PAE”), to cross assign 25% participation interests (“PIs”) in Block 2 and Block 31. The Company’s assignment of a 25% PI in Block 2 to Hokchi closed on December 21, 2018, and Hokchi has assumed operator responsibilities with respect to Block 2. Hokchi’s assignment of Block 31 to the Company will be completed upon final approval by the CNH subsequent to December 31, 2018. In addition, Premier exercised its option to reduce its PI in Block 2 to zero and assign a 5% PI to each of Sierra and the Company. Such assignment is also subject to CNH’s approval which had not occurred as of December 31, 2018. Upon completion of the Hokchi Cross Assignment and Premier’s option exercise, the Company will own a 25% PI in each of Block 2 and Block 31, and Hokchi will be the operator of both blocks. The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2018, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2018 2017 2016 2015 and Prior Acquisition United States $ 49,777 $ 40,657 $ — $ 2,244 $ 6,876 Exploration United States 13,327 8,391 3,188 92 1,656 Total United States unproved properties, not subject to amortization $ 63,104 $ 49,048 $ 3,188 $ 2,336 $ 8,532 Exploration Mexico 45,105 14,362 23,332 6,110 1,301 Total Mexico unproved properties, not subject to amortization $ 45,105 $ 14,362 $ 23,332 $ 6,110 $ 1,301 Total unproved properties, not subject to amortization $ 108,209 $ 63,410 $ 26,520 $ 8,446 $ 9,833 The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined. The Company expects this process to occur over the next five years. Capitalized Overhead. General and administrative expense in the Company’s financial statements is reflected net of capitalized overhead. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities. Capitalized overhead for the years ended December 31, 2018, 2017 and 2016 was $21.9 million, $13.7 million and $12.5 million, respectively. 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 in the table below 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 in the Company’s consolidated statements of operations. If the Company incurs an amount different from the amount accrued for decommissioning obligations, the Company recognizes the difference as an adjustment to proved properties. The discounted asset retirement obligations included in the consolidated balance sheets in current and non-current liabilities, and the changes in that liability during each of the years ended December 31, 2018 and 2017 were as follows (in thousands): Year Ended December 31, 2018 2017 Asset retirement obligations at January 1 $ 214,733 $ 220,049 Fair value of asset retirement obligations acquired (1) 244,766 699 Obligations settled (112,946 ) (32,573 ) Accretion expense 35,344 19,295 Obligations incurred 358 4,213 Changes in estimate 562 3,050 Asset retirement obligations at December 31 $ 382,817 $ 214,733 Less: Current portion (68,965 ) (39,741 ) Long-term portion $ 313,852 $ 174,992 (1) Includes $220.6 million and $23.9 million of asset retirement obligations assumed in the Stone Combination and the Whistler Acquisition, respectively.

Financial Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2018
Financial Instruments [Abstract]
Financial Instruments	Note 5 — Financial Instruments The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments (in thousands): December 31, 2018 December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value 11.00% Second-Priority Senior Secured Notes – due April 2022 (1) $ 381,229 $ 362,168 $ — $ — 7.50% Senior Secured Notes – due May 2022 $ 6,060 $ 5,151 $ — $ — Bank Credit Facility – due May 2022 (1) $ 257,448 $ 265,000 $ — $ — 11.00% Bridge Loans – due April 2022 (1) $ — $ — $ 169,838 $ 172,023 9.75% Senior Notes – due July 2022 (1) $ — $ — $ 100,681 $ 102,000 9.75% Senior Notes – due February 2018 $ — $ — $ 24,977 $ 24,977 LLC Bank Credit Facility - due February 2019 (1) $ — $ — $ 402,062 $ 403,000 Oil and Natural Gas Derivatives $ 74,923 $ 74,923 $ (66,830 ) $ (66,830 ) (1) The carrying amounts are net of discount and deferred financing costs. As of December 31, 2018 and 2017, the carrying amounts of cash and cash equivalents, accounts receivable, restricted cash and accounts payable approximate their fair values because of the short-term nature of these instruments. 11.00% Second-Priority Senior Secured Notes – due April 2022. The $390.9 million aggregate principal amount of 11.00% Senior Secured Notes is reported on the consolidated balance sheet at its carrying value, net of original issue discount and deferred financing costs, see Note 6 — . The fair value of the 11.00% Senior Secured Notes is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices. 7.50% Senior Secured Notes – due May 2022 . The $6.1 million aggregate principal amount of 7.50% Stone Senior Notes is reported on the consolidated balance sheet as of December 31, 2018 at its carrying value, see Note 6 — . The fair value of the 7.50% Stone Senior Notes is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices. Bank Credit Facility – due May 2022. On May 10, 2018, in connection with the Stone Combination, the Talos Energy LLC senior reserve-based revolving credit facility (“LLC Bank Credit Facility”) was repaid and terminated, and the Company executed a new Bank Credit Facility with an initial borrowing base of $600.0 million (the “Bank Credit Facility”). The LLC Bank Credit Facility was repaid with borrowings from the Bank Credit Facility and cash acquired in the Stone Combination. The Company’s Bank Credit Facility is reported on the consolidated balance sheet as of December 31, 2018 at its carrying value net of deferred financing costs, see Note 6 — . The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the Company’s Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement). Oil and natural gas derivatives. The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Collar contracts typically require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the consolidated balance sheet 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 qualifying as hedging instruments, had on its consolidated statements of operations (in thousands): Year Ended December 31, 2018 2017 2016 Price risk management activities income (expense) (1) $ 60,435 $ (27,563 ) $ (57,398 ) (1) The Company paid cash settlements of $111.1 million, and received cash settlements of $23.8 million and $172.2 million for the years ended December 31, 2018, 2017 and 2016, respectively. The following table reflects the contracted volumes and weighted average prices the Company will receive under its derivative contracts as of December 31, 2018: Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Weighted Average Put Price Weighted Average Call Price Crude Oil – WTI: (Bbls) (per Bbl) (per Bbl) (per Bbl) January 2019 – December 2019 Swap 25,059 $ 55.39 $ — $ — Natural Gas – Henry Hub NYMEX: (MMBtu) (per MMBtu) (per MMBtu) (per MMBtu) January 2019 – December 2019 Collar 8,630 $ — $ 3.00 $ 3.95 January 2019 – December 2019 Swaps 21,872 $ 2.90 $ — $ — Subsequent event. The following table reflects the contracted volumes and weighted average prices the Company will receive under its derivative contracts entered into subsequent to December 31, 2018, which are not reflected in the table above: Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Weighted Average Put Price Weighted Average Call Price Crude Oil – WTI: (Bbls) (per Bbl) (per Bbl) (per Bbl) April 2019 – December 2019 Swap 3,444 $ 56.94 $ — $ — January 2020 - December 2020 Swap 3,746 $ 57.07 $ — $ — January 2020 - December 2020 Collar 3,000 $ 55.00 $ 55.00 $ 60.64 Natural Gas – Henry Hub NYMEX: (MMBtu) (per MMBtu) (per MMBtu) (per MMBtu) April 2019 – December 2019 Swap 19,418 $ 2.89 $ — $ — The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands): December 31, 2018 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 75,473 $ — $ 75,473 Liabilities: Oil and natural gas swaps and costless collars — (550 ) — (550 ) Total net asset $ — $ 74,923 $ — $ 74,923 December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 1,908 $ — $ 1,908 Liabilities: Oil and natural gas swaps and costless collars — (68,738 ) — (68,738 ) Total net liability $ — $ (66,830 ) $ — $ (66,830 ) 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 present its derivative financial instruments on a gross basis in its consolidated balance sheets. On derivative contracts recorded as assets in the table below, the Company is exposed to the risk the counterparties may not perform. The following table presents the fair value of derivative financial instruments at December 31, 2018 and 2017 (in thousands): December 31, 2018 December 31, 2017 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 75,473 $ 550 $ 1,563 $ 49,957 Non-current — — 345 18,781 Total $ 75,473 $ 550 $ 1,908 $ 68,738 Credit Risk. The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at December 31, 2018 represent derivative instruments from nine counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and seven 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, 2018
Debt Disclosure [Abstract]
Debt	Note 6 — 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): Description December 31, 2018 December 31, 2017 11.00% Second-Priority Senior Secured Notes – due April 2022 $ 390,868 $ — 7.50% Senior Secured Notes – due May 2022 6,060 — Bank Credit Facility – due May 2022 265,000 — 4.20% Building Loan – due November 2030 10,567 — 11.00% Bridge Loans – due April 2022 — 172,023 9.75% Senior Notes – due July 2022 — 102,000 9.75% Senior Notes – due February 2018 — 24,977 LLC Bank Credit Facility – due February 2019 — 403,000 Total debt, before discount and deferred financing cost 672,495 702,000 Discount and deferred financing cost (17,191 ) (4,442 ) Total debt, net of discount and deferred financing costs 655,304 697,558 Less: Current portion of long-term debt (443 ) (24,977 ) Long-term debt, net of discount and deferred financing costs $ 654,861 $ 672,581 In connection with the Stone Combination, the Company consummated the Transactions, pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% Senior Notes to the Company in exchange for Common Stock; (ii) the holders of 11.00% Bridge Loans exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Senior Secured Notes and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Stone Senior Notes for $137.4 million aggregate principal amount of 11.00% Senior Secured Notes. An additional $81.5 million of 7.50% Stone Senior Notes held by non-affiliates were also exchanged for 11.00% Senior Secured Notes pursuant to an exchange offer and consent solicitation in connection with the Stone Combination. The exchanges to 11.00% Senior Secured Notes were accounted for as a debt modification. Under a debt modification, a new effective interest rate that equates the revised cash flows to the carrying amount of the 11.00% Senior Secured Notes is computed and applied prospectively. Costs incurred with third parties directly related to the modification are expensed as incurred. The Company incurred approximately $4.3 million of transaction fees related to the modification which were expensed and reflected in general and administrative expense on the consolidated statements of operations during the year ended December 31, 2018. The Company also paid $9.3 million in work fees to holders of the 11.00% Senior Secured Notes, which are reflected as debt discount reducing long-term debt on the consolidated balance sheet. 11.00% Second-Priority Senior Secured Notes – due April 2022 . The 11.00% Senior Secured Notes were issued pursuant to an indenture dated May 10, 2018, between the Talos Issuers, the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 11.00% Senior Secured Notes mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15. Prior to May 10, 2019, the Company may, at its option, redeem all or a portion of the 11.00% Senior Secured Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 11.00% Senior Secured Notes at redemption prices decreasing annually from 105.5% to 100.0% plus accrued and unpaid interest. The indenture governing the 11.00% Senior Secured Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur additional indebtedness or issue certain preferred shares; (ii) pay dividends and make certain other restricted payments; (iii) create restrictions on the payment of dividends or other distributions to the Company from its restricted subsidiaries; (iv) create liens on certain assets to secure debt; (v) make certain investments; (vi) engage in sales of assets and subsidiary stock; (vii) transfer all or substantially all of its assets or enter into merger or consolidation transactions; and (viii) engage in transactions with affiliates. The 11.00% Senior Secured Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2018. 7.50% Senior Secured Notes – due May 2022 . The 7.50% Stone Senior Notes represent the remaining $6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for 11.00% Senior Secured Notes pursuant to the Exchange Offer and Consent Solicitation, and thus remain outstanding. As a result of the exchange offer and consent solicitation, substantially all of the restrictive covenants relating to the 7.50% Stone Senior Notes have been removed and collateral securing the 7.50% Stone Senior Notes has been released. The 7.50% Stone Senior Notes mature May 31, 2022 and have interest payable semi-annually each May 31 and November 30. Prior to May 31, 2020, the Company may, at its option, redeem all or a portion of the 7.50% Stone Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 7.50% Stone Senior Notes at redemption prices decreasing annually from 105.625% to 100.0% plus accrued and unpaid interest. Bank Credit Facility – due May 2022. Talos Production LLC, a subsidiary of the Company, executed the Bank Credit Facility in conjunction with the Stone Combination with a syndicate of financial institutions, with an initial borrowing base of $600.0 million. The Bank Credit Facility is currently scheduled to mature on May 10, 2022. The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. In addition, the Company is obligated to pay a commitment fee of 0.50% on the unfunded portion of the commitments under the Bank Credit Facility. The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a total debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 each quarter. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter. According to the Bank Credit Facility, undrawn commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by substantially all of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries. The Bank Credit Facility provides for determination of the borrowing base based on the Company’s proved producing reserves and a portion of its proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter. On November 16, 2018 the borrowing base was increased from $600.0 million to $850.0 million. However, the Company elected to maintain the $600.0 million commitment based upon its current liquidity needs. The next redetermination is scheduled for April 2019. As of December 31, 2018, commitments under the Company’s borrowing base was set at $600.0 million, of which no more than $200.0 million can be used as letters of credit. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. The Company was in compliance with all debt covenants at December 31, 2018. As of December 31, 2018, the Bank Credit Facility had approximately $320.3 million of undrawn commitments (taking into account $14.7 million letters of credit and $265.0 million drawn from the Bank Credit Facility). Building Loan – due November 2030 . In connection with the Stone Combination, the Company assumed Stone’s 4.20% term loan maturing on November 20, 2030 (the “Building Loan”). The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of approximately $0.1 million. As of December 31, 2018, the outstanding balance under the Building Loan totaled $10.6 million. The Building Loan is collateralized by the Company’s two office buildings in Lafayette, Louisiana. Under the financial covenants of the Building Loan, the Company must maintain a ratio of EBITDA to Net Interest Expense of not less than 2.00 to 1.00. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities. The Company was in compliance with all covenants under the Building Loan as of December 31, 2018. 9.75% Senior Notes – due February 2018 . The 2018 Senior Notes were issued pursuant to an indenture dated February 6, 2013 among the Talos Issuers, the subsidiaries, as issuers, the subsidiary guarantors party thereto and the trustee. On February 15, 2018, the Talos Issuers redeemed the remaining $25.0 million principal amount of the 9.75% Senior Notes at par. Subsequent Event. On January 22, 2019, the Company borrowed $35.0 million from the Bank Credit Facility to fund 2019 acquisition activities, see Note 15 — Subsequent Events .

Employee Benefits Plans and Sha

Employee Benefits Plans and Share-Based Compensation	12 Months Ended
	Dec. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Employee Benefits Plans and Share-Based Compensation	Note 7 — Employee Benefits Plans and Share-Based Compensation Stone Change of Control and Severance Plans T he Company maintains the Stone Energy Corporation Executive Severance Plan and Stone Energy Corporation Employee Severance Plan, each a legacy plan of Talos Petroleum LLC (f/k/a Stone Energy Corporation). The plans provide for the payment of severance and change in control benefits to certain individuals who, prior to the Stone Combination, were executive officers or employees of Talos Petroleum LLC, in each case upon an involuntary termination within twelve months of Closing. For the year ended December 31, 2018 the Company incurred $7.8 million of severance expense, reflected in general and administrative expense on the consolidated statement of operations. Approximately $0.3 million of such expense remained unpaid at December 31, 2018. Talos Energy Inc. Long Term Incentive Plan In connection with the Closing, the Company adopted the Talos Energy Inc. Long Term Incentive Plan (the “LTIP”), pursuant to which the Company may issue, subject to Board approval, grants of options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards or any combination of the foregoing to employees, directors and consultants. The LTIP authorizes the Company to grant awards of up to 5,415,576 shares of the Company’s Common Stock. Restricted Stock Units – Employees . During the year ended December 31, 2018, the Company granted 116,448 RSUs under the LTIP to employees. These RSUs had a grant date fair value of $3.9 million and vest ratably over an approximate three year period, which began on May 14, 2018, 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, 2018 was approximately $3.3 million, which is expected to be recognized over a weighted average period of 2.4 years. Restricted Stock Units – On May 21, 2018, the Company granted 22,963 RSUs under the LTIP to non-employee directors. These RSUs had a grant date fair value of $0.8 million and vest on May 19, 2019, 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% or 13,778 of these RSUs, and cash for the remaining 40% or 9,185 of these RSUs. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2018 was approximately $0.2 million, which is expected to be recognized over a weighted average period of 0.4 years. Of the unrecognized share-based compensation expense, $0.1 million relates to liability awards and will be subsequently remeasured at each reporting period. The following table summarizes RSU activity for the year ended December 31, 2018: Restricted Stock Units Weighted Average Grant Date Fair Value Unvested RSUs at December 31, 2017 — $ — Granted 139,411 33.85 Vested (53 ) 32.86 Forfeited (654 ) 32.86 Unvested RSUs at December 31, 2018 138,704 $ 33.85 Performance Share Units – Employees. During the year ended December 31, 2018, the Company granted 232,891 PSUs to employees with each PSU representing the contingent right to receive one share of Common Stock. However, the number of Common Stock shares issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the total shareholder return (“TSR”) of the Common Stock relative to the TSR achieved by a specific industry peer group over an approximate three-year performance period, the last day of which is also the vesting date. The total unrecognized share-based compensation expense related to these PSUs at December 31, 2018 was approximately $9.2 million, which is expected to be recognized over a weighted average period of 2.4 years. The following table summarizes PSU activity for the year ended December 31, 2018: Performance Share Units Weighted Average Grant Date Fair Value Unvested PSUs at December 31, 2017 — $ — Granted 232,891 44.47 Vested — — Forfeited (1,349 ) 42.94 Unvested PSUs at December 31, 2018 231,542 $ 44.47 The grant date fair value of the PSUs, calculated using a Monte Carlo simulation, was $10.4 million. The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted August 29, 2018 and September 28, 2018: August 29, 2018 Grant Date Fair Value Assumptions September 28, 2018 Grant Date Fair Value Assumptions Number of simulations 100,000 100,000 Expected term (in years) 2.7 2.6 Expected volatility 50.6 % 47.4 % Risk-free interest rate 2.7 % 2.9 % Dividend yield — % — % Talos Energy LLC Series B Units Prior to the Stone Combination, the Limited Liability Company Agreement of Talos Energy LLC established Series A, Series B and Series C Units. Series B Units were generally intended to be used as incentives for Company employees. Series B Units do not participate in distributions prior to vesting or until Series A Units have received cumulative distributions equal to (i) the original cash contributed to the Company for such Series A Units and (ii) an 8% return, compounded annually (the “Aggregate Series A Payout”), and Series C Units have received $25.0 million in distributions. In connection with the Transactions, the Series A, Series B and Series C Units were exchanged for an equivalent number of units in each of an entity affiliated with the Apollo Funds and an entity affiliated with the Riverstone Funds, each of which hold Common Stock of the Company. The modification did not result in incremental value to the Series B Units. For accounting and financial reporting purposes, the Series B Units are deemed to be equity awards, and the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the Company’s consolidated financial statements and is reflected as a corresponding credit to accumulated deficit on the consolidated balance sheet. The Company’s unrecognized compensation expense at December 31, 2018 is approximately $2.7 million. Of this amount, approximately $0.5 million of the unrecognized compensation expense will continue to be recognized on a straight-line basis over the remainder of the four year requisite service period. The remaining $2.2 million will be recognized upon an Aggregate Series A Payout. The weighted-average period over which the unrecognized compensation expense for the Series B Units will be recognized is 1.7 years. New Talos Energy LLC Series B Units In connection with the transactions contemplated in the Exchange Agreement on May 10, 2018, an entity affiliated with the Apollo Funds and an entity affiliated with the Riverstone Funds, each of which hold Common Stock in the Company as a result of the Sponsor Debt Exchange, established new Series A Units (“New Series A Units”) and new Series B Units (“New Series B Units”). The New Series B Units are generally intended to be used as incentives for Company employees. The New Series B Units do not participate in distributions prior to vesting or until the New Series A Units have received cumulative distributions of $102.0 million. After issuance, 80% of the New Series B Units vest on a monthly basis over a four year period based on the initial vesting schedule of the original Series B Units, subject to continued employment. All unvested New Series B Units fully vest upon the cumulative distribution of $102.0 million. For accounting and financial reporting purposes, the New Series B Units are deemed to be equity awards, and the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the Company’s consolidated financial statements and is reflected as a corresponding credit to accumulated deficit on the consolidated balance sheet. The New Series B Units issued were valued using the option pricing method for valuing securities. In this method, the rights and claims of each security are modeled as a portfolio of Black-Scholes-Merton call options written on the total equity of the entities affiliated with the Apollo Funds and Riverstone Funds. The total value of the equity is calculated in an iterative process that results in the New Series A Units being valued at par. The risk-free rate of interest is based on the U.S. Treasury yield curve on the grant date. The expected time to a liquidity event is based on a weighted average calculation of management’s estimate considering market conditions and expectations. The expected volatility of equity is based on the volatility of the assets of similar publicly traded companies using a Black-Scholes-Merton model. The discount for lack of marketability is based on the restrictions on the New Series B Units and the volatility of the New Series B Units using a Black-Scholes-Merton model. The Company’s unrecognized compensation expense at December 31, 2018 is approximately $1.2 million. Of this amount, approximately $0.2 million of the unrecognized compensation expense will continue to be recognized on a straight-line basis over the remainder of the four year requisite service period. The remaining $1.0 million will be recognized upon the New Series A Units receiving the cumulative distribution. The weighted-average period over which the unrecognized compensation expense will be recognized is 0.8 months. Share-based Compensation Expense, net Share-based compensation expense associated with RSUs, PSUs and Series B Units are reflected as general administrative expense, net amounts capitalized to oil and gas properties in the consolidated statement of operations. 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 used in or provided by operating activities in the consolidated statement of cash flows. For the year ended December 31, 2018, share-based compensation expense did not have any associated income tax benefit. The Company recognized the following share-based compensation expense, net for the following years (in thousands): Year Ended December 31, 2018 2017 2016 Restricted stock units - Employees $ 560 $ — $ — Restricted stock units - Non-employee Directors 402 — — Performance share units 1,129 — — Talos Energy LLC Series B Units 666 1,795 2,287 New Talos Energy LLC Series B Units 3,752 — — Total share-based compensation expense 6,509 1,795 2,287 Less: amounts capitalized to oil and gas properties (3,616 ) (920 ) (1,204 ) Total share-based compensation expense, net $ 2,893 $ 875 $ 1,083

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Note 8 — Income Taxes Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. Talos Energy LLC’s operations in the shallow waters off the coast of Mexico were conducted under a different legal form and are subject to foreign income taxes. In connection with the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to federal and state income taxes. The Company is also subject to foreign income taxes. Due to the change in tax status, deferred taxes are recorded for differences in book and tax basis. The Company’s differences in its book and tax basis in its assets and liabilities is primarily related to different cost recovery periods utilized for book and tax purposes for the Company’s oil and natural gas properties, asset retirement obligations and net operating loss carryforwards. A valuation allowance is established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax asset will not be realized. The Company believes it is more likely than not that the net federal deferred tax asset will not be realized and therefore recorded a valuation allowance. Due to the valuation allowance, the tax expense resulting from the initial book and tax basis difference from the change in tax status was zero. The Company accounted for the book and tax basis difference from the Stone Combination in acquisition method accounting and recorded an estimated state deferred tax liability of $2.7 million. As part of the Stone Combination, entities related to the Apollo Funds and Riverstone Funds contributed entities to the Company that were under common control. At December 31, 2018, the Company also estimated a net deferred tax asset related to tax loss carryforwards and differences in book and tax basis of assets. The net deferred tax asset and valuation allowance from the contribution is accounted for in stockholder’s equity. The Company believes it is more likely than not that the net deferred tax asset will not be realized and therefore recorded a valuation allowance. As a result of the Stone Combination, the Company acquired a current income tax receivable of $10.7 million primarily related to the carryback of specified liability losses. Tax Cuts and Jobs Act. On December 22, 2017, the President signed into law Public Law No. 115-97 (“Tax Act”), an Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018. The Tax Act made broad and complex changes to the U.S. tax code. The SEC issued SAB 118, which has since been codified into ASC 740, providing guidance on the accounting for the tax effects of the Tax Act. ASC 740 provides a measurement period that should not extend beyond one year from the Tax Act enactment date to complete the accounting under ASC 740. In accordance with this pronouncement, the Company completed its assessment on certain effects of the Tax Act in the financial statements for the period ending December 31, 2018. In assessing the need for a valuation allowance on its deferred tax assets, the Company considered whether it was more likely than not that some portion or all of them will not be realized. Due to a full valuation allowance against the Company’s deferred tax assets, the adjustments did not have any net impact on tax expense for 2018. The components of income tax expense (benefit) were as follows (in thousands): Year Ended December 31, 2018 2017 2016 Current income tax expense (benefit) United States $ — $ — $ — Mexico 1,345 — — Total current income tax expense (benefit) $ 1,345 $ — $ — Deferred income tax expense (benefit) United States $ 1,064 $ — $ — Mexico 513 — — Total deferred income tax expense (benefit) 1,577 — — Total income tax expense (benefit) $ 2,922 $ — $ — The reconciliation of income taxes computed at the U.S. federal statutory tax rate to the Company’s income tax expense is as follows (in thousands, except percentages): Year Ended December 31, 2018 2017 2016 Income tax (benefit) at the federal statutory tax rate $ 47,137 $ (22,004 ) $ (72,830 ) Earnings not subject to tax 9,980 22,004 72,830 State income taxes 11,738 — — Foreign income taxes 1,008 — — Foreign rate differential 432 — — Prior year taxes 417 — — Other adjustments 800 — — Change in tax status (35,925 ) — — Change in valuation allowance (32,665 ) Total income tax $ 2,922 $ — $ — Effective tax rate 1.30 % — % — % The Company’s effective tax rate for the year ending December 31, 2018, differed from the federal statutory rate of 21.0% primarily due to recording a valuation allowance for its deferred tax assets. The effective tax rate for years 2017 and 2016 differed from the federal statutory rate of 35.0% because the Company was not subject to U.S. federal or state taxation as a partnership and the Company’s Mexico operations did not incur a material income tax expense. Deferred Tax Assets and Liabilities Deferred taxes 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, 2018 2017 Deferred tax assets: Federal net operating loss $ 117,546 $ — Foreign tax loss carryforward 2,303 4,023 State net operating loss 23,542 — Asset retirement obligations 95,546 — Tax credits 12 — Interest 33,867 — Other 5,909 — Total deferred tax assets 278,725 4,023 Valuation allowance (94,085 ) (4,007 ) Total deferred tax assets, net $ 184,640 $ 16 Deferred tax liabilities Oil and gas properties 166,879 — Hedges 18,246 — Prepaid 3,371 — Deferred tax liabilities 188,496 — Net deferred tax asset (liability) $ (3,856 ) $ 16 Income Tax Receivables and Payables As of December 31, 2018, the Company recorded current income tax receivables of $10.7 million. As a result of the Stone Combination, the Company acquired the current income tax receivable primarily related to the carryback of specified liability losses. The Company has also recorded an income tax payable of $1.3 million primarily related to estimated taxes for the 2018 Mexico tax returns. Net Operating Loss The table below presents the details of the Company’s net operating loss and tax credit carryovers as of December 31, 2018 (in thousands): Amount Expiration Year Federal net operating losses $ 557,895 2034-2038 Foreign tax loss carryforward $ 8,970 2025-2028 State net operating losses $ 307,629 2019-2038 As of December, 31, 2018, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately Valuation Allowance During 2018, the Company recorded a valuation allowance of $94.1 million related to federal, state and foreign deferred tax assets. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on deferred tax assets, the Company considers whether it is more likely than not that some portion or all of them will not be realized. As of December 31, 2018, the Company had a valuation allowance related to federal, state and foreign deferred tax assets. The Company did not record a valuation allowance during 2017 for federal and state deferred tax assets as the Company was not subject to taxation as a partnership during this period. Uncertain Tax Positions The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. There are no unrecognized benefits that would impact the effective tax rate if recognized. While amounts could change in 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, 2018 2017 Total unrecognized tax benefits, beginning balance $ — $ — Increases (decreases) in unrecognized tax benefits as a result of: Tax positions taken during a prior period 360 — Tax positions taken during the current period — — Settlements with taxing authorities — — Lapse of applicable statute of limitations — — Total unrecognized tax benefits, ending balance $ 360 $ — The Company recognizes interest and penalties related to uncertain tax positions as interest expense and general and administrative expenses, respectively. Years open to examination The 2015 through 2017 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, 2014 are closed.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Earnings Per Share	Note 9 — Earnings Per Share Basic earnings per common share 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 earnings per common share includes the impact of RSUs, PSUs and outstanding warrants. As of December 31, 2018, the Company had approximately 3.5 million outstanding warrants. These warrants have an exercise price of $42.04 per share and a term of four years ending February 28, 2021. As of December 31, 2018, the Company had 138,704 and 231,542 outstanding RSUs and PSUs, respectively, which settle in shares of Common Stock. For the year ended December 31, 2018, dilutive weighted average shares for RSUs and PSUs totaled 2,819 shares resulting in an increase to the basic weighted average common shares of 46,058,216 to arrive at diluted weighted average common shares outstanding of 46,061,035. For the year ended December 31, 2018, 419,639 weighted average antidilutive RSUs and PSUs were excluded from the computation of diluted earnings per common share. Additionally, for the year ended December 31, 2018, all outstanding warrants were considered antidilutive due to the exercise price of the warrants exceeding the average market price of Common Stock. For the periods prior to May 10, 2018, the Company retrospectively adjusted the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. There is no impact in fiscal year 2017 and 2016 on diluted earnings per common share from the RSUs, PSUs and outstanding warrants as these instruments did not exist throughout such periods.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Note 10 — Related Party Transactions Whistler Acquisition . On August 31, 2018, the Company acquired Whistler from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds, for $52.6 million ($14.8 million, net of $37.8 million of cash acquired). Included in current assets acquired as of December 31, 2018 is $1.1 million in receivables from an affiliate of the Apollo Funds to reimburse the Company for certain payments made post closing. See additional details in Note 3 – Acquisitions. Equity Registration Rights Agreement . On the Closing Date, the Company entered into an Equity Registration Rights Agreement with each of the Apollo Funds, Riverstone Funds, Franklin and MacKay Shields relating to the registered resale of its Common Stock owned by such parties as of Closing. The Company will bear all of the expenses incurred in connection with the offer and sale, while the Apollo Funds, Riverstone Funds, Franklin and MacKay Shields are responsible for paying underwriting fees, discounts and commissions or similar charges. Fees incurred by the Company in conjunction with the Equity Registration Rights Agreement were $1.8 million for the year ended December 31, 2018. Legal Fees. The Company has engaged the law firm Vinson & Elkins L.L.P. to provide legal services. An immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel and one of its executive officers, is a partner at Vinson & Elkins L.L.P. For the year ended December 31, 2018, 2017 and 2016, the Company incurred fees of approximately $4.4 million, $ 4.0 million and $0.7 million, respectively, of which $1.1 million, $4.0 million and $0.1 million were payable at each respective balance sheet date for legal services performed by Vinson & Elkins L.L.P. Contributions and Distributions . During the years ended December 31, 2018 and 2017, the Company did not receive any cash contributions or make any distributions to Apollo Funds and Riverstone Funds. During the year ended December 31, 2016, the Company received a $93.8 million ($91.9 million net of $1.9 million of transaction fees) capital contribution from Apollo Funds and Riverstone Funds primarily to fund the Sojitz Acquisition. See Note 3 — Acquisitions for further details. Transaction Fee Agreement . As part of the agreements with Apollo Funds and Riverstone Funds, the Company paid a transaction fee equal to 2% of capital contributions made by Apollo Funds and Riverstone Funds. For the years ended December 31, 2018 and 2017, there were no capital contributions and thus the Company did not incur or pay transaction fees related to capital contributions. For the year ended December 31, 2016 the Company incurred fees totaling $1.9 million related to the capital contributions received from Apollo Funds and Riverstone Funds. In connection with the Stone Combination, the Transaction Fee Agreement was terminated on May 10, 2018. Service Fee Agreement. The Company entered into service fee agreements with Apollo Funds and Riverstone Funds for the provision of certain management consulting and advisory services. Under each agreement, the Company paid a fee equal to the higher of (i) a certain percentage of earnings before interest, income taxes, depletion, depreciation and amortization and (ii) a fixed fee payable quarterly, provided, however, such fees did not exceed in each case $0.5 million, in aggregate, for any calendar year. For the year ended December 31, 2018, 2017 and 2016, the Company incurred approximately $0.5 million, $0.5 million and $0.5 million, respectively, for these services. These fees are recognized in general and administrative expense on the consolidated statements of operations. In connection with the Stone Combination on May 10, 2018, the Service Fee Agreement was terminated. Debt Modification Work Fees. The Company paid $9.3 million in work fees to holders of the 11.00% Bridge Loans and 7.50% Stone Senior Notes to exchange into 11.00% Senior Secured Notes as a result of the Stone Combination. The Apollo Funds and Riverstone Funds received $4.1 million and the Franklin Noteholders and McKay Noteholders received $3.3 million as a result of the work fees paid

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 11 — Commitments and Contingencies Capital Lease On August 2, 2016, the Company executed a seven-year lease agreement (the “Agreement”), effective June 1, 2016, with Helix for use of the HP-I to process hydrocarbons produced from the Phoenix Field. Under the terms of the Agreement, the Company paid Helix a $49.0 annual fixed demand charge plus a potential $0.5 million quarterly incentive payment if certain uptime rates were achieved. Thereafter the Company will pay a $45.0 annual fixed demand charge plus a potential $0.8 million quarterly incentive payment if certain uptime rates are achieved. The Agreement with Helix is accounted for as a capital lease. The Company initially recorded both a capital lease asset and obligation of $124.3 million on its consolidated balance sheet. As of December 31, 2018, the balance of the capital lease obligation on the consolidated balance sheet is $93.6 million, of which $14.1 million is included in other current liabilities and $79.5 million is included in other long-term liabilities. As a result of the Agreement being accounted for as a capital lease, the lease payments are reflected as (i) a reduction of the capital lease obligation, (ii) interest expense and (iii) direct lease operating expense. As of December 31, 2018, minimum lease commitments for the capital lease in future years are as follows (in thousands): 2019 $ 45,000 2020 45,000 2021 45,000 2022 45,000 2023 18,750 Total minimum lease payments 198,750 Less amount represented lease operating expenses (51,864 ) Less amount represented interest (53,218 ) Present value of minimum lease payments 93,668 Less current maturities of capital lease obligations (14,127 ) Long-term capital lease obligations $ 79,541 Legal Proceedings and Other Contingencies On January 6, 2016, Energy Resource Technology GOM, LLC (“ERT”) plead guilty to two violations of the Clean Water for self-reported activities surrounding overboard discharge sampling and unpermitted discharges and two violations of Outer Continental Shelf Lands Act. On April 6, 2016, the United States District Court for the Eastern District of Louisiana accepted ERT’s plea and sentenced ERT, consistent with the plea agreement, to pay a penalty of $4.2 million which ERT has paid. The Court placed ERT on probation for three years. The conditions of probation include compliance with an agreed Safety and Environmental Compliance Program. As a result of ERT’s conviction for violations of the Clean Water Act, ERT was debarred and cannot enter into contracts with or receive benefits from the federal government, until the EPA reinstates ERT by certifying that ERT has corrected the conditions giving rise to the Clean Water convictions. EPA also imposed discretionary suspension and proposed debarment on Talos Production LLC, Talos Energy Offshore LLC and Talos Energy LLC as affiliates of ERT. On November 23, 2016, EPA terminated and administratively closed the suspension as to each of the three entities previously suspended. On August 29, 2017, EPA certified that the conditions giving rise to ERT’s conviction were corrected, and its debarment was lifted. The Company is named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. The Company does not expect that these matters, individually or in the aggregate, will have a material adverse effect on its financial condition. Performance Obligations Regulations with respect to offshore operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities and to guarantee the execution of the minimum work program under the Mexico production sharing contracts. As of December 31, 2018 and 2017, the Company had secured performance bonds totaling approximately $644.1 million and $287.8 million, respectively. As of December 31, 2018 and 2017, the Company had $14.7 million and $4.9 million, respectively, in letters of credit issued under its Bank Credit Facility. The table below summarizes the Company’s total minimum commitments associated with long-term, non-cancelable operating leases, vessel commitments, purchase obligations and the Mexico minimum work program as of December 31, 2018 (in thousands): 2019 2020 2021 2022 Thereafter Total Vessel Commitments (1) $ 35,206 $ — $ — $ — $ — $ 35,206 Committed purchase orders (2) 15,562 11,921 7,921 — — 35,404 Operating lease obligations (3) 3,622 4,315 4,016 4,298 27,225 43,476 Mexico minimum work program — 19,277 — — — 19,277 Total (4) $ 54,390 $ 35,513 $ 11,937 $ 4,298 $ 27,225 $ 133,363 (1) Includes vessel commitments the Company will utilize for certain deep water well intervention and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs. (2) Includes committed purchase orders to execute planned future drilling and completion activities as well as seismic use agreements the Company entered into in connection with the Stone Combination. (3) Amounts include long-term lease payments for office space. (4) Excludes the capital lease for the HP-I floating production facility in the Phoenix Field discussed above. The table above includes leases for buildings, facilities and related equipment with varying expiration dates through 2029. Total rent expense, for continuing operations, included in general and administrative expense for the years ended December 31, 2018, 2017 and 2016 was $2.9 million, $2.1 million and $2.0 million, respectively.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2018
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	Note 12 — Condensed Consolidating Financial Information Talos Energy Inc. owns no operating assets and has no operations independent of its subsidiaries. Talos Production LLC and Talos Production Finance Inc. issued 11.00% Second-Priority Senior Secured Notes on May 10, 2018, which are fully and unconditionally guaranteed, jointly and severally, by Talos Energy Inc. and certain 100% owned subsidiaries on a senior unsecured basis. The following condensed consolidating financial information presents the financial information of the Company on an unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the period indicated. Such financial information may not necessarily be indicative of the Company’s results of operations, cash flows, or financial position had these subsidiaries operated as independent entities. TALOS ENERGY INC. CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2018 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ 13,541 $ 100,801 $ 25,572 $ — $ 139,914 Restricted cash — — 1,248 — — 1,248 Accounts receivable Trade, net — — 103,025 — — 103,025 Joint interest, net — — 15,870 4,374 — 20,244 Other — 3,100 9,566 7,020 — 19,686 Assets from price risk management activities — 75,473 — — — 75,473 Prepaid assets — 1,225 37,639 47 — 38,911 Income tax receivable — — 10,701 — — 10,701 Other current assets — — 7,644 — — 7,644 Total current assets — 93,339 286,494 37,013 — 416,846 Property and equipment: Proved properties — — 3,629,430 — — 3,629,430 Unproved properties, not subject to amortization — — 63,104 45,105 — 108,209 Other property and equipment — 20,670 12,440 81 — 33,191 Total property and equipment — 20,670 3,704,974 45,186 — 3,770,830 Accumulated depreciation, depletion and amortization — (8,310 ) (1,711,288 ) (11 ) — (1,719,609 ) Total property and equipment, net — 12,360 1,993,686 45,175 — 2,051,221 Other long-term assets: Other well equipment inventory — — 9,224 — — 9,224 Investments in subsidiaries 1,011,359 1,560,922 — — (2,572,281 ) — Other assets — 364 2,258 73 — 2,695 1,011,359 1,666,985 2,291,662 82,261 (2,572,281 ) 2,479,986 LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable 144 1,242 42,736 6,897 — 51,019 Accrued liabilities — 4,995 159,491 24,164 — 188,650 Accrued royalties — — 38,520 — — 38,520 Current portion of long-term debt — — 443 — — 443 Current portion of asset retirement obligations — — 68,965 — — 68,965 Liabilities from price risk management activities 550 — — — 550 Accrued interest payable — 10,162 38 — — 10,200 Other current liabilities — — 22,071 — — 22,071 Total current liabilities 144 16,949 332,264 31,061 — 380,418 Long-term debt, net of discount and deferred financing costs — 638,677 16,184 — — 654,861 Asset retirement obligations — — 313,852 — — 313,852 Other long-term liabilities 3,719 — 119,432 208 — 123,359 Total liabilities 3,863 655,626 781,732 31,269 — 1,472,490 Commitments and Contingencies (Note 11) Stockholders' equity (deficit) 1,007,496 1,011,359 1,509,930 50,992 (2,572,281 ) 1,007,496 $ 1,011,359 $ 1,666,985 $ 2,291,662 $ 82,261 $ (2,572,281 ) $ 2,479,986 TALOS ENERGY INC. CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2017 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ 22,315 $ 7,806 $ 2,070 $ — $ 32,191 Restricted cash — — 1,242 — — 1,242 Accounts receivable, net Trade, net — — 62,871 — — 62,871 Joint interest, net — — 11,659 1,954 — 13,613 Other — 938 5,863 5,685 — 12,486 Assets from price risk management activities — 1,406 157 — — 1,563 Prepaid assets — — 17,919 12 — 17,931 Inventory — — 840 — — 840 Other current assets — — 2,148 — — 2,148 Total current assets — 24,659 110,505 9,721 — 144,885 Property and equipment: Proved properties — — 2,440,811 — — 2,440,811 Unproved properties, not subject to amortization — — 41,259 30,743 — 72,002 Other property and equipment — 7,266 1,580 11 — 8,857 Total property and equipment — 7,266 2,483,650 30,754 — 2,521,670 Accumulated depreciation, depletion and amortization — (6,355 ) (1,424,527 ) (8 ) — (1,430,890 ) Total property and equipment, net — 911 1,059,123 30,746 — 1,090,780 Other long-term assets: Assets from price risk management activities — 345 — — — 345 Other well equipment inventory — — 2,577 — — 2,577 Investments in subsidiaries (54,087 ) 697,663 — — (643,576 ) — Other assets — 364 326 16 — 706 Total assets $ (54,087 ) $ 723,942 $ 1,172,531 $ 40,483 $ (643,576 ) $ 1,239,293 LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable $ — $ 1,124 $ 70,458 $ 1,099 $ — $ 72,681 Accrued liabilities — 6,516 80,464 993 — 87,973 Accrued royalties — — 24,208 — — 24,208 Current portion of long-term debt — 24,977 — — — 24,977 Current portion of asset retirement obligations — — 39,741 — — 39,741 Liabilities from price risk management activities — 46,580 3,377 — — 49,957 Accrued interest payable — 8,742 — — — 8,742 Other current liabilities — — 15,188 — — 15,188 Total current liabilities — 87,939 233,436 2,092 — 323,467 Long-term debt, net of discount and deferred financing costs — 672,581 — — — 672,581 Asset retirement obligations — — 174,992 — — 174,992 Liabilities from price risk management activities — 17,509 1,272 — — 18,781 Other long-term liabilities — — 103,559 — — 103,559 Total liabilities — 778,029 513,259 2,092 — 1,293,380 Commitments and Contingencies (Note 11) Stockholders' equity (deficit) (54,087 ) (54,087 ) 659,272 38,391 (643,576 ) (54,087 ) $ (54,087 ) $ 723,942 $ 1,172,531 $ 40,483 $ (643,576 ) $ 1,239,293 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2018 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 781,815 $ — $ — $ 781,815 Natural gas revenue — — 73,610 — — 73,610 NGL revenue — — 35,863 — — 35,863 Total revenue — — 891,288 — — 891,288 Operating expenses: Direct lease operating expense — — 145,988 — — 145,988 Insurance — — 15,342 — — 15,342 Production taxes — — 1,989 — — 1,989 Total lease operating expense — — 163,319 — — 163,319 Workover and maintenance expense — — 64,961 — — 64,961 Depreciation, depletion and amortization — 1,955 286,760 4 — 288,719 Accretion expense — — 35,344 — — 35,344 General and administrative expense 142 43,841 40,035 1,798 — 85,816 Total operating expenses 142 45,796 590,419 1,802 — 638,159 Operating income (loss) (142 ) (45,796 ) 300,869 (1,802 ) — 253,129 Interest expense — (58,172 ) (30,255 ) (1,687 ) — (90,114 ) Price risk management activities income — 50,025 10,410 — — 60,435 Other income (loss) — (1,563 ) 874 1,701 — 1,012 Income tax expense (1,065 ) — (360 ) (1,497 ) — (2,922 ) Equity earnings (losses) from subsidiaries 222,747 278,253 — — (501,000 ) — Net income (loss) $ 221,540 $ 222,747 $ 281,538 $ (3,285 ) $ (501,000 ) $ 221,540 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2017 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 344,781 $ — $ — $ 344,781 Natural gas revenue — — 48,886 — — 48,886 NGL revenue — — 16,658 — — 16,658 Other — — 2,503 — — 2,503 Total revenue — — 412,828 — — 412,828 Operating expenses: Direct lease operating expense — — 109,180 — — 109,180 Insurance — — 10,743 — — 10,743 Production taxes — — 1,460 — — 1,460 Total lease operating expense — — 121,383 — — 121,383 Workover and maintenance expense — — 32,825 — — 32,825 Depreciation, depletion and amortization — 1,401 155,947 4 — 157,352 Accretion expense — — 19,295 — — 19,295 General and administrative expense — 21,882 14,172 619 — 36,673 Total operating expenses — 23,283 343,622 623 — 367,528 Operating income (loss) — (23,283 ) 69,206 (623 ) — 45,300 Interest expense — (48,236 ) (30,252 ) (2,446 ) — (80,934 ) Price risk management activities expense — (22,998 ) (4,565 ) — — (27,563 ) Other income (expense) — 600 (333 ) 62 — 329 Equity earnings from subsidiaries (62,868 ) 31,049 — — 31,819 — Net income (loss) $ (62,868 ) $ (62,868 ) $ 34,056 $ (3,007 ) $ 31,819 $ (62,868 ) TALOS ENERGY INC. CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2016 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 197,583 $ — — $ 197,583 Natural gas revenue — — 42,705 — — 42,705 NGL revenue — — 9,532 — — 9,532 Other — — 8,934 — — 8,934 Total revenue — — 258,754 — — 258,754 Operating expenses: Direct lease operating expense — — 124,360 — — 124,360 Insurance — — 13,101 — — 13,101 Production taxes — — 1,958 — — 1,958 Total lease operating expense — — 139,419 — — 139,419 Workover and maintenance expense — — 24,810 — — 24,810 Depreciation, depletion and amortization — 1,553 123,132 4 — 124,689 Accretion expense — — 21,829 — — 21,829 General and administrative expense — 13,204 15,044 438 — 28,686 Total operating expenses — 14,757 324,234 442 — 339,433 Operating loss — (14,757 ) (65,480 ) (442 ) — (80,679 ) Interest expense — (47,291 ) (19,680 ) (3,444 ) — (70,415 ) Price risk management activities expense — (57,398 ) — — — (57,398 ) Other income (expense) — — 430 (25 ) — 405 Equity earnings from subsidiaries (208,087 ) (88,641 ) — — 296,728 — Net income (loss) $ (208,087 ) $ (208,087 ) $ (84,730 ) $ (3,911 ) $ 296,728 $ (208,087 ) TALOS ENERGY INC. CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2018 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ (193,088 ) $ 442,890 $ 13,643 $ — $ 263,445 Cash flows from investing activities: Exploration, development, and other capital expenditures — (13,404 ) (227,228 ) (282 ) — (240,914 ) Cash paid for acquisitions, net of cash acquired — — 278,409 — — 278,409 Investments in subsidiaries — (1,316,588 ) — — 1,316,588 — Distributions from subsidiaries — 1,694,460 9 — (1,694,469 ) — Net cash provided by (used in) investing activities — 364,468 51,190 (282 ) (377,881 ) 37,495 Cash flows from financing activities: Redemption of Senior Notes and other long-term debt — (25,152 ) (105 ) — — (25,257 ) Proceeds from Bank Credit Facility — 319,000 — — — 319,000 Repayment of Bank Credit Facility — (54,000 ) — — — (54,000 ) Repayment of LLC Bank Credit Facility — (403,000 ) — — — (403,000 ) Deferred financing costs — (17,002 ) — — — (17,002 ) Payment of capital lease — — (12,952 ) — — (12,952 ) Capital contributions — — 1,301,876 14,712 (1,316,588 ) — Distributions to Subsidiary Issuer — — (1,689,898 ) (4,571 ) 1,694,469 — Net cash provided by (used in) financing activities — (180,154 ) (401,079 ) 10,141 377,881 (193,211 ) Net increase (decrease) in cash, cash equivalents and restricted cash — (8,774 ) 93,001 23,502 — 107,729 Cash, cash equivalents and restricted cash Balance, beginning of period — 22,315 9,048 2,070 — 33,433 Balance, end of period $ — $ 13,541 $ 102,049 $ 25,572 $ — $ 141,162 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2017 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ (30,245 ) $ 204,419 $ 1,879 $ — $ 176,053 Cash flows from investing activities: Exploration, development, and other capital expenditures — (260 ) (132,317 ) (22,600 ) — (155,177 ) Cash paid for acquisitions, net of cash acquired — — (2,464 ) — — (2,464 ) Investments in subsidiaries — (577,055 ) — — 577,055 — Distributions from subsidiaries — 611,526 6,041 — (617,567 ) — Net cash provided by (used in) investing activities — 34,211 (128,740 ) (22,600 ) (40,512 ) (157,641 ) Cash flows from financing activities: Redemption of 2018 Senior Notes — (1,000 ) — — — (1,000 ) Proceeds from Bank Credit Facility — 10,000 — — — 10,000 Repayment of Bank Credit Facility — (15,000 ) — — — (15,000 ) Payments of capital lease — — (12,412 ) — — (12,412 ) Capital contributions — — 550,555 26,500 (577,055 ) — Distributions to subsidiaries — — (611,526 ) (6,041 ) 617,567 — Net cash provided by (used in) financing activities — (6,000 ) (73,383 ) 20,459 40,512 (18,412 ) Net increase (decrease) in cash, cash equivalents and restricted cash — (2,034 ) 2,296 (262 ) — — Cash, cash equivalents and restricted cash: Balance, beginning of period — 24,349 6,752 2,332 — 33,433 Balance, end of period $ — $ 22,315 $ 9,048 $ 2,070 $ — $ 33,433 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2016 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ 124,698 $ (2,806 ) $ (5,769 ) — $ 116,123 Cash flows from investing activities: Exploration, development, and other capital expenditures — (301 ) (106,647 ) (6,084 ) — (113,032 ) Cash paid for acquisitions, net of cash acquired — — (85,886 ) — — (85,886 ) Investments in subsidiaries (91,891 ) (524,192 ) — — 616,083 — Distributions from subsidiaries — 411,074 — — (411,074 ) — Net cash provided by (used in) investing activities (91,891 ) (113,419 ) (192,533 ) (6,084 ) 205,009 (198,918 ) Cash flows from financing activities: Proceeds from Bank Credit Facility — 15,000 — — — 15,000 Repayment of Bank Credit Facility — (10,000 ) — — — (10,000 ) Payments of capital lease — — (5,267 ) — — (5,267 ) Capital contributions — — 599,630 16,453 (616,083 ) — Distributions to subsidiaries — — (408,050 ) (3,024 ) 411,074 — Contributions from Sponsors 93,750 — — — — 93,750 Distributions to Sponsors (1,859 ) — — — — (1,859 ) Net cash provided by (used in) financing activities 91,891 5,000 186,313 13,429 (205,009 ) 91,624 Net increase (decrease) in cash, cash equivalents and restricted cash — 16,279 (9,026 ) 1,576 — 8,829 Cash, cash equivalents and restricted cash: Balance, beginning of period — 8,070 15,778 756 — 24,604 Balance, end of period $ — $ 24,349 $ 6,752 $ 2,332 $ — $ 33,433

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data (Unaudited)	Note 13 —Selected Quarterly Financial Data (Unaudited) Unaudited quarterly financial data are as follows (in thousands): March 31 June 30 September 30 December 31 Quarter Ended 2018 Revenues $ 145,850 $ 203,906 $ 282,868 $ 258,664 Operating income 48,584 39,211 91,361 73,973 Price risk management activities income (expense) (51,976 ) (91,176 ) (53,330 ) 256,917 Net income (loss) $ (22,943 ) $ (74,912 ) $ 13,109 $ 306,286 Net income (loss) per common share: Basic $ (0.73 ) $ (1.69 ) $ 0.24 $ 5.66 Diluted $ (0.73 ) $ (1.69 ) $ 0.24 $ 5.66 Weighted average common shares outstanding: Basic 31,244 44,336 54,156 54,156 Diluted 31,244 44,336 54,164 54,159 Quarter Ended 2017 Revenues $ 101,824 $ 95,426 $ 99,962 $ 115,616 Operating income 7,287 6,314 13,329 18,370 Price risk management activities income (expense) 45,893 38,995 (28,086 ) (84,365 ) Net income (loss) $ 34,462 $ 24,607 $ (36,177 ) $ (85,760 ) Net income (loss) per common share: Basic $ 1.10 $ 0.79 $ (1.16 ) $ (2.74 ) Diluted $ 1.10 $ 0.79 $ (1.16 ) $ (2.74 ) Weighted average common shares outstanding: Basic 31,244 31,244 31,244 31,244 Diluted 31,244 31,244 31,244 31,244

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures (Unaudited)	12 Months Ended
	Dec. 31, 2018
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures (Unaudited)	Note 14 —Supplemental Oil and Gas Disclosures (Unaudited) Capitalized Costs Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands): December 31, 2018 2017 Proved properties $ 3,629,430 $ 2,440,811 Unproved oil and gas properties, not subject to amortization 108,209 72,002 Total oil and gas properties 3,737,639 2,512,813 Less: Accumulated depletion and amortization (1,709,614 ) (1,423,829 ) Net capitalized costs $ 2,028,025 $ 1,088,984 Depletion and amortization rate per Boe $ 17.07 $ 14.85 Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s proportionate share of asset retirement costs relating to these properties which are also reflected as asset retirement obligations in the accompanying consolidated balance sheets. At December 31, 2018 and 2017 the Company’s liability for oil and gas asset retirement obligations totaled $382.8 million and $214.7 million, respectively. Costs Incurred for Property Acquisition, Exploration and Development Activities The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Year Ended December 31, 2018 2017 2016 Property acquisition costs: Proved properties $ 850,515 $ 1,108 $ 77,906 Unproved properties, not subject to amortization 65,063 5,778 15,919 Total property acquisition costs 915,578 6,886 93,825 Exploration costs 93,780 82,887 27,807 Development costs 215,467 114,846 195,869 Total costs incurred $ 1,224,825 $ 204,619 $ 317,501 Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves The Company employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. The Company’s Director of Reserves, At December 31, 2018, 2017 and 2016, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and complied for reporting purposes by the Company’s reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists. The following table presents the Company’s estimated proved reserves at its net ownership interest: Oil (MBbls) Gas (MMcf) NGL (MBbls) Oil Equivalent (MBoe) Total proved reserves at December 31, 2015 46,354 129,224 4,581 72,473 Revision of previous estimates (1,712 ) 10,024 (352 ) (394 ) Production (5,126 ) (19,001 ) (603 ) (8,896 ) Purchases of reserves 11,128 11,208 950 13,946 Extensions and discoveries 21,722 19,149 1,660 26,573 Total proved reserves at December 31, 2016 72,366 150,604 6,236 103,702 Revision of previous estimates (2,673 ) (15,860 ) 250 (5,067 ) Production (7,048 ) (16,308 ) (706 ) (10,472 ) Extensions and discoveries 10,159 9,220 767 12,462 Total proved reserves at December 31, 2017 72,804 127,656 6,547 100,625 Revision of previous estimates 2,595 (37,933 ) 3,187 (539 ) Production (11,771 ) (22,771 ) (1,176 ) (16,742 ) Purchases of reserves 44,788 95,661 2,074 62,806 Extensions and discoveries 4,123 8,411 64 5,589 Total proved reserves at December 31, 2018 112,539 171,024 10,696 151,739 Total proved developed reserves as of: December 31, 2016 45,753 96,122 4,032 65,805 December 31, 2017 37,460 77,577 3,315 53,704 December 31, 2018 85,530 131,364 8,104 115,528 Total proved undeveloped reserves as of: December 31, 2016 26,613 54,482 2,204 37,897 December 31, 2017 35,344 50,079 3,232 46,921 December 31, 2018 27,009 39,660 2,592 36,211 During 2018, the Company added 51.1 MMBoe of estimated proved reserves, which included 62.8 MMBoe added through purchases of 59.3 MMBoe from the Stone Combination and 3.5 MMBoe from the Whistler Acquisition. The Company also added 5.6 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Green Canyon Block 18. The increase was partially offset by a decrease of 16.7 MMBoe of production. During 2017, the Company added 12.5 MMBoe of estimated proved reserves from extensions and discoveries primarily from drilling the Tornado II exploration prospect in the Phoenix Field. The increase was offset by a decrease of 10.5 MMBoe of production and 5.1 MMBoe of negative performance revisions. During 2016, the Company added 13.9 MMBoe of estimated proved reserves through the purchase of reserves from the Sojitz Acquisition. The Company also added 26.6 MMBoe of estimated proved reserves from extensions and discoveries from successful drilling of the Tornado exploration well in the Phoenix Field. 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): December 31, 2018 2017 2016 Future cash inflows $ 8,654,631 $ 4,308,863 $ 3,390,612 Future costs: Production (1,740,850 ) (815,509 ) (775,354 ) Development and abandonment (1,349,005 ) (823,164 ) (664,254 ) Future net cash flows before income taxes 5,564,776 2,670,190 1,951,004 Future income tax expense (1) (862,473 ) — — Future net cash flows after income taxes 4,702,303 2,670,190 1,951,004 Discount at 10% annual rate (1,362,057 ) (862,521 ) (614,969 ) Standardized measure of discounted future net cash flows $ 3,340,246 $ 1,807,669 $ 1,336,035 (1) For December 31, 2017 and 2016, the standardized measure of discounted future net cash flows did not include the impact of future federal income taxes because Talos Energy LLC was not subject to federal income taxes prior to the Stone Combination. Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for base prices used in determining the standardized measure: Year Ended December 31, 2018 2017 2016 Oil price per Bbl $ 69.42 $ 51.36 $ 40.02 Natural gas prices per Mcf $ 3.08 $ 3.20 $ 2.66 NGL price per Bbl $ 29.50 $ 24.64 $ 14.96 Future net cash flows are discounted at the prescribed rate of 10%. Actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves. Changes in Standardized Measure of Discounted Future Net Cash Flows Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands): Year Ended December 31, 2018 2017 2016 Standardized measure, beginning of year $ 1,807,669 $ 1,336,035 $ 602,981 Changes during the year: Sales and transfers of oil, net gas and NGLs produced during the period (727,969 ) (288,942 ) (114,625 ) Net change in prices and production costs 1,578,330 555,100 80,174 Changes in estimated future development costs 32,328 (156,282 ) 2,292 Previously estimated development costs incurred 45,937 146,687 108,484 Accretion of discount 180,767 133,603 60,298 Net change in income taxes (1) (585,017 ) — — Purchases of reserves 943,519 — 222,581 Extensions and discoveries 148,068 328,565 479,833 Net change due to revision in quantity estimates 190,853 (113,629 ) (5,685 ) Changes in production rates (timing) and other (274,239 ) (133,468 ) (100,298 ) Total 1,532,577 471,634 733,054 Standardized measure, end of year $ 3,340,246 $ 1,807,669 $ 1,336,035 (1) For December 31, 2017 and 2016, the standardized measure of discounted future net cash flows did not include the impact of future federal income taxes because Talos Energy LLC was not subject to federal income taxes prior to the Stone Combination.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	Note 15 —Subsequent Events Gunflint Acquisition On January 11, 2019, the Company entered into a Purchase Sale Agreement with Samson Offshore Mapleleaf, LLC to acquire an approximate 9.6% non-operated working interest in the Gunflint Field located in the Mississippi Canyon area for $29.6 million. Derivative Contracts For additional information, see Note 5 — Financial Instruments. Debt For additional information, see Note 6 — Debt

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Formation and Nature of Business	Formation and Nature of Business Talos Energy Inc. (“Talos” or the “Company”) is a technically driven independent exploration and production company with operations in the United States (“U.S.”) Gulf of Mexico and offshore Mexico. The Company’s focus in the U.S. Gulf of Mexico is the acquisition of deep water assets with existing infrastructure and the exploration, exploitation and development of such assets in key geological trends. Offshore Mexico provides high impact exploration opportunities in an oil rich emerging basin. The Company uses access to an extensive seismic database and its deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. Talos Energy Inc. was formed in connection with the previously disclosed business combination between Talos Energy LLC and Stone Energy Corporation (“Stone”) that occurred on May 10, 2018, pursuant to which Talos Energy LLC and Stone became indirect wholly owned subsidiaries of Talos Energy Inc.
Talos Energy LLC	Talos Energy LLC Talos Energy LLC was formed in 2011 and commenced commercial operations on February 6, 2013. Prior to February 6, 2013, Talos Energy LLC had incurred certain general and administrative expenses associated with the start-up of its operations. On February 3, 2012, Talos Energy LLC completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”, and together with the Apollo Funds, the “Sponsors”) and members of management pursuant to which the Company received a private equity capital commitment.
Stone Combination	Stone Combination On May 10, 2018 (the “Closing Date”), the Company (f/k/a Sailfish Energy Holdings Corporation) consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), by and among Stone, the Company, Sailfish Merger Sub Corporation (“Merger Sub”), Talos Energy LLC and Talos Production LLC, pursuant to which, among other items, each of Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of the Company (the “Stone Combination”). Prior to the Closing Date, the Company did not conduct any material activities other than those incident to its formation and the matters contemplated by the Transaction Agreement. On Closing Date, the following transactions, among others, occurred: (i) Stone underwent a reorganization pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and a direct wholly-owned subsidiary of the Company (the “Merger”) and each share of Stone’s common stock outstanding immediately prior to the Merger (other than treasury shares held by Stone, which were cancelled for no consideration) was converted into the right to receive one share of the Company’s common stock, par value $0.01 (the “Common Stock”) and (ii) the Sponsors contributed all of the equity interests in Talos Production LLC (which at that time owned 100% of the equity interests in Talos Energy LLC) to the Company in exchange for an aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”). Concurrently with the consummation of the Transaction Agreement, the Company consummated the transactions contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among the Company, Stone, the Talos Issuers (defined below), the various lenders and noteholders of the Talos Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% Senior Notes due 2022 (“9.75% Senior Notes”) issued by Talos Production LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to the Company in exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Debt Exchange”); (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (“11.00% Senior Secured Notes”) and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Secured Notes due 2022 issued by Stone (“7.50% Stone Senior Notes”) for $137.4 million aggregate principal amount of 11.00% Senior Secured Notes. Substantially concurrent therewith, the Company consummated an exchange offer and consent solicitation, pursuant to which the holders of the 7.50% Stone Senior Notes, excluding the 7.50% Stone Senior Notes held by the Franklin Noteholders and the MacKay Noteholders, exchanged their 7.50% Stone Senior Notes for 11.00% Senior Secured Notes and a cash payment, and a solicitation of consents to proposed amendments to the 7.50% Stone Senior Notes. Approximately $81.5 million in aggregate principal amount of the 7.50% Stone Senior Notes were validly tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Stone Senior Notes remained outstanding as of the Closing Date. As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange Agreement (the “Transactions”) the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the Closing Date.
Basis of Presentation and Consolidation	Basis of Presentation and Consolidation The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include each subsidiary from the date of inception. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods are reflected herein. The Company has evaluated subsequent events through the date the consolidated financial statements were issued. Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, the historical financial and operating data of Talos Energy Inc., which covers periods prior to the Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC and does not reflect the assets, liabilities and results of operations of Stone. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Stockholders’ Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos Energy Inc. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. The Company has one reportable segment, which is the exploration and production of oil and natural gas. Substantially all the Company’s long-lived assets, proved reserves and production sales are related to the Company’s operations in the United States.
Recently Adopted Or Issued Accounting Standards	Recently Adopted Accounting Standards Revenue Recognition On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers Revenue Recognition Extractive Activities – Oil and Gas – Revenue Recognition. 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 applied the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. 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. Under previous accounting guidance, the Company used the entitlement method to account for sales and production. Under the entitlement method, revenue was recorded based on the Company’s entitled share of production with any difference recorded as an imbalance on the consolidated balance sheet. Upon the adoption of ASC 606, 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. The change in accounting method from the entitlements method to the sales method resulted in an immaterial cumulative-effect adjustment to stockholders’ deficit on the date of adoption. Production Handling Fees. Under previous accounting guidance, the Company presented certain reimbursements for costs from certain third parties as other revenue on the consolidated statement of operations. Upon the adoption of ASC 606, the reimbursements are presented as a reduction of direct lease operating expense on the consolidated statement of operations. The impact of the reclassification for the year ended December 31, 2018 was immaterial . Recently Issued Accounting Standards Leases. In February 2016, the FASB issued ASU 2016-02, This ASU supersedes the lease requirements in Topic 840, , and requires that a lessee recognize a right-of-use asset and lease liability for leases that do not meet the definition of a short-term lease. The right-of-use asset and lease liability are to be measured on the balance sheet at the present value of the lease payments. For income statement purposes, ASU 2016-02 retains a dual model requiring leases to be classified as either operating or finance within the Company’s consolidated statements of operations. Lease costs for operating leases are recognized as a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. For finance leases, interest expense is recognized on the lease liability separately from amortization of the right-to-use asset. ASU 2016-02 does not apply to leases for oil and natural gas properties, but does apply to equipment used to explore and develop oil and natural gas reserves. This ASU is effective for fiscal years beginning after December 15, 2018, including the first quarter of 2019. The Company will adopt this standard using the modified retrospective method applied to all leases that exist on January 1, 2019. Talos made certain elections allowing the Company not to reassess contracts that commenced prior to adoption and to not recognize right-of-use assets or lease liabilities for short-term leases. Upon adoption, the Company expects the right-to-use asset and lease liability reported on the consolidated balance sheet to be material. The Company is finalizing the implementation of the changes to business processes, systems and controls to support accounting and disclosure requirements of this ASU.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company presents cash as cash and cash equivalents on the Company’s consolidated balance sheets. The Company considers all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost, which approximates fair value.
Accounts Receivable and Allowance for Uncollectible Accounts	Accounts Receivable and Allowance for Uncollectible Accounts Accounts receivable are stated at the historical carrying amount net of an allowance for uncollectible accounts of $8.7 million at December 31, 2018 and $5.9 million at December 31, 2017. The Company establishes provisions for losses on accounts receivable with other parties if it believes that it will not collect all or part of the outstanding balance. On a quarterly basis, the Company reviews collectability and establishes or adjusts the Company’s allowance as necessary using the specific identification method.
Prepaid Assets	Prepaid Assets Prepaid assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”). The deposits are the Company’s estimated ONRR royalties payable within thirty days of the production rate. On a monthly basis the Company adjusts the deposit based on actual royalty payments remitted to the ONRR.
Revenue Recognition	Revenue Recognition Upon the adoption of ASC 606, revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. See Note 1 Formation and Basis of Presentation for additional information.
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. In August 2016, the Company entered into a capital lease for the use of the Helix Producer I (“HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy, and recorded a $124.3 million capital lease asset. Since the HP-I is utilized in the Company’s oil and natural gas development activities, the asset is included within proved property and subject to the ceiling test calculation described below. Due to the inclusion within proved properties, the HP-I is depleted as part of the full cost pool. See Note 11 — Commitments and Contingencies Capitalized costs associated with proved reserves are amortized on a country by country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least quarterly. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash impairment expense on the consolidated statement 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 utilize 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. The ceiling test computation did not result in a write-down of the Company’s oil and natural gas properties during the years ended December 31, 2018, 2017 and 2016. 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. The Company recognizes transportation costs as a component of direct lease operating expense when it is the shipper of the product. Such costs were $12.5 million, $10.3 million and $9.1 million in the years ended December 31, 2018, 2017 and 2016, respectively.
Other Property and Equipment	Other Property and Equipment Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures, computer hardware and software. Acquisitions, renewals and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years.
Other Well Equipment Inventory	Other Well Equipment Inventory Other well equipment inventory primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When this inventory is supplied to wells, the cost of this inventory is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants. The Company’s inventory is stated at the lower of cost or net realizable value. The Company recorded $0.2 million, $0.3 million, $0.2 million of impairment to adjust inventory to net realizable value, which was expensed and reflected in workover/maintenance expense, during the years ended December 31, 2018, 2017 and 2016, respectively.
Fair Value Measure of Financial Instruments	Fair Value Measure of Financial Instruments Financial instruments generally consist of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments. Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows: Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement. Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions, and are significant to the fair value measurement. Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows: Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost). Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models). Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
Asset Retirement Obligations	Asset Retirement Obligations The Company is required to record its asset retirement obligations at fair value in the period such obligations are incurred with the associated asset retirement costs being capitalized as part of the carrying cost of the asset. The Company’s asset retirement obligations consist of estimated costs for dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and natural gas properties. The estimate of the asset retirement cost is determined, inflated to an estimated future value using a ten year average of the Consumer Price Index and discounted to present value using the Company’s credit-adjusted risk-free rate. Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values.
Price Risk Management Activities	Price Risk Management Activities The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. Commodity derivatives are recorded on the consolidated balance sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in price risk management activities income (expense) in the consolidated statements of operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes. The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company then utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable.
Income Taxes	Income Taxes Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. In connection with the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to U.S. federal and state income taxes. The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the consolidated balance sheets. The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations. The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expense, respectively.
Earnings Per Share	Earnings Per Share Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of restricted stock units (“RSUs”), performance share units (“PSUs”) and outstanding warrants. See Note 9 — Earnings Per Share
Share-Based Compensation	Share-Based Compensation Certain of the Company’s employees participate in its equity based compensation. The Company measures all employee equity based compensation awards at fair value as calculated using an option pricing method for valuing such securities on the date awards are granted to its employees and recognize compensation cost on a straight-line basis in the Company’s financial statements over the vesting period of each grant according to ASC 718, Compensation—Stock Compensation. During 2018, the Company issued RSUs and PSUs to certain employees and non-employee directors. The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity, but is remeasured at each reporting period for awards classified as a liability. The Company records share-based compensation, net of actual forfeitures, for the RSUs and PSUs in general and administrative expense on the consolidated statement of operations, net of amounts capitalized to oil and gas properties. See Note 7 — Employee Benefits Plans and Share-Based Compensation RSUs. Share-based compensation is based on the market price of the Company’s Common Stock on the grant date and recognized over the vesting period using the straight-line method as the requisite service period is fulfilled. PSUs. Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over the vesting period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of Common Stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the Company’s total shareholder return (“TSR”) relative to the TSR achieved by a specified industry peer group. Share-based compensation related to PSUs is recognized as the requisite service period is fulfilled, even if the market condition is not achieved
Concentration of Credit Risk	Concentration of Credit Risk Consisting principally of cash and cash equivalents, restricted cash, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk. Cash and cash equivalents and restricted cash 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, the majority 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 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, 2018 2017 2016 Shell Trading (US) Company 65 % 80 % 68 % Phillips 66 18 % ** ** Chevron U.S.A Inc. ** ** 14 % ** 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, 2018
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, 2018 2017 2016 Shell Trading (US) Company 65 % 80 % 68 % Phillips 66 18 % ** ** Chevron U.S.A Inc. ** ** 14 % ** less than 10%

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2018
Stone Energy Corporation
Business Acquisition [Line Items]
Summary of Purchase Price	The following table summarizes the purchase price (in thousands, except per share data): Stone Energy common stock - issued and outstanding as of May 9, 2018 20,038 Stone Energy common stock price $ 35.49 Common stock value $ 711,149 Stone Energy common stock warrants - issued and outstanding as of May 9, 2018 3,528 Stone Energy common stock warrants price $ 5.90 Common stock warrants value $ 20,815 Total purchase price $ 731,964
Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed	The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on May 10, 2018 (in thousands): Current assets (1) $ 372,760 Property and equipment 883,490 Other long-term assets 18,928 Current liabilities (130,062 ) Long-term debt (235,416 ) Other long-term liabilities (177,736 ) Allocated purchase price $ 731,964 (1) Includes $293.0 million of cash acquired. The fair values of current assets acquired includes trade receivables and joint interest receivables of $43.3 million and $3.5 million, respectively, which the Company expects all to be realizable.
Supplemental Proforma Information	The following supplemental pro forma information (in thousands, except per common share amounts), presents the consolidated results of operations for the years ended December 31, 2018 and 2017 as if the Stone Combination had occurred on January 1, 2017. The unaudited pro forma information was derived from historical statements of operations of the Company and Stone and adjusted to include (i) depletion and accretion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect the debt transactions contemplated by the Exchange Agreement and (iii) general and administrative expense adjusted for transaction related costs incurred. This information does not purport to be indicative of results of operations that would have occurred had the Stone Combination occurred on January 1, 2017, nor is such information indicative of any expected future results of operations. Year Ended December 31, 2018 2017 Revenue $ 1,013,184 712,648 Net income (loss) $ 274,577 (100,980 ) Basic and diluted net income (loss) per common share $ 5.07 $ (1.86 )
Whistler Energy II, LLC
Business Acquisition [Line Items]
Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed	The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on August 31, 2018 (in thousands): Current assets (1) $ 45,337 Property and equipment 35,344 Other long-term assets 66 Current liabilities (4,261 ) Asset retirement obligations (23,862 ) Allocated purchase price $ 52,624
Sojitz Energy Venture Inc
Business Acquisition [Line Items]
Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed	Proved properties $ 77,967 Unproved properties, not subject to amortization 11,133 Other short and long-term assets 2,380 Asset retirement obligations (3,242 ) Allocated purchase price $ 88,238

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2018 2017 2016 2015 and Prior Acquisition United States $ 49,777 $ 40,657 $ — $ 2,244 $ 6,876 Exploration United States 13,327 8,391 3,188 92 1,656 Total United States unproved properties, not subject to amortization $ 63,104 $ 49,048 $ 3,188 $ 2,336 $ 8,532 Exploration Mexico 45,105 14,362 23,332 6,110 1,301 Total Mexico unproved properties, not subject to amortization $ 45,105 $ 14,362 $ 23,332 $ 6,110 $ 1,301 Total unproved properties, not subject to amortization $ 108,209 $ 63,410 $ 26,520 $ 8,446 $ 9,833
Schedule of Asset Retirement Obligations	The discounted asset retirement obligations included in the consolidated balance sheets in current and non-current liabilities, and the changes in that liability during each of the years ended December 31, 2018 and 2017 were as follows (in thousands): Year Ended December 31, 2018 2017 Asset retirement obligations at January 1 $ 214,733 $ 220,049 Fair value of asset retirement obligations acquired (1) 244,766 699 Obligations settled (112,946 ) (32,573 ) Accretion expense 35,344 19,295 Obligations incurred 358 4,213 Changes in estimate 562 3,050 Asset retirement obligations at December 31 $ 382,817 $ 214,733 Less: Current portion (68,965 ) (39,741 ) Long-term portion $ 313,852 $ 174,992 (1) Includes $220.6 million and $23.9 million of asset retirement obligations assumed in the Stone Combination and the Whistler Acquisition, respectively.

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Financial Instruments [Abstract]
Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments	The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments (in thousands): December 31, 2018 December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value 11.00% Second-Priority Senior Secured Notes – due April 2022 (1) $ 381,229 $ 362,168 $ — $ — 7.50% Senior Secured Notes – due May 2022 $ 6,060 $ 5,151 $ — $ — Bank Credit Facility – due May 2022 (1) $ 257,448 $ 265,000 $ — $ — 11.00% Bridge Loans – due April 2022 (1) $ — $ — $ 169,838 $ 172,023 9.75% Senior Notes – due July 2022 (1) $ — $ — $ 100,681 $ 102,000 9.75% Senior Notes – due February 2018 $ — $ — $ 24,977 $ 24,977 LLC Bank Credit Facility - due February 2019 (1) $ — $ — $ 402,062 $ 403,000 Oil and Natural Gas Derivatives $ 74,923 $ 74,923 $ (66,830 ) $ (66,830 ) (1) The carrying amounts are net of discount and deferred financing costs.
Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Consolidated Statements of Operations	The following table presents the impact that derivatives, not qualifying as hedging instruments, had on its consolidated statements of operations (in thousands): Year Ended December 31, 2018 2017 2016 Price risk management activities income (expense) (1) $ 60,435 $ (27,563 ) $ (57,398 ) (1) The Company paid cash settlements of $111.1 million, and received cash settlements of $23.8 million and $172.2 million for the years ended December 31, 2018, 2017 and 2016, respectively.
Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under Derivative Contracts	The following table reflects the contracted volumes and weighted average prices the Company will receive under its derivative contracts as of December 31, 2018: Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Weighted Average Put Price Weighted Average Call Price Crude Oil – WTI: (Bbls) (per Bbl) (per Bbl) (per Bbl) January 2019 – December 2019 Swap 25,059 $ 55.39 $ — $ — Natural Gas – Henry Hub NYMEX: (MMBtu) (per MMBtu) (per MMBtu) (per MMBtu) January 2019 – December 2019 Collar 8,630 $ — $ 3.00 $ 3.95 January 2019 – December 2019 Swaps 21,872 $ 2.90 $ — $ — Subsequent event. The following table reflects the contracted volumes and weighted average prices the Company will receive under its derivative contracts entered into subsequent to December 31, 2018, which are not reflected in the table above: Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Weighted Average Put Price Weighted Average Call Price Crude Oil – WTI: (Bbls) (per Bbl) (per Bbl) (per Bbl) April 2019 – December 2019 Swap 3,444 $ 56.94 $ — $ — January 2020 - December 2020 Swap 3,746 $ 57.07 $ — $ — January 2020 - December 2020 Collar 3,000 $ 55.00 $ 55.00 $ 60.64 Natural Gas – Henry Hub NYMEX: (MMBtu) (per MMBtu) (per MMBtu) (per MMBtu) April 2019 – December 2019 Swap 19,418 $ 2.89 $ — $ —
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, 2018 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 75,473 $ — $ 75,473 Liabilities: Oil and natural gas swaps and costless collars — (550 ) — (550 ) Total net asset $ — $ 74,923 $ — $ 74,923 December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 1,908 $ — $ 1,908 Liabilities: Oil and natural gas swaps and costless collars — (68,738 ) — (68,738 ) Total net liability $ — $ (66,830 ) $ — $ (66,830 )
Schedule of Fair Value of Derivative Financial Instruments	The following table presents the fair value of derivative financial instruments at December 31, 2018 and 2017 (in thousands): December 31, 2018 December 31, 2017 Assets Liabilities Assets Liabilities Oil and natural gas derivatives: Current $ 75,473 $ 550 $ 1,563 $ 49,957 Non-current — — 345 18,781 Total $ 75,473 $ 550 $ 1,908 $ 68,738

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2018
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): Description December 31, 2018 December 31, 2017 11.00% Second-Priority Senior Secured Notes – due April 2022 $ 390,868 $ — 7.50% Senior Secured Notes – due May 2022 6,060 — Bank Credit Facility – due May 2022 265,000 — 4.20% Building Loan – due November 2030 10,567 — 11.00% Bridge Loans – due April 2022 — 172,023 9.75% Senior Notes – due July 2022 — 102,000 9.75% Senior Notes – due February 2018 — 24,977 LLC Bank Credit Facility – due February 2019 — 403,000 Total debt, before discount and deferred financing cost 672,495 702,000 Discount and deferred financing cost (17,191 ) (4,442 ) Total debt, net of discount and deferred financing costs 655,304 697,558 Less: Current portion of long-term debt (443 ) (24,977 ) Long-term debt, net of discount and deferred financing costs $ 654,861 $ 672,581

Employee Benefits Plans and S_2

Employee Benefits Plans and Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Schedule of Restricted Stock and Performance Share Units Activity	The following table summarizes RSU activity for the year ended December 31, 2018: Restricted Stock Units Weighted Average Grant Date Fair Value Unvested RSUs at December 31, 2017 — $ — Granted 139,411 33.85 Vested (53 ) 32.86 Forfeited (654 ) 32.86 Unvested RSUs at December 31, 2018 138,704 $ 33.85
Schedule of Restricted Stock and Performance Share Units Activity	The following table summarizes PSU activity for the year ended December 31, 2018: Performance Share Units Weighted Average Grant Date Fair Value Unvested PSUs at December 31, 2017 — $ — Granted 232,891 44.47 Vested — — Forfeited (1,349 ) 42.94 Unvested PSUs at December 31, 2018 231,542 $ 44.47
Summary of Assumptions Used to Calculate the Grant Date Fair Value of PSUs Granted	The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted August 29, 2018 and September 28, 2018: August 29, 2018 Grant Date Fair Value Assumptions September 28, 2018 Grant Date Fair Value Assumptions Number of simulations 100,000 100,000 Expected term (in years) 2.7 2.6 Expected volatility 50.6 % 47.4 % Risk-free interest rate 2.7 % 2.9 % Dividend yield — % — %
Schedule of Recognized Share Based Compensation Expense, Net	For the year ended December 31, 2018, share-based compensation expense did not have any associated income tax benefit. The Company recognized the following share-based compensation expense, net for the following years (in thousands): Year Ended December 31, 2018 2017 2016 Restricted stock units - Employees $ 560 $ — $ — Restricted stock units - Non-employee Directors 402 — — Performance share units 1,129 — — Talos Energy LLC Series B Units 666 1,795 2,287 New Talos Energy LLC Series B Units 3,752 — — Total share-based compensation expense 6,509 1,795 2,287 Less: amounts capitalized to oil and gas properties (3,616 ) (920 ) (1,204 ) Total share-based compensation expense, net $ 2,893 $ 875 $ 1,083

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2016 Current income tax expense (benefit) United States $ — $ — $ — Mexico 1,345 — — Total current income tax expense (benefit) $ 1,345 $ — $ — Deferred income tax expense (benefit) United States $ 1,064 $ — $ — Mexico 513 — — Total deferred income tax expense (benefit) 1,577 — — Total income tax expense (benefit) $ 2,922 $ — $ —
Summary of Reconciliation of Income Taxes Computed at U.S. Federal Statutory Tax Rate to Income Tax Expense	The reconciliation of income taxes computed at the U.S. federal statutory tax rate to the Company’s income tax expense is as follows (in thousands, except percentages): Year Ended December 31, 2018 2017 2016 Income tax (benefit) at the federal statutory tax rate $ 47,137 $ (22,004 ) $ (72,830 ) Earnings not subject to tax 9,980 22,004 72,830 State income taxes 11,738 — — Foreign income taxes 1,008 — — Foreign rate differential 432 — — Prior year taxes 417 — — Other adjustments 800 — — Change in tax status (35,925 ) — — Change in valuation allowance (32,665 ) Total income tax $ 2,922 $ — $ — Effective tax rate 1.30 % — % — %
Summary of Significant Components of Deferred Tax Assets and Liabilities	Deferred taxes 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, 2018 2017 Deferred tax assets: Federal net operating loss $ 117,546 $ — Foreign tax loss carryforward 2,303 4,023 State net operating loss 23,542 — Asset retirement obligations 95,546 — Tax credits 12 — Interest 33,867 — Other 5,909 — Total deferred tax assets 278,725 4,023 Valuation allowance (94,085 ) (4,007 ) Total deferred tax assets, net $ 184,640 $ 16 Deferred tax liabilities Oil and gas properties 166,879 — Hedges 18,246 — Prepaid 3,371 — Deferred tax liabilities 188,496 — Net deferred tax asset (liability) $ (3,856 ) $ 16
Summary of Net Operating Loss and Tax Credit Carryovers	The table below presents the details of the Company’s net operating loss and tax credit carryovers as of December 31, 2018 (in thousands): Amount Expiration Year Federal net operating losses $ 557,895 2034-2038 Foreign tax loss carryforward $ 8,970 2025-2028 State net operating losses $ 307,629 2019-2038
Summary of Balances In Uncertain Tax Positions	Balances in the uncertain tax positions are as follows (in thousands): Year Ended December 31, 2018 2017 Total unrecognized tax benefits, beginning balance $ — $ — Increases (decreases) in unrecognized tax benefits as a result of: Tax positions taken during a prior period 360 — Tax positions taken during the current period — — Settlements with taxing authorities — — Lapse of applicable statute of limitations — — Total unrecognized tax benefits, ending balance $ 360 $ —

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Schedule of Future Minimum Lease Commitments	As of December 31, 2018, minimum lease commitments for the capital lease in future years are as follows (in thousands): 2019 $ 45,000 2020 45,000 2021 45,000 2022 45,000 2023 18,750 Total minimum lease payments 198,750 Less amount represented lease operating expenses (51,864 ) Less amount represented interest (53,218 ) Present value of minimum lease payments 93,668 Less current maturities of capital lease obligations (14,127 ) Long-term capital lease obligations $ 79,541
Summary of Total Minimum Commitments Associated With Long-Term Non-cancelable Operating Lease	The table below summarizes the Company’s total minimum commitments associated with long-term, non-cancelable operating leases, vessel commitments, purchase obligations and the Mexico minimum work program as of December 31, 2018 (in thousands): 2019 2020 2021 2022 Thereafter Total Vessel Commitments (1) $ 35,206 $ — $ — $ — $ — $ 35,206 Committed purchase orders (2) 15,562 11,921 7,921 — — 35,404 Operating lease obligations (3) 3,622 4,315 4,016 4,298 27,225 43,476 Mexico minimum work program — 19,277 — — — 19,277 Total (4) $ 54,390 $ 35,513 $ 11,937 $ 4,298 $ 27,225 $ 133,363 (1) Includes vessel commitments the Company will utilize for certain deep water well intervention and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs. (2) Includes committed purchase orders to execute planned future drilling and completion activities as well as seismic use agreements the Company entered into in connection with the Stone Combination. (3) Amounts include long-term lease payments for office space. (4) Excludes the capital lease for the HP-I floating production facility in the Phoenix Field discussed above.

Condensed Consolidating Finan_2

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2018
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Summary of Condensed Consolidating Financial Information	The following condensed consolidating financial information presents the financial information of the Company on an unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the period indicated. Such financial information may not necessarily be indicative of the Company’s results of operations, cash flows, or financial position had these subsidiaries operated as independent entities. TALOS ENERGY INC. CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2018 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ 13,541 $ 100,801 $ 25,572 $ — $ 139,914 Restricted cash — — 1,248 — — 1,248 Accounts receivable Trade, net — — 103,025 — — 103,025 Joint interest, net — — 15,870 4,374 — 20,244 Other — 3,100 9,566 7,020 — 19,686 Assets from price risk management activities — 75,473 — — — 75,473 Prepaid assets — 1,225 37,639 47 — 38,911 Income tax receivable — — 10,701 — — 10,701 Other current assets — — 7,644 — — 7,644 Total current assets — 93,339 286,494 37,013 — 416,846 Property and equipment: Proved properties — — 3,629,430 — — 3,629,430 Unproved properties, not subject to amortization — — 63,104 45,105 — 108,209 Other property and equipment — 20,670 12,440 81 — 33,191 Total property and equipment — 20,670 3,704,974 45,186 — 3,770,830 Accumulated depreciation, depletion and amortization — (8,310 ) (1,711,288 ) (11 ) — (1,719,609 ) Total property and equipment, net — 12,360 1,993,686 45,175 — 2,051,221 Other long-term assets: Other well equipment inventory — — 9,224 — — 9,224 Investments in subsidiaries 1,011,359 1,560,922 — — (2,572,281 ) — Other assets — 364 2,258 73 — 2,695 1,011,359 1,666,985 2,291,662 82,261 (2,572,281 ) 2,479,986 LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable 144 1,242 42,736 6,897 — 51,019 Accrued liabilities — 4,995 159,491 24,164 — 188,650 Accrued royalties — — 38,520 — — 38,520 Current portion of long-term debt — — 443 — — 443 Current portion of asset retirement obligations — — 68,965 — — 68,965 Liabilities from price risk management activities 550 — — — 550 Accrued interest payable — 10,162 38 — — 10,200 Other current liabilities — — 22,071 — — 22,071 Total current liabilities 144 16,949 332,264 31,061 — 380,418 Long-term debt, net of discount and deferred financing costs — 638,677 16,184 — — 654,861 Asset retirement obligations — — 313,852 — — 313,852 Other long-term liabilities 3,719 — 119,432 208 — 123,359 Total liabilities 3,863 655,626 781,732 31,269 — 1,472,490 Commitments and Contingencies (Note 11) Stockholders' equity (deficit) 1,007,496 1,011,359 1,509,930 50,992 (2,572,281 ) 1,007,496 $ 1,011,359 $ 1,666,985 $ 2,291,662 $ 82,261 $ (2,572,281 ) $ 2,479,986 TALOS ENERGY INC. CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2017 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ 22,315 $ 7,806 $ 2,070 $ — $ 32,191 Restricted cash — — 1,242 — — 1,242 Accounts receivable, net Trade, net — — 62,871 — — 62,871 Joint interest, net — — 11,659 1,954 — 13,613 Other — 938 5,863 5,685 — 12,486 Assets from price risk management activities — 1,406 157 — — 1,563 Prepaid assets — — 17,919 12 — 17,931 Inventory — — 840 — — 840 Other current assets — — 2,148 — — 2,148 Total current assets — 24,659 110,505 9,721 — 144,885 Property and equipment: Proved properties — — 2,440,811 — — 2,440,811 Unproved properties, not subject to amortization — — 41,259 30,743 — 72,002 Other property and equipment — 7,266 1,580 11 — 8,857 Total property and equipment — 7,266 2,483,650 30,754 — 2,521,670 Accumulated depreciation, depletion and amortization — (6,355 ) (1,424,527 ) (8 ) — (1,430,890 ) Total property and equipment, net — 911 1,059,123 30,746 — 1,090,780 Other long-term assets: Assets from price risk management activities — 345 — — — 345 Other well equipment inventory — — 2,577 — — 2,577 Investments in subsidiaries (54,087 ) 697,663 — — (643,576 ) — Other assets — 364 326 16 — 706 Total assets $ (54,087 ) $ 723,942 $ 1,172,531 $ 40,483 $ (643,576 ) $ 1,239,293 LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable $ — $ 1,124 $ 70,458 $ 1,099 $ — $ 72,681 Accrued liabilities — 6,516 80,464 993 — 87,973 Accrued royalties — — 24,208 — — 24,208 Current portion of long-term debt — 24,977 — — — 24,977 Current portion of asset retirement obligations — — 39,741 — — 39,741 Liabilities from price risk management activities — 46,580 3,377 — — 49,957 Accrued interest payable — 8,742 — — — 8,742 Other current liabilities — — 15,188 — — 15,188 Total current liabilities — 87,939 233,436 2,092 — 323,467 Long-term debt, net of discount and deferred financing costs — 672,581 — — — 672,581 Asset retirement obligations — — 174,992 — — 174,992 Liabilities from price risk management activities — 17,509 1,272 — — 18,781 Other long-term liabilities — — 103,559 — — 103,559 Total liabilities — 778,029 513,259 2,092 — 1,293,380 Commitments and Contingencies (Note 11) Stockholders' equity (deficit) (54,087 ) (54,087 ) 659,272 38,391 (643,576 ) (54,087 ) $ (54,087 ) $ 723,942 $ 1,172,531 $ 40,483 $ (643,576 ) $ 1,239,293 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2018 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 781,815 $ — $ — $ 781,815 Natural gas revenue — — 73,610 — — 73,610 NGL revenue — — 35,863 — — 35,863 Total revenue — — 891,288 — — 891,288 Operating expenses: Direct lease operating expense — — 145,988 — — 145,988 Insurance — — 15,342 — — 15,342 Production taxes — — 1,989 — — 1,989 Total lease operating expense — — 163,319 — — 163,319 Workover and maintenance expense — — 64,961 — — 64,961 Depreciation, depletion and amortization — 1,955 286,760 4 — 288,719 Accretion expense — — 35,344 — — 35,344 General and administrative expense 142 43,841 40,035 1,798 — 85,816 Total operating expenses 142 45,796 590,419 1,802 — 638,159 Operating income (loss) (142 ) (45,796 ) 300,869 (1,802 ) — 253,129 Interest expense — (58,172 ) (30,255 ) (1,687 ) — (90,114 ) Price risk management activities income — 50,025 10,410 — — 60,435 Other income (loss) — (1,563 ) 874 1,701 — 1,012 Income tax expense (1,065 ) — (360 ) (1,497 ) — (2,922 ) Equity earnings (losses) from subsidiaries 222,747 278,253 — — (501,000 ) — Net income (loss) $ 221,540 $ 222,747 $ 281,538 $ (3,285 ) $ (501,000 ) $ 221,540 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2017 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 344,781 $ — $ — $ 344,781 Natural gas revenue — — 48,886 — — 48,886 NGL revenue — — 16,658 — — 16,658 Other — — 2,503 — — 2,503 Total revenue — — 412,828 — — 412,828 Operating expenses: Direct lease operating expense — — 109,180 — — 109,180 Insurance — — 10,743 — — 10,743 Production taxes — — 1,460 — — 1,460 Total lease operating expense — — 121,383 — — 121,383 Workover and maintenance expense — — 32,825 — — 32,825 Depreciation, depletion and amortization — 1,401 155,947 4 — 157,352 Accretion expense — — 19,295 — — 19,295 General and administrative expense — 21,882 14,172 619 — 36,673 Total operating expenses — 23,283 343,622 623 — 367,528 Operating income (loss) — (23,283 ) 69,206 (623 ) — 45,300 Interest expense — (48,236 ) (30,252 ) (2,446 ) — (80,934 ) Price risk management activities expense — (22,998 ) (4,565 ) — — (27,563 ) Other income (expense) — 600 (333 ) 62 — 329 Equity earnings from subsidiaries (62,868 ) 31,049 — — 31,819 — Net income (loss) $ (62,868 ) $ (62,868 ) $ 34,056 $ (3,007 ) $ 31,819 $ (62,868 ) TALOS ENERGY INC. CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2016 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 197,583 $ — — $ 197,583 Natural gas revenue — — 42,705 — — 42,705 NGL revenue — — 9,532 — — 9,532 Other — — 8,934 — — 8,934 Total revenue — — 258,754 — — 258,754 Operating expenses: Direct lease operating expense — — 124,360 — — 124,360 Insurance — — 13,101 — — 13,101 Production taxes — — 1,958 — — 1,958 Total lease operating expense — — 139,419 — — 139,419 Workover and maintenance expense — — 24,810 — — 24,810 Depreciation, depletion and amortization — 1,553 123,132 4 — 124,689 Accretion expense — — 21,829 — — 21,829 General and administrative expense — 13,204 15,044 438 — 28,686 Total operating expenses — 14,757 324,234 442 — 339,433 Operating loss — (14,757 ) (65,480 ) (442 ) — (80,679 ) Interest expense — (47,291 ) (19,680 ) (3,444 ) — (70,415 ) Price risk management activities expense — (57,398 ) — — — (57,398 ) Other income (expense) — — 430 (25 ) — 405 Equity earnings from subsidiaries (208,087 ) (88,641 ) — — 296,728 — Net income (loss) $ (208,087 ) $ (208,087 ) $ (84,730 ) $ (3,911 ) $ 296,728 $ (208,087 ) TALOS ENERGY INC. CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2018 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ (193,088 ) $ 442,890 $ 13,643 $ — $ 263,445 Cash flows from investing activities: Exploration, development, and other capital expenditures — (13,404 ) (227,228 ) (282 ) — (240,914 ) Cash paid for acquisitions, net of cash acquired — — 278,409 — — 278,409 Investments in subsidiaries — (1,316,588 ) — — 1,316,588 — Distributions from subsidiaries — 1,694,460 9 — (1,694,469 ) — Net cash provided by (used in) investing activities — 364,468 51,190 (282 ) (377,881 ) 37,495 Cash flows from financing activities: Redemption of Senior Notes and other long-term debt — (25,152 ) (105 ) — — (25,257 ) Proceeds from Bank Credit Facility — 319,000 — — — 319,000 Repayment of Bank Credit Facility — (54,000 ) — — — (54,000 ) Repayment of LLC Bank Credit Facility — (403,000 ) — — — (403,000 ) Deferred financing costs — (17,002 ) — — — (17,002 ) Payment of capital lease — — (12,952 ) — — (12,952 ) Capital contributions — — 1,301,876 14,712 (1,316,588 ) — Distributions to Subsidiary Issuer — — (1,689,898 ) (4,571 ) 1,694,469 — Net cash provided by (used in) financing activities — (180,154 ) (401,079 ) 10,141 377,881 (193,211 ) Net increase (decrease) in cash, cash equivalents and restricted cash — (8,774 ) 93,001 23,502 — 107,729 Cash, cash equivalents and restricted cash Balance, beginning of period — 22,315 9,048 2,070 — 33,433 Balance, end of period $ — $ 13,541 $ 102,049 $ 25,572 $ — $ 141,162 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2017 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ (30,245 ) $ 204,419 $ 1,879 $ — $ 176,053 Cash flows from investing activities: Exploration, development, and other capital expenditures — (260 ) (132,317 ) (22,600 ) — (155,177 ) Cash paid for acquisitions, net of cash acquired — — (2,464 ) — — (2,464 ) Investments in subsidiaries — (577,055 ) — — 577,055 — Distributions from subsidiaries — 611,526 6,041 — (617,567 ) — Net cash provided by (used in) investing activities — 34,211 (128,740 ) (22,600 ) (40,512 ) (157,641 ) Cash flows from financing activities: Redemption of 2018 Senior Notes — (1,000 ) — — — (1,000 ) Proceeds from Bank Credit Facility — 10,000 — — — 10,000 Repayment of Bank Credit Facility — (15,000 ) — — — (15,000 ) Payments of capital lease — — (12,412 ) — — (12,412 ) Capital contributions — — 550,555 26,500 (577,055 ) — Distributions to subsidiaries — — (611,526 ) (6,041 ) 617,567 — Net cash provided by (used in) financing activities — (6,000 ) (73,383 ) 20,459 40,512 (18,412 ) Net increase (decrease) in cash, cash equivalents and restricted cash — (2,034 ) 2,296 (262 ) — — Cash, cash equivalents and restricted cash: Balance, beginning of period — 24,349 6,752 2,332 — 33,433 Balance, end of period $ — $ 22,315 $ 9,048 $ 2,070 $ — $ 33,433 TALOS ENERGY INC. CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2016 (In thousands) Parent Subsidiary Issuers Guarantors Non-Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ 124,698 $ (2,806 ) $ (5,769 ) — $ 116,123 Cash flows from investing activities: Exploration, development, and other capital expenditures — (301 ) (106,647 ) (6,084 ) — (113,032 ) Cash paid for acquisitions, net of cash acquired — — (85,886 ) — — (85,886 ) Investments in subsidiaries (91,891 ) (524,192 ) — — 616,083 — Distributions from subsidiaries — 411,074 — — (411,074 ) — Net cash provided by (used in) investing activities (91,891 ) (113,419 ) (192,533 ) (6,084 ) 205,009 (198,918 ) Cash flows from financing activities: Proceeds from Bank Credit Facility — 15,000 — — — 15,000 Repayment of Bank Credit Facility — (10,000 ) — — — (10,000 ) Payments of capital lease — — (5,267 ) — — (5,267 ) Capital contributions — — 599,630 16,453 (616,083 ) — Distributions to subsidiaries — — (408,050 ) (3,024 ) 411,074 — Contributions from Sponsors 93,750 — — — — 93,750 Distributions to Sponsors (1,859 ) — — — — (1,859 ) Net cash provided by (used in) financing activities 91,891 5,000 186,313 13,429 (205,009 ) 91,624 Net increase (decrease) in cash, cash equivalents and restricted cash — 16,279 (9,026 ) 1,576 — 8,829 Cash, cash equivalents and restricted cash: Balance, beginning of period — 8,070 15,778 756 — 24,604 Balance, end of period $ — $ 24,349 $ 6,752 $ 2,332 $ — $ 33,433

Selected Quarterly Financial _2

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Unaudited Quarterly Financial Data	Unaudited quarterly financial data are as follows (in thousands): March 31 June 30 September 30 December 31 Quarter Ended 2018 Revenues $ 145,850 $ 203,906 $ 282,868 $ 258,664 Operating income 48,584 39,211 91,361 73,973 Price risk management activities income (expense) (51,976 ) (91,176 ) (53,330 ) 256,917 Net income (loss) $ (22,943 ) $ (74,912 ) $ 13,109 $ 306,286 Net income (loss) per common share: Basic $ (0.73 ) $ (1.69 ) $ 0.24 $ 5.66 Diluted $ (0.73 ) $ (1.69 ) $ 0.24 $ 5.66 Weighted average common shares outstanding: Basic 31,244 44,336 54,156 54,156 Diluted 31,244 44,336 54,164 54,159 Quarter Ended 2017 Revenues $ 101,824 $ 95,426 $ 99,962 $ 115,616 Operating income 7,287 6,314 13,329 18,370 Price risk management activities income (expense) 45,893 38,995 (28,086 ) (84,365 ) Net income (loss) $ 34,462 $ 24,607 $ (36,177 ) $ (85,760 ) Net income (loss) per common share: Basic $ 1.10 $ 0.79 $ (1.16 ) $ (2.74 ) Diluted $ 1.10 $ 0.79 $ (1.16 ) $ (2.74 ) Weighted average common shares outstanding: Basic 31,244 31,244 31,244 31,244 Diluted 31,244 31,244 31,244 31,244

Supplemental Oil and Gas Disc_2

Supplemental Oil and Gas Disclosures (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
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): December 31, 2018 2017 Proved properties $ 3,629,430 $ 2,440,811 Unproved oil and gas properties, not subject to amortization 108,209 72,002 Total oil and gas properties 3,737,639 2,512,813 Less: Accumulated depletion and amortization (1,709,614 ) (1,423,829 ) Net capitalized costs $ 2,028,025 $ 1,088,984 Depletion and amortization rate per Boe $ 17.07 $ 14.85
Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities	The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Year Ended December 31, 2018 2017 2016 Property acquisition costs: Proved properties $ 850,515 $ 1,108 $ 77,906 Unproved properties, not subject to amortization 65,063 5,778 15,919 Total property acquisition costs 915,578 6,886 93,825 Exploration costs 93,780 82,887 27,807 Development costs 215,467 114,846 195,869 Total costs incurred $ 1,224,825 $ 204,619 $ 317,501
Schedule of Estimated Proved Reserves at Net Ownership Interest	The following table presents the Company’s estimated proved reserves at its net ownership interest: Oil (MBbls) Gas (MMcf) NGL (MBbls) Oil Equivalent (MBoe) Total proved reserves at December 31, 2015 46,354 129,224 4,581 72,473 Revision of previous estimates (1,712 ) 10,024 (352 ) (394 ) Production (5,126 ) (19,001 ) (603 ) (8,896 ) Purchases of reserves 11,128 11,208 950 13,946 Extensions and discoveries 21,722 19,149 1,660 26,573 Total proved reserves at December 31, 2016 72,366 150,604 6,236 103,702 Revision of previous estimates (2,673 ) (15,860 ) 250 (5,067 ) Production (7,048 ) (16,308 ) (706 ) (10,472 ) Extensions and discoveries 10,159 9,220 767 12,462 Total proved reserves at December 31, 2017 72,804 127,656 6,547 100,625 Revision of previous estimates 2,595 (37,933 ) 3,187 (539 ) Production (11,771 ) (22,771 ) (1,176 ) (16,742 ) Purchases of reserves 44,788 95,661 2,074 62,806 Extensions and discoveries 4,123 8,411 64 5,589 Total proved reserves at December 31, 2018 112,539 171,024 10,696 151,739 Total proved developed reserves as of: December 31, 2016 45,753 96,122 4,032 65,805 December 31, 2017 37,460 77,577 3,315 53,704 December 31, 2018 85,530 131,364 8,104 115,528 Total proved undeveloped reserves as of: December 31, 2016 26,613 54,482 2,204 37,897 December 31, 2017 35,344 50,079 3,232 46,921 December 31, 2018 27,009 39,660 2,592 36,211
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): December 31, 2018 2017 2016 Future cash inflows $ 8,654,631 $ 4,308,863 $ 3,390,612 Future costs: Production (1,740,850 ) (815,509 ) (775,354 ) Development and abandonment (1,349,005 ) (823,164 ) (664,254 ) Future net cash flows before income taxes 5,564,776 2,670,190 1,951,004 Future income tax expense (1) (862,473 ) — — Future net cash flows after income taxes 4,702,303 2,670,190 1,951,004 Discount at 10% annual rate (1,362,057 ) (862,521 ) (614,969 ) Standardized measure of discounted future net cash flows $ 3,340,246 $ 1,807,669 $ 1,336,035 (1) For December 31, 2017 and 2016, the standardized measure of discounted future net cash flows did not include the impact of future federal income taxes because Talos Energy LLC was not subject to federal income taxes prior to the Stone Combination.
Schedule of Base Prices Used in Determining Standardized Measure	Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for base prices used in determining the standardized measure: Year Ended December 31, 2018 2017 2016 Oil price per Bbl $ 69.42 $ 51.36 $ 40.02 Natural gas prices per Mcf $ 3.08 $ 3.20 $ 2.66 NGL price per Bbl $ 29.50 $ 24.64 $ 14.96
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, 2018 2017 2016 Standardized measure, beginning of year $ 1,807,669 $ 1,336,035 $ 602,981 Changes during the year: Sales and transfers of oil, net gas and NGLs produced during the period (727,969 ) (288,942 ) (114,625 ) Net change in prices and production costs 1,578,330 555,100 80,174 Changes in estimated future development costs 32,328 (156,282 ) 2,292 Previously estimated development costs incurred 45,937 146,687 108,484 Accretion of discount 180,767 133,603 60,298 Net change in income taxes (1) (585,017 ) — — Purchases of reserves 943,519 — 222,581 Extensions and discoveries 148,068 328,565 479,833 Net change due to revision in quantity estimates 190,853 (113,629 ) (5,685 ) Changes in production rates (timing) and other (274,239 ) (133,468 ) (100,298 ) Total 1,532,577 471,634 733,054 Standardized measure, end of year $ 3,340,246 $ 1,807,669 $ 1,336,035 (1) For December 31, 2017 and 2016, the standardized measure of discounted future net cash flows did not include the impact of future federal income taxes because Talos Energy LLC was not subject to federal income taxes prior to the Stone Combination.

Formation and Basis of Presen_2

Formation and Basis of Presentation - Additional Information (Details) $ / shares in Units, $ in Thousands	May 10, 2018USD ($)$ / sharesshares	Nov. 21, 2017USD ($)shares	Dec. 31, 2018USD ($)Segment	Dec. 31, 2017USD ($)
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Common stock par value | $ / shares	$ 0.01
Senior notes, maturity date			Feb. 28, 2019	Feb. 28, 2019
Senior notes, outstading amount			$ 672,495	$ 702,000
Number of reportable segment | Segment			1
Talos Energy LLC Stakeholders | Talos Energy Inc.
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Percentage of voting interest acquired	63.00%
Stone Energy Corporation Stockholders | Talos Energy Inc.
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Percentage of voting interest acquired	37.00%
9.75% Senior Notes – due July 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate			9.75%	9.75%
Senior notes, maturity date			Jul. 5, 2022	Jul. 5, 2022
11.00% Second-Priority Senior Secured Notes – due April 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate			11.00%	11.00%
Senior notes, maturity date			Apr. 30, 2022	Apr. 30, 2022
Senior Notes | 9.75% Senior Notes
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Proceeds from issuance of senior notes		$ 102,000
Debt instrument interest rate		9.75%	9.75%
Shares issued on exchange agreement | shares		2,874,049
Senior notes, outstading amount			$ 102,000
Senior Notes | 9.75% Senior Notes – due July 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate			9.75%
Senior notes, maturity date			Jul. 31, 2022
Senior notes, outstading amount				$ 102,000
Senior Notes | 7.50% Senior Secured Notes due 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate		7.50%	7.50%
Proceeds from Issuance of senior secured notes in exchange of 11% senior secured notes		$ 137,400
Senior notes, principal amount	$ 81,500
Senior notes, outstading amount	$ 6,100
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate		11.00%	11.00%
Senior notes, maturity date			Apr. 30, 2022
Senior notes, outstading amount			$ 390,868
Debt instrument interest rate exchanged percentage	11.00%
Bridge Loans | 11.00% Bridge Loans
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate		11.00%
Proceeds from issuance of bridge loans in exchange of 11% senior secured notes		$ 172,000
Stone Energy Corporation
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Closing date of merger agreement			May 10, 2018
Stone Energy Corporation | 11.00% Second-Priority Senior Secured Notes – due April 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate			11.00%
Senior notes, maturity date			Apr. 30, 2022
Senior notes, principal amount			$ 390,900
Talos Production LLC
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Percentage of voting interest acquired	100.00%
Share issued on merger | shares	31,244,085

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2016
Summary Of Significant Accounting Policies [Line Items]
Allowance for uncollectible accounts	$ 8,700	$ 5,900
Capital lease asset				$ 124,300
Transportation costs	12,500	10,300	$ 9,100
Impairment to adjust other well equipment inventory	$ 244	$ 260	$ 218
Minimum
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, estimated useful lives	3 years
Number of common stock issuable upon vesting, percentage range of PSUs granted	0.00%
Maximum
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, estimated useful lives	10 years
Number of common stock issuable upon vesting, percentage range of PSUs granted	200.00%
Measurement Input Discount Rate
Summary Of Significant Accounting Policies [Line Items]
Present value of future net revenues from proved reserves, discount rate	10.00%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Schedule of Percent of Consolidated Revenue of Major Customers, Those Whose Total Represented 10% or More of Oil, Natural Gas and NGL Revenues (Details) - Sales Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Shell Trading (US) Company
Concentration Risk [Line Items]
Concentration risk, percentage	65.00%	80.00%	68.00%
Phillips 66
Concentration Risk [Line Items]
Concentration risk, percentage	18.00%
Chevron U.S.A Inc
Concentration Risk [Line Items]
Concentration risk, percentage			14.00%

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Schedule of Percent of Consolidated Revenue of Major Customers, Those Whose Total Represented 10% or More of Oil, Natural Gas and NGL Revenues (Parenthetical) (Details) - Sales Revenue - Customer Concentration Risk - Chevron U.S.A Inc	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Concentration Risk [Line Items]
Concentration risk, percentage			14.00%
Maximum
Concentration Risk [Line Items]
Concentration risk, percentage	10.00%	10.00%	10.00%

Acquisitions - Additional Infor

Acquisitions - Additional Information (Details)	Aug. 31, 2018USD ($)	May 10, 2018USD ($)	Dec. 20, 2016USD ($)$ / bbl	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Senior Notes | Second Priority Senior Secured Notes
Business Acquisition [Line Items]
Debt instrument interest rate				11.00%		11.00%
Stone Energy Corporation
Business Acquisition [Line Items]
Purchase price		$ 731,964,000
Acquisition, transaction related cost						$ 88,600,000
Acquisition, transaction related fees to note holders and for seismic use agreements						56,100,000
Acquisition, transaction related fees paid to note holders						9,300,000
Acquisition, transaction related fees for seismic use agreements						46,800,000
Decrease in income tax receivables				$ 5,500,000	$ 5,500,000
Increase in trade receivables				1,000,000	1,000,000
Increase in other long -term liabilities				2,700,000	2,700,000
Increase in unproved properties				$ 7,200,000	$ 7,200,000
Revenue attributable to the assets acquired						332,900,000
Net income attributable to the assets acquired						148,500,000
Stone Energy Corporation | General and Administrative Expense
Business Acquisition [Line Items]
Acquisition, transaction related cost						$ 32,500,000
Whistler Energy II, LLC
Business Acquisition [Line Items]
Purchase price	$ 52,600,000
Business acquisition purchase price net	14,800,000
Available cash acquired	37,800,000
Business combination cash collateral	30,800,000
Business combination cash on hand for working capital	$ 7,000,000
Sojitz Energy Venture Inc
Business Acquisition [Line Items]
Percentage of voting interest acquired			15.00%
Purchase price			$ 93,800
Business acquisition purchase price net			91,900
Business acquisition purchase price in cash			85,800
Business acquisition transaction fees			$ 1,900
Consideration earn out percentage			5.00%
Oil price realized | $ / bbl			65
Payout under the earn-out			$ 10,000
Business combination post-closing adjustments							$ 2,500,000
Talos Energy LLC Stakeholders | Talos Energy Inc.
Business Acquisition [Line Items]
Percentage of voting interest acquired		63.00%
Stone Energy Corporation Stockholders | Talos Energy Inc.
Business Acquisition [Line Items]
Percentage of voting interest acquired		37.00%

Acquisitions - Summary of Purch

Acquisitions - Summary of Purchase Price (Details) - USD ($) $ / shares in Units, $ in Thousands	May 10, 2018	Dec. 31, 2018	May 09, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Common stock value		$ 542		$ 312
Stone Energy Corporation
Business Acquisition [Line Items]
Stone Energy common stock - issued and outstanding as of May 9, 2018			20,038,000
Stone Energy common stock price	$ 35.49
Common stock value	$ 711,149
Stone Energy common stock warrants - issued and outstanding as of May 9, 2018			3,528,000
Stone Energy common stock warrants price	$ 5.90
Common stock warrants value	$ 20,815
Total purchase price	$ 731,964

Acquisitions - Summary of Alloc

Acquisitions - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Aug. 31, 2018	May 10, 2018
Stone Energy Corporation
Business Acquisition [Line Items]
Current assets		$ 372,760
Property and equipment		883,490
Other long-term assets		18,928
Current liabilities		(130,062)
Long-term debt		(235,416)
Other long-term liabilities		(177,736)
Allocated purchase price		$ 731,964
Whistler Energy II, LLC
Business Acquisition [Line Items]
Current assets	$ 45,337
Property and equipment	35,344
Other long-term assets	66
Current liabilities	(4,261)
Allocated purchase price	52,624
Asset retirement obligations	$ (23,862)

Acquisitions - Summary of All_2

Acquisitions - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Parenthetical) (Details) - USD ($) $ in Millions	Aug. 31, 2018	May 10, 2018
Stone Energy Corporation
Business Acquisition [Line Items]
Cash acquired		$ 293
Stone Energy Corporation | Trade Accounts Receivable
Business Acquisition [Line Items]
Primary fair values of receivables acquired		43.3
Stone Energy Corporation | Joint Interest Receivables
Business Acquisition [Line Items]
Primary fair values of receivables acquired		$ 3.5
Whistler Energy II, LLC
Business Acquisition [Line Items]
Cash acquired	$ 37.8
Whistler Energy II, LLC | Trade Accounts Receivable
Business Acquisition [Line Items]
Primary fair values of receivables acquired	$ 3.2

Acquisitions - Summary of Suppl

Acquisitions - Summary of Supplemental Proforma Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition Pro Forma Information [Abstract]
Revenue	$ 1,013,184	$ 712,648
Net income (loss)	$ 274,577	$ (100,980)
Basic and diluted net income (loss) per common share	$ 5.07	$ (1.86)

Acquisitions - Summary of Preli

Acquisitions - Summary of Preliminary Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - Sojitz Energy Venture Inc $ in Thousands	Dec. 20, 2016USD ($)
Business Acquisition [Line Items]
Proved properties	$ 77,967
Unproved properties, not subject to amortization	11,133
Other short and long-term assets	2,380
Asset retirement obligations	(3,242)
Allocated purchase price	$ 88,238

Property, Plant and Equipment -

Property, Plant and Equipment - Additional Information (Details)	Dec. 21, 2018	Sep. 30, 2018	Dec. 31, 2018USD ($)$ / bbl$ / Mcf	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Aug. 31, 2016USD ($)
Property, Plant and Equipment [Line Items]
capital lease | $			$ 79,541,000			$ 124,300
Capitalized overhead costs | $			$ 21,900,000	$ 13,700,000	$ 12,500,000
Block 2
Property, Plant and Equipment [Line Items]
Participating interest percentage		25.00%
Block 2 | Hokchi Cross Assignment | Hokchi
Property, Plant and Equipment [Line Items]
Participating interest percentage	25.00%	25.00%
Block 2 | Premier’s Option Exercise
Property, Plant and Equipment [Line Items]
Participating interest percentage		5.00%
Block 2 | Premier’s Option Exercise | Sierra
Property, Plant and Equipment [Line Items]
Participating interest percentage			5.00%
Block 2 | Premier’s Option Exercise | Premier
Property, Plant and Equipment [Line Items]
Reduction in participating interest percentage upon option exercise			0.00%
Block 31
Property, Plant and Equipment [Line Items]
Participating interest percentage		25.00%
Block 31 | Hokchi Cross Assignment | Hokchi
Property, Plant and Equipment [Line Items]
Participating interest percentage		25.00%
US
Property, Plant and Equipment [Line Items]
Unweighted average first day of month commodity price for crude oil for prior twelve months | $ / bbl			69.42
Unweighted average first day of month commodity price for natural gas for prior twelve months | $ / Mcf			3.08
Unweighted average first day of month commodity price for natural gas liquids for prior twelve months | $ / bbl			29.50
Measurement Input Discount Rate
Property, Plant and Equipment [Line Items]
Present value of future net revenues from proved reserves, discount rate			10.00%

Property, Plant and Equipment_2

Property, Plant and Equipment - Summary of Oil and Natural Gas Property Costs Not Being Amortized (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	$ 108,209
United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	49,777
Exploration	13,327
Total unproved properties, not subject to amortization	63,104
Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	45,105
Total unproved properties, not subject to amortization	45,105
2018
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	63,410
2018 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	40,657
Exploration	8,391
Total unproved properties, not subject to amortization	49,048
2018 | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	14,362
Total unproved properties, not subject to amortization	14,362
2017
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	26,520
2017 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	3,188
Total unproved properties, not subject to amortization	3,188
2017 | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	23,332
Total unproved properties, not subject to amortization	23,332
2016
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	8,446
2016 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	2,244
Exploration	92
Total unproved properties, not subject to amortization	2,336
2016 | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	6,110
Total unproved properties, not subject to amortization	6,110
2015 and Prior
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	9,833
2015 and Prior | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	6,876
Exploration	1,656
Total unproved properties, not subject to amortization	8,532
2015 and Prior | Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	1,301
Total unproved properties, not subject to amortization	$ 1,301

Property, Plant and Equipment_3

Property, Plant and Equipment - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil And Gas Property [Abstract]
Asset retirement obligations	$ 214,733	$ 220,049
Fair value of asset retirement obligations acquired	244,766	699
Obligations settled	(112,946)	(32,573)
Accretion expense	35,344	19,295	$ 21,829
Obligations incurred	358	4,213
Changes in estimate	562	3,050
Asset retirement obligations	382,817	214,733	$ 220,049
Less: Current portion	(68,965)	(39,741)
Long-term portion	$ 313,852	$ 174,992

Property, Plant and Equipment_4

Property, Plant and Equipment - Schedule of Asset Retirement Obligations (Parenthetical) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Stone Energy Corporation
Property, Plant and Equipment [Line Items]
Fair value of asset retirement obligations assumed	$ 220.6
Whistler Energy II, LLC
Property, Plant and Equipment [Line Items]
Fair value of asset retirement obligations assumed	$ 23.9

Financial Instruments - Schedul

Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Thousands		Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Carrying Amount	[1]		$ 402,062
Fair Value	[1]		403,000
Oil and Natural Gas Derivatives
Debt Instrument [Line Items]
Carrying Amount		$ 74,923	(66,830)
Fair Value		74,923	(66,830)
11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Carrying Amount		381,229
Fair Value		362,168
7.50% Senior Secured Notes – due May 2022
Debt Instrument [Line Items]
Carrying Amount		6,060
Fair Value		5,151
11.00% Bridge Loans – due April 2022
Debt Instrument [Line Items]
Carrying Amount	[1]		169,838
Fair Value	[1]		172,023
9.75% Senior Notes – due July 2022
Debt Instrument [Line Items]
Carrying Amount	[1]		100,681
Fair Value	[1]		102,000
9.75% Senior Notes – due February 2018
Debt Instrument [Line Items]
Carrying Amount			24,977
Fair Value			$ 24,977
Bank Credit Facility – due May 2022
Debt Instrument [Line Items]
Carrying Amount	[1]	257,448
Fair Value	[1]	$ 265,000
[1]	The carrying amounts are net of discount and deferred financing costs.

Financial Instruments - Sched_2

Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Senior notes, maturity date	Feb. 28, 2019	Feb. 28, 2019
Bank Credit Facility – due May 2022
Debt Instrument [Line Items]
Senior notes, maturity date	May 10, 2022	May 10, 2022
11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%	11.00%
Senior notes, maturity date	Apr. 30, 2022	Apr. 30, 2022
7.50% Senior Secured 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
11.00% Bridge Loans – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%	11.00%
Senior notes, maturity date	Apr. 3, 2022	Apr. 3, 2022
9.75% Senior Notes – due July 2022
Debt Instrument [Line Items]
Debt instrument interest rate	9.75%	9.75%
Senior notes, maturity date	Jul. 5, 2022	Jul. 5, 2022
9.75% Senior Notes – due February 2018
Debt Instrument [Line Items]
Debt instrument interest rate	9.75%	9.75%
Senior notes, maturity date	Feb. 15, 2018	Feb. 15, 2018

Financial Instruments - Additio

Financial Instruments - Additional Information (Details)	12 Months Ended
	Dec. 31, 2018USD ($)counterparty	Dec. 31, 2017	May 10, 2018USD ($)
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes, maturity date	Feb. 28, 2019	Feb. 28, 2019
Bank Credit Facility
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Number of counterparties | counterparty	7
Investment Grade Credit Rating
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Number of counterparties | counterparty	9
11.00% Second-Priority Senior Secured Notes – due April 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	11.00%	11.00%
Senior notes, maturity date	Apr. 30, 2022	Apr. 30, 2022
7.50% Senior Secured Notes – due May 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes, principal amount			$ 6,100,000
Debt instrument interest rate	7.50%	7.50%
Senior notes, maturity date	May 31, 2022	May 31, 2022
New Bank Credit Facility
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes, maturity date	May 10, 2022
New Bank Credit Facility | LLC Bank Credit Facility
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Credit facility, maximum borrowing capacity			$ 600,000,000
Stone Energy Corporation | 11.00% Second-Priority Senior Secured Notes – due April 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes, principal amount	$ 390,900,000
Debt instrument interest rate	11.00%
Senior notes, maturity date	Apr. 30, 2022
Stone Energy Corporation | 7.50% Senior Secured Notes – due May 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes, principal amount	$ 6,100,000
Debt instrument interest rate	7.50%
Senior notes, maturity date	May 31, 2022

Financial Instruments - Sched_3

Financial Instruments - Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Consolidated Statements of Operations (Details) - USD ($) $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Price risk management activities income (expense)

$ 256,917

$ (53,330)

$ (91,176)

$ (51,976)

$ (84,365)

$ (28,086)

$ 38,995

$ 45,893

$ 60,435

[1]

$ (27,563)

[1]

$ (57,398)

[1]

[1]

The Company paid cash settlements of $111.1 million, and received cash settlements of $23.8 million and $172.2 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Financial Instruments - Sched_4

Financial Instruments - Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Consolidated Statements of Operations (Parenthetical) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Net cash receipts (payments) on settled derivative instruments	$ (111,147)	$ 23,834	$ 172,182

Financial Instruments - Sched_5

Financial Instruments - Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under Derivative Contracts (Details)	1 Months Ended	12 Months Ended
	Feb. 08, 2019MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2018MMBTU$ / bbl$ / MMBTUbbl
January 2019 - December 2019 | Swap | NYMEX | Henry Hub
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type		Swaps
Average Daily Volumes | MMBTU		21,872
Weighted Average Swap Price | $ / MMBTU		2.90
January 2019 - December 2019 | Collar | NYMEX | Henry Hub
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type		Collar
Average Daily Volumes | MMBTU		8,630
Weighted Average Put Price | $ / MMBTU		3
Weighted Average Call Price | $ / MMBTU		3.95
April 2019 - December 2019 | Swap | NYMEX | Henry Hub | Subsequent Event
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type	Swap
Average Daily Volumes | MMBTU	19,418
Weighted Average Swap Price | $ / MMBTU	2.89
Crude Oil | WTI | January 2019 - December 2019 | Swap
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type		Swap
Average Daily Volumes | bbl		25,059
Weighted Average Swap Price		55.39
Crude Oil | WTI | April 2019 - December 2019 | Swap | Subsequent Event
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type	Swap
Average Daily Volumes | bbl	3,444
Weighted Average Swap Price	56.94
Crude Oil | WTI | January 2020 - December 2020 | Swap | Subsequent Event
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type	Swap
Average Daily Volumes | bbl	3,746
Weighted Average Swap Price	57.07
Crude Oil | WTI | January 2020 - December 2020 | Collar | Subsequent Event
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type	Collar
Average Daily Volumes | bbl	3,000
Weighted Average Swap Price	55
Weighted Average Put Price	55
Weighted Average Call Price	60.64

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, 2018	Dec. 31, 2017
Oil And Natural Gas Swaps
Liabilities:
Total net asset (liability)	$ 74,923	$ (66,830)
Fair Value on Recurring Basis
Liabilities:
Total net asset (liability)	74,923	(66,830)
Fair Value on Recurring Basis | Level 2
Liabilities:
Total net asset (liability)	74,923	(66,830)
Fair Value on Recurring Basis | Oil And Natural Gas Swaps
Assets:
Oil and natural gas swaps and costless collars	75,473	1,908
Liabilities:
Oil and natural gas swaps and costless collars	(550)	(68,738)
Fair Value on Recurring Basis | Oil And Natural Gas Swaps | Level 2
Assets:
Oil and natural gas swaps and costless collars	75,473	1,908
Liabilities:
Oil and natural gas swaps and costless collars	$ (550)	$ (68,738)

Financial Instruments - Sched_6

Financial Instruments - Schedule of Fair Value of Derivative Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Price Risk Derivatives [Line Items]
Current, Assets	$ 75,473	$ 1,563
Non-current, Assets		345
Current, Liabilities	550	49,957
Non-current, Liabilities		18,781
Oil and Natural Gas Derivatives
Price Risk Derivatives [Line Items]
Current, Assets	75,473	1,563
Non-current, Assets		345
Assets	75,473	1,908
Current, Liabilities	550	49,957
Non-current, Liabilities		18,781
Liabilities	$ 550	$ 68,738

Debt - Summary of Detail Compri

Debt - Summary of Detail Comprising Debt and Related Book Values (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	$ 672,495	$ 702,000
Discount and deferred financing cost	(17,191)	(4,442)
Total debt, net of discount and deferred financing costs	655,304	697,558
Less: current portion of long-term debt	(443)	(24,977)
Long-term debt, net of discount and deferred financing costs	654,861	672,581
4.20% Building Loan - due November 2030
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	10,600
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	390,868
Senior Notes | 7.50% Senior Secured Notes – due May 2022
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	6,060
Senior Notes | 9.75% Senior Notes – due July 2022
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost		102,000
Senior Notes | 9.75% Senior Notes – due February 2018
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost		24,977
Bridge Loans | 11.00% Bridge Loans – due April 2022
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	172,000	172,023
Bank Credit Facility | Bank Credit Facility – due May 2022
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	265,000
Building Loan | 4.20% Building Loan - due November 2030
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost	$ 10,567
LLC Bank Credit Facility | Bank Credit Facility – due February 2019
Debt Instrument [Line Items]
Total debt, before discount and deferred financing cost		$ 403,000

Debt - Summary of Detail Comp_2

Debt - Summary of Detail Comprising Debt and Related Book Values (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Nov. 21, 2017
Debt Instrument [Line Items]
Senior notes, maturity date	Feb. 28, 2019	Feb. 28, 2019
11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%	11.00%
Senior notes, maturity date	Apr. 30, 2022	Apr. 30, 2022
7.50% Senior Secured 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 – due May 2022
Debt Instrument [Line Items]
Senior notes, maturity date	May 10, 2022
4.20% Building Loan - due November 2030
Debt Instrument [Line Items]
Debt instrument interest rate	4.20%
Senior notes, maturity date	Nov. 20, 2030
11.00% Bridge Loans – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%	11.00%
Senior notes, maturity date	Apr. 3, 2022	Apr. 3, 2022
9.75% Senior Notes – due July 2022
Debt Instrument [Line Items]
Debt instrument interest rate	9.75%	9.75%
Senior notes, maturity date	Jul. 5, 2022	Jul. 5, 2022
9.75% Senior Notes – due February 2018
Debt Instrument [Line Items]
Debt instrument interest rate	9.75%	9.75%
Senior notes, maturity date	Feb. 15, 2018	Feb. 15, 2018
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%		11.00%
Senior notes, maturity date	Apr. 30, 2022
Senior Notes | 7.50% Senior Secured Notes – due May 2022
Debt Instrument [Line Items]
Debt instrument interest rate	7.50%
Senior notes, maturity date	May 31, 2022
Senior Notes | 9.75% Senior Notes – due July 2022
Debt Instrument [Line Items]
Debt instrument interest rate	9.75%
Senior notes, maturity date	Jul. 31, 2022
Senior Notes | 9.75% Senior Notes – due February 2018
Debt Instrument [Line Items]
Debt instrument interest rate	9.75%
Senior notes, maturity date	Feb. 28, 2018
Bank Credit Facility | Bank Credit Facility – due May 2022
Debt Instrument [Line Items]
Senior notes, maturity date	May 31, 2022
Building Loan | 4.20% Building Loan - due November 2030
Debt Instrument [Line Items]
Debt instrument interest rate	4.20%
Senior notes, maturity date	Nov. 30, 2030
Bridge Loans
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%
Bridge Loans | 11.00% Bridge Loans – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%
Senior notes, maturity date	Apr. 30, 2022
LLC Bank Credit Facility | Bank Credit Facility – due February 2019
Debt Instrument [Line Items]
Senior notes, maturity date	Feb. 28, 2019

Debt - Additional information (

Debt - Additional information (Details) - USD ($)	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Jan. 22, 2019	Nov. 16, 2018	May 10, 2018	Nov. 21, 2017
Debt Instrument [Line Items]
Senior notes, outstading amount		$ 672,495,000	$ 702,000,000
Payments of debt issuance costs		$ 4,300
Debt instrument redemption, description		The indenture governing the 11.00% Senior Secured Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur additional indebtedness or issue certain preferred shares; (ii) pay dividends and make certain other restricted payments; (iii) create restrictions on the payment of dividends or other distributions to the Company from its restricted subsidiaries; (iv) create liens on certain assets to secure debt; (v) make certain investments; (vi) engage in sales of assets and subsidiary stock; (vii) transfer all or substantially all of its assets or enter into merger or consolidation transactions; and (viii) engage in transactions with affiliates. The 11.00% Senior Secured Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2018.
Debt instrument maturity date		Feb. 28, 2019	Feb. 28, 2019
Bank Credit Facility | Subsequent Event
Debt Instrument [Line Items]
Line of credit outstanding amount				$ 35,000,000
11.00% Bridge Loans – due April 2022
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage		11.00%	11.00%
Debt instrument maturity date		Apr. 3, 2022	Apr. 3, 2022
7.50% Senior Secured Notes – due May 2022
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage		7.50%	7.50%
Senior notes, principal amount						$ 6,100,000
Debt instrument maturity date		May 31, 2022	May 31, 2022
Debt instrument frequency of periodic payment		semi-annually
Debt instrument payment terms		semi-annually each May 31 and November 30.
7.50% Senior Secured Notes – due May 2022 | Maximum
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage		105.625%
7.50% Senior Secured Notes – due May 2022 | Minimum
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage		100.00%
11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage		11.00%	11.00%
Debt instrument maturity date		Apr. 30, 2022	Apr. 30, 2022
Bank Credit Facility – due May 2022
Debt Instrument [Line Items]
Debt instrument maturity date		May 10, 2022
Credit facility, maximum borrowing capacity		$ 600,000,000			$ 850,000,000
Line of credit facility for current liquidity requirement		600,000,000
Bank Credit Facility – due February 2019
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity		$ 600,000,000
Commitment fee percentage		0.50%
Undrawn commitment under credit facility		$ 320,300,000
Letters of credit outstanding amount		14,700,000
Line of credit outstanding amount		265,000,000
Bank Credit Facility – due February 2019 | Letter of Credit
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity		$ 200,000,000
Bank Credit Facility – due February 2019 | Maximum
Debt Instrument [Line Items]
Debt covenant to EBITDAX	100.00%
Bank Credit Facility – due February 2019 | Maximum | London Interbank Offered Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		3.75%
Bank Credit Facility – due February 2019 | Maximum | Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.75%
Bank Credit Facility – due February 2019 | Minimum
Debt Instrument [Line Items]
Debt covenant to EBITDAX	300.00%
Bank Credit Facility – due February 2019 | Minimum | London Interbank Offered Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.75%
Bank Credit Facility – due February 2019 | Minimum | Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
4.20% Building Loan - due November 2030
Debt Instrument [Line Items]
Senior notes, outstading amount		$ 10,600,000
Debt instrument, interest rate, stated percentage		4.20%
Debt instrument maturity date		Nov. 20, 2030
Debt instrument frequency of periodic payment		180 equal monthly installments
Debt instrument, periodic payment		$ 100,000
EBITDA to net interest		2.00%
9.75% Senior Notes – due February 2018
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage		9.75%	9.75%
Debt instrument maturity date		Feb. 15, 2018	Feb. 15, 2018
Debt instrument, repurchase amount		$ 25,000,000
Senior Notes | 9.75% Senior Notes
Debt Instrument [Line Items]
Senior notes, outstading amount		$ 102,000,000
Debt instrument, interest rate, stated percentage		9.75%					9.75%
Senior Notes | 7.50% Senior Secured Notes – due May 2022
Debt Instrument [Line Items]
Senior notes, outstading amount		$ 6,060,000
Debt instrument, interest rate, stated percentage		7.50%
Proceeds from Issuance of senior secured notes in exchange of 11% senior secured notes		$ 137,400,000
Debt instrument maturity date		May 31, 2022
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Senior notes, outstading amount		$ 390,868,000
Debt instrument, interest rate, stated percentage		11.00%					11.00%
Work fees to debt holders		$ 9,300,000
Debt instrument maturity date		Apr. 30, 2022
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022 | Maximum
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage		105.50%
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022 | Minimum
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage		100.00%
Senior Notes | 9.75% Senior Notes – due February 2018
Debt Instrument [Line Items]
Senior notes, outstading amount			$ 24,977,000
Debt instrument, interest rate, stated percentage		9.75%
Debt instrument maturity date		Feb. 28, 2018
Bridge Loans
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage		11.00%
Bridge Loans | 11.00% Bridge Loans – due April 2022
Debt Instrument [Line Items]
Senior notes, outstading amount		$ 172,000,000	$ 172,023,000
Debt instrument, interest rate, stated percentage		11.00%
Debt instrument maturity date		Apr. 30, 2022
Stone Notes | 7.50% Senior Secured Notes – due May 2022
Debt Instrument [Line Items]
Senior notes, outstading amount		$ 81,500,000
Debt instrument, interest rate, stated percentage		7.50%

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
	May 21, 2018	Dec. 31, 2018
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted		0.00%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted		200.00%
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share based compensation grants		139,411
Performance Share Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share based compensation grants		232,891
Share-based compensation grant date fair value		$ 10.4
Share based compensation grants, vesting period		3 years
Options conversion in common stock shares		1
Share-based compensation expense recognized period		2 years 4 months 24 days
Share-based compensation expense unrecognized		$ 9.2
Performance Share Units | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted		0.00%
Performance Share Units | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted		200.00%
Executive Severance Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Termination period		12 months
Compensation expense accrued		$ 0.3
Executive Severance Plan | General and Administrative Expense
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Severance Costs1		$ 7.8
Long Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-Based Compensation authorized to grant		5,415,576
Long Term Incentive Plan | Employees | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share based compensation grants		116,448
Share-based compensation grant date fair value		$ 3.9
Share based compensation grants, vesting period		3 years
Options conversion in common stock shares		1
Share-based compensation expense recognized period		2 years 4 months 24 days
Share-based compensation expense unrecognized		$ 3.3
Long Term Incentive Plan | Non-employee Directors | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share based compensation grants	22,963
Share-based compensation grant date fair value	$ 0.8
Options conversion in common stock shares		1
Share-based compensation expense recognized period		4 months 24 days
Share-based compensation expense unrecognized		$ 0.2
Options conversion percentage in RSUs		60.00%
Options conversion percentage in cash		40.00%
Share-based compensation expense liabilities		$ 0.1
Long Term Incentive Plan | Non-employee Directors | Restricted Stock Units | Share-based Compensation Award, Tranche One
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of RSUs vested and expected to vest		13,778
Long Term Incentive Plan | Non-employee Directors | Restricted Stock Units | Share-based Compensation Award, Tranche Two
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of RSUs vested and expected to vest		9,185
Talos Energy LLC Series B Units | Series A Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of compounded annual returns attained covenant		8.00%
Talos Energy LLC Series B Units | Series C Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Distribution paid		$ 25
Talos Energy LLC Series B Units | Series B Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense recognized period		1 year 8 months 12 days
Share-based compensation expense unrecognized		$ 2.7
Unrecognized compensation expense to be recognized over remainder of requisite service period		$ 0.5
Requisite service period		4 years
Unrecognized compensation expense to be recognized upon recoganization of Series A payout		$ 2.2
New Talos Energy LLC Series B Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense unrecognized		1.2
Unrecognized compensation expense to be recognized over remainder of requisite service period		$ 0.2
Requisite service period		4 years
New Talos Energy LLC Series B Units | New Series B Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share based compensation grants, vesting period		4 years
Distribution paid		$ 102
Percentage of units to be vested covenant		80.00%
New Talos Energy LLC Series B Units | New Series A Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense recognized period		24 days
Unrecognized compensation expense to be recognized upon recoganization of Series A payout		$ 1

Employee Benefits Plans and S_4

Employee Benefits Plans and Share Based Compensation - Schedule of Restricted Stock and Performance Share Units Activity (Details)	12 Months Ended
	Dec. 31, 2018$ / sharesshares
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested restricted stock units and award, granted | shares	139,411
Unvested restricted stock units and award, vested | shares	(53)
Unvested restricted stock units and award, forfeited | shares	(654)
Unvested restricted stock units and award, end of the period | shares	138,704
Unvested weighted average grant date fair value, granted | $ / shares	$ 33.85
Unvested weighted average grant date fair value, vested | $ / shares	32.86
Unvested weighted average grant date fair value, forfeited | $ / shares	32.86
Unvested weighted average grante date fair value, end of the period | $ / shares	$ 33.85
Performance Share Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested restricted stock units and award, granted | shares	232,891
Unvested restricted stock units and award, forfeited | shares	(1,349)
Unvested restricted stock units and award, end of the period | shares	231,542
Unvested weighted average grant date fair value, granted | $ / shares	$ 44.47
Unvested weighted average grant date fair value, forfeited | $ / shares	42.94
Unvested weighted average grante date fair value, end of the period | $ / shares	$ 44.47

Employee Benefits Plans and S_5

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

Employee Benefits Plans and S_6

Employee Benefits Plans and Share Based Compensation - Schedule of Recognized Share Based Compensation Expense, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Total share-based compensation expense	$ 6,509	$ 1,795	$ 2,287
Less: amounts capitalized to oil and gas properties	(3,616)	(920)	(1,204)
Total share-based compensation expense, net	2,893	875	1,083
Talos Energy LLC Series B Units
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Total share-based compensation expense	666	$ 1,795	$ 2,287
New Talos Energy LLC Series B Units
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Total share-based compensation expense	3,752
Restricted Stock Units | Employees
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Total share-based compensation expense	560
Restricted Stock Units | Non-employee Directors
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Total share-based compensation expense	402
Performance Share Units
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Total share-based compensation expense	$ 1,129

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Line Items]
Income taxes receivable, current	$ 10,700,000
Federal statutory rate	21.00%	35.00%	35.00%
Valuation allowance	$ 94,100,000	$ 0
Earliest Tax Year
Income Tax Disclosure [Line Items]
Income tax examination, Year	2015
Latest Tax Year
Income Tax Disclosure [Line Items]
Income tax examination, Year	2017
Mexico Tax Returns
Income Tax Disclosure [Line Items]
Income tax payable	$ 1,300,000
State
Income Tax Disclosure [Line Items]
Estimated deferred tax liability related to acquisition	2,700,000
Operating Loss Carryforwards	307,629,000
Federal
Income Tax Disclosure [Line Items]
Operating Loss Carryforwards	557,895,000
Federal | Section 382 of Internal Revenue Code
Income Tax Disclosure [Line Items]
Operating Loss Carryforwards	$ 538,400,000

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)
Current income tax expense (benefit)
Mexico	$ 1,345
Total current income tax expense (benefit)	1,345
Deferred income tax expense (benefit)
United States	1,064
Mexico	513
Total deferred income tax expense (benefit)	1,577
Total income tax expense (benefit)	$ 2,922

Income Taxes - Summary of Recon

Income Taxes - Summary of Reconciliation of Income Taxes Computed U.S.Federal Statutory Tax Rate To Income Tax Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income tax (benefit) at the federal statutory tax rate	$ 47,137	$ (22,004)	$ (72,830)
Earnings not subject to tax	9,980	$ 22,004	$ 72,830
State income taxes	11,738
Foreign income taxes	1,008
Foreign rate differential	432
Prior year taxes	417
Other adjustments	800
Change in tax status	(35,925)
Change in valuation allowance	(32,665)
Total income tax expense (benefit)	$ 2,922
Effective tax rate	1.30%

Income Taxes - Summary of Signi

Income Taxes - Summary of Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred tax assets:
Federal net operating loss	$ 117,546
Foreign tax loss carryforward	2,303	$ 4,023
State net operating loss	23,542
Asset retirement obligations	95,546
Tax credits	12
Interest	33,867
Other	5,909
Total deferred tax assets	278,725	4,023
Valuation allowance	(94,085)	(4,007)
Total deferred tax assets, net	184,640	16
Deferred tax liabilities
Oil and gas properties	166,879
Hedges	18,246
Prepaid	3,371
Deferred tax liabilities	188,496
Net deferred tax (liability)	$ (3,856)
Net deferred tax asset		$ 16

Income Taxes - Summary of Net O

Income Taxes - Summary of Net Operating Loss and Tax Credit Carryovers (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)
Federal
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 557,895
Federal | Minimum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2034
Federal | Maximum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2038
Foreign
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 8,970
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	2028
State
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 307,629
State | Minimum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2019
State | Maximum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2038

Income Taxes - Summary of Balan

Income Taxes - Summary of Balances In Uncertain Tax Positions (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)
Income Tax Disclosure [Abstract]
Tax positions taken during a prior period	$ 360
Total unrecognized tax benefits, ending balance	$ 360

Earnings Per Share - Additional

Earnings Per Share - Additional Information (Details) - $ / shares	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Line Items]
Warrants, Outstanding	3,500,000								3,500,000
Warrants, exercise price	$ 42.04								$ 42.04
Warrants, Term									4 years
Warrants, maturity date	Feb. 28, 2021								Feb. 28, 2021
Weighted-average basic shares outstanding	54,156,000	54,156,000	44,336,000	31,244,000	31,244,000	31,244,000	31,244,000	31,244,000	46,058,000	31,244,000	26,036,000
Weighted-average diluted shares outstanding	54,159,000	54,164,000	44,336,000	31,244,000	31,244,000	31,244,000	31,244,000	31,244,000	46,061,000	31,244,000	26,036,000
Restricted Stock Units
Earnings Per Share [Line Items]
Number of units outstanding	138,704								138,704
Number of units outstanding	138,704								138,704
Performance Share Units
Earnings Per Share [Line Items]
Number of units outstanding	231,542								231,542
Restricted Stock Units and Performance Share Units
Earnings Per Share [Line Items]
Effect of dilutive weighted average securities									2,819
Weighted-average basic shares outstanding									46,058,216
Weighted-average diluted shares outstanding									46,061,035
Number of weighted-average antidilutive units excluded from the computation of diluted net income per common share									419,639

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	Aug. 31, 2018	Aug. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Nov. 21, 2017
Related Party Transaction [Line Items]
Net of cash acquired			$ (278,409,000)	$ 2,464,000	$ 85,886,000
Proceeds from contributions from affiliates for acquisition and other asset purchases			0	0
Distributions to parent or sponsors			$ 0	$ 0
11.00% Second-Priority Senior Secured Notes – due April 2022
Related Party Transaction [Line Items]
Debt instrument, interest rate, stated percentage			11.00%	11.00%
Bridge Loans
Related Party Transaction [Line Items]
Debt instrument, interest rate, stated percentage			11.00%
Senior Notes | 7.50% Senior Secured Notes due 2022
Related Party Transaction [Line Items]
Debt instrument, interest rate, stated percentage			7.50%			7.50%
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Related Party Transaction [Line Items]
Work fees to debt holders			$ 9,300,000
Debt instrument, interest rate, stated percentage			11.00%			11.00%
Equity Registration Rights Agreement
Related Party Transaction [Line Items]
Fees incurred in conjunction with agreement			$ 1,800,000
Vinson & Elkins L.L.P.
Related Party Transaction [Line Items]
Legal fees incurred			4,400,000	$ 4,000,000	700,000
Legal fees payable			1,100,000	4,000,000	100,000
Apollo and Riverstone Funds
Related Party Transaction [Line Items]
Work fees to debt holders			4,100,000
Apollo and Riverstone Funds | Contributions and Distributions
Related Party Transaction [Line Items]
Capital contribution, gross					93,800,000
Capital contribution, net					91,900,000
Transaction fees related to capital contributions					1,900,000
Apollo and Riverstone Funds | Transaction Fee Agreement
Related Party Transaction [Line Items]
Transaction fees related to capital contributions			$ 0	0	1,900,000
Transaction fee equal to percentage of capital contributions			2.00%
Apollo and Riverstone Funds | Service Fee Agreement | Shareholder Service
Related Party Transaction [Line Items]
Service fee			$ 500,000	$ 500,000	$ 500,000
Apollo and Riverstone Funds | Service Fee Agreement | Shareholder Service | Maximum
Related Party Transaction [Line Items]
Service fee			500,000
Franklin and McKay Noteholders
Related Party Transaction [Line Items]
Work fees to debt holders			3,300,000
Whistler Energy II, LLC
Related Party Transaction [Line Items]
Available cash acquired	$ 37,800,000
Whistler Energy II, LLC | Apollo Funds | Whistler Energy II Holdco, LLC
Related Party Transaction [Line Items]
Business acquisition, date of acquisition agreement		Aug. 31, 2018
Cash acquired		$ 52,600,000
Net of cash acquired		14,800,000
Available cash acquired		$ 37,800,000
Primary fair values of receivables acquired			$ 1,100,000
Stone Energy Corporation
Related Party Transaction [Line Items]
Closing date of merger agreement			May 10, 2018
Work fees to debt holders			$ 9,300,000
Stone Energy Corporation | 11.00% Second-Priority Senior Secured Notes – due April 2022
Related Party Transaction [Line Items]
Debt instrument, interest rate, stated percentage			11.00%
Stone Energy Corporation | Apollo and Riverstone Funds | Transaction Fee Agreement | Shareholder Service
Related Party Transaction [Line Items]
Closing date of merger agreement			May 10, 2018
Stone Energy Corporation | Apollo and Riverstone Funds | Service Fee Agreement | Shareholder Service
Related Party Transaction [Line Items]
Closing date of merger agreement			May 10, 2018

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Thousands		Aug. 02, 2016	Apr. 06, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Capital lease obligations		$ 124,300		$ 93,600
Amount of penalty paid			$ 4,200
Term of probation			3 years
Performance obligations	[1]			$ 133,363
Leases for building, facilities and related equipment expiration dates				2029
General and Administrative Expense
Loss Contingencies [Line Items]
Rent expense				$ 2,900	$ 2,100	$ 2,000
Bank Credit Facility | Letter of Credit
Loss Contingencies [Line Items]
Credit facility				14,700	4,900
Production Sharing Contracts | Mexico
Loss Contingencies [Line Items]
Performance obligations				644,100	$ 287,800
Other Current Liabilities
Loss Contingencies [Line Items]
Capital lease obligations				14,100
Other Long-term Liabilities
Loss Contingencies [Line Items]
Capital lease obligations				$ 79,500
Seven-Year Lease Agreement
Loss Contingencies [Line Items]
Lease agreement term		7 years
Annual fixed demand charge paid		$ 49,000
Anual fixed demand charge to be paid thereafter		45,000
Potential quarterly incentive payment paid		500
Potential quarterly incentive payment to be paid thereafter		$ 800
[1]	Excludes the capital lease for the HP-I floating production facility in the Phoenix Field discussed above.

Commitments and Contingencies_2

Commitments and Contingencies - Schedule of Future Minimum Lease Commitments (Details) - USD ($)	Dec. 31, 2018	Aug. 31, 2016
Leases [Abstract]
2019	$ 45,000,000
2020	45,000,000
2021	45,000,000
2022	45,000,000
2023	18,750,000
Total minimum lease payments	198,750,000
Less amount represented lease operating expenses	(51,864,000)
Less amount represented interest	(53,218,000)
Present value of minimum lease payments	93,668,000
Less current maturities of capital lease obligations	(14,127,000)
Long-term capital lease obligations	$ 79,541,000	$ 124,300

Commitments and Contingencies_3

Commitments and Contingencies - Summary of Total Minimum Commitments Associated With Long-Term Non-cancelable Operating Lease (Details) $ in Thousands	Dec. 31, 2018USD ($)
Contractual Obligation [Line Items]
2019	$ 54,390	[1]
2020	35,513	[1]
2021	11,937	[1]
2022	4,298	[1]
Thereafter	27,225	[1]
Total	133,363	[1]
Vessel Commitments
Contractual Obligation [Line Items]
2019	35,206	[2]
Total	35,206	[2]
Committed Purchase Orders
Contractual Obligation [Line Items]
2019	15,562	[3]
2020	11,921	[3]
2021	7,921	[3]
Total	35,404	[3]
Operating Lease Obligations
Contractual Obligation [Line Items]
2019	3,622	[4]
2020	4,315	[4]
2021	4,016	[4]
2022	4,298	[4]
Thereafter	27,225	[4]
Total	43,476	[4]
Mexico | Minimum Work Program
Contractual Obligation [Line Items]
2020	19,277
Total	$ 19,277
[1]	Excludes the capital lease for the HP-I floating production facility in the Phoenix Field discussed above.
[2]	Includes vessel commitments the Company will utilize for certain deep water well intervention and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.
[3]	Includes committed purchase orders to execute planned future drilling and completion activities as well as seismic use agreements the Company entered into in connection with the Stone Combination.
[4]	Amounts include long-term lease payments for office space.

Condensed Consolidating Finan_3

Condensed Consolidating Financial Information - Additional Information (Details)	12 Months Ended
	Dec. 31, 2018	May 10, 2018
Percentage of equity interest	100.00%
11.00% Second-Priority Senior Secured Notes
Debt instrument interest rate		11.00%

Condensed Consolidating Finan_4

Condensed Consolidating Financial Information - Summary of Consolidating Financial Position (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 139,914	$ 32,191
Restricted cash	1,248	1,242
Accounts receivable
Trade, net	103,025	62,871
Joint interest, net	20,244	13,613
Other	19,686	12,486
Assets from price risk management activities	75,473	1,563
Prepaid assets	38,911	17,931
Income tax receivable	10,701
Inventory		840
Other current assets	7,644	2,148
Total current assets	416,846	144,885
Property and equipment:
Proved properties	3,629,430	2,440,811
Unproved properties, not subject to amortization	108,209	72,002
Other property and equipment	33,191	8,857
Total property and equipment	3,770,830	2,521,670
Accumulated depreciation, depletion and amortization	(1,719,609)	(1,430,890)
Total property and equipment, net	2,051,221	1,090,780
Other long-term assets:
Assets from price risk management activities		345
Other well equipment inventory	9,224	2,577
Other assets	2,695	706
Total assets	2,479,986	1,239,293
Current liabilities:
Accounts payable	51,019	72,681
Accrued liabilities	188,650	87,973
Accrued royalties	38,520	24,208
Current portion of long-term debt	443	24,977
Current portion of asset retirement obligations	68,965	39,741
Liabilities from price risk management activities	550	49,957
Accrued interest payable	10,200	8,742
Other current liabilities	22,071	15,188
Total current liabilities	380,418	323,467
Long-term debt, net of discount and deferred financing costs	654,861	672,581
Asset retirement obligations	313,852	174,992
Liabilities from price risk management activities		18,781
Other long-term liabilities	123,359	103,559
Total liabilities	1,472,490	1,293,380
Commitments and Contingencies
Stockholders' equity (deficit)	1,007,496	(54,087)	$ 6,986	$ 120,895
Total liabilities and stockholders' equity	2,479,986	1,239,293
Parent
Other long-term assets:
Investments in subsidiaries	1,011,359	(54,087)
Total assets	1,011,359	(54,087)
Current liabilities:
Accounts payable	144
Total current liabilities	144
Other long-term liabilities	3,719
Total liabilities	3,863
Commitments and Contingencies
Stockholders' equity (deficit)	1,007,496	(54,087)
Total liabilities and stockholders' equity	1,011,359	(54,087)
Subsidiary Issuer
Current assets:
Cash and cash equivalents	13,541	22,315
Accounts receivable
Other	3,100	938
Assets from price risk management activities	75,473	1,406
Prepaid assets	1,225
Total current assets	93,339	24,659
Property and equipment:
Other property and equipment	20,670	7,266
Total property and equipment	20,670	7,266
Accumulated depreciation, depletion and amortization	(8,310)	(6,355)
Total property and equipment, net	12,360	911
Other long-term assets:
Assets from price risk management activities		345
Investments in subsidiaries	1,560,922	697,663
Other assets	364	364
Total assets	1,666,985	723,942
Current liabilities:
Accounts payable	1,242	1,124
Accrued liabilities	4,995	6,516
Current portion of long-term debt		24,977
Liabilities from price risk management activities	550	46,580
Accrued interest payable	10,162	8,742
Total current liabilities	16,949	87,939
Long-term debt, net of discount and deferred financing costs	638,677	672,581
Liabilities from price risk management activities		17,509
Total liabilities	655,626	778,029
Commitments and Contingencies
Stockholders' equity (deficit)	1,011,359	(54,087)
Total liabilities and stockholders' equity	1,666,985	723,942
Guarantors
Current assets:
Cash and cash equivalents	100,801	7,806
Restricted cash	1,248	1,242
Accounts receivable
Trade, net	103,025	62,871
Joint interest, net	15,870	11,659
Other	9,566	5,863
Assets from price risk management activities		157
Prepaid assets	37,639	17,919
Income tax receivable	10,701
Inventory		840
Other current assets	7,644	2,148
Total current assets	286,494	110,505
Property and equipment:
Proved properties	3,629,430	2,440,811
Unproved properties, not subject to amortization	63,104	41,259
Other property and equipment	12,440	1,580
Total property and equipment	3,704,974	2,483,650
Accumulated depreciation, depletion and amortization	(1,711,288)	(1,424,527)
Total property and equipment, net	1,993,686	1,059,123
Other long-term assets:
Other well equipment inventory	9,224	2,577
Other assets	2,258	326
Total assets	2,291,662	1,172,531
Current liabilities:
Accounts payable	42,736	70,458
Accrued liabilities	159,491	80,464
Accrued royalties	38,520	24,208
Current portion of long-term debt	443
Current portion of asset retirement obligations	68,965	39,741
Liabilities from price risk management activities		3,377
Accrued interest payable	38
Other current liabilities	22,071	15,188
Total current liabilities	332,264	233,436
Long-term debt, net of discount and deferred financing costs	16,184
Asset retirement obligations	313,852	174,992
Liabilities from price risk management activities		1,272
Other long-term liabilities	119,432	103,559
Total liabilities	781,732	513,259
Commitments and Contingencies
Stockholders' equity (deficit)	1,509,930	659,272
Total liabilities and stockholders' equity	2,291,662	1,172,531
Non-Guarantors
Current assets:
Cash and cash equivalents	25,572	2,070
Accounts receivable
Joint interest, net	4,374	1,954
Other	7,020	5,685
Prepaid assets	47	12
Total current assets	37,013	9,721
Property and equipment:
Unproved properties, not subject to amortization	45,105	30,743
Other property and equipment	81	11
Total property and equipment	45,186	30,754
Accumulated depreciation, depletion and amortization	(11)	(8)
Total property and equipment, net	45,175	30,746
Other long-term assets:
Other assets	73	16
Total assets	82,261	40,483
Current liabilities:
Accounts payable	6,897	1,099
Accrued liabilities	24,164	993
Total current liabilities	31,061	2,092
Other long-term liabilities	208
Total liabilities	31,269	2,092
Commitments and Contingencies
Stockholders' equity (deficit)	50,992	38,391
Total liabilities and stockholders' equity	82,261	40,483
Elimination
Other long-term assets:
Investments in subsidiaries	(2,572,281)	(643,576)
Total assets	(2,572,281)	(643,576)
Current liabilities:
Commitments and Contingencies
Stockholders' equity (deficit)	(2,572,281)	(643,576)
Total liabilities and stockholders' equity	$ (2,572,281)	$ (643,576)

Condensed Consolidating Finan_5

Condensed Consolidating Financial Information - Summary of Consolidating Results Of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Revenues:
Total revenue	$ 258,664	$ 282,868	$ 203,906	$ 145,850	$ 115,616	$ 99,962	$ 95,426	$ 101,824	$ 891,288		$ 412,828		$ 258,754
Operating expenses:
Workover and maintenance expense									64,961		32,825		24,810
Depreciation, depletion and amortization									288,719		157,352		124,689
Accretion expense									35,344		19,295		21,829
General and administrative expense									85,816		36,673		28,686
Total operating expenses									638,159		367,528		339,433
Operating income (loss)	73,973	91,361	39,211	48,584	18,370	13,329	6,314	7,287	253,129		45,300		(80,679)
Interest expense									(90,114)		(80,934)		(70,415)
Price risk management activities income (expense)	256,917	(53,330)	(91,176)	(51,976)	(84,365)	(28,086)	38,995	45,893	60,435	[1]	(27,563)	[1]	(57,398)	[1]
Other income									1,012		329		405
Income tax expense									(2,922)
Net income (loss)	$ 306,286	$ 13,109	$ (74,912)	$ (22,943)	$ (85,760)	$ (36,177)	$ 24,607	$ 34,462	221,540		(62,868)		(208,087)
Oil and Gas Properties
Operating expenses:
Direct lease operating expense									145,988		109,180		124,360
Insurance									15,342		10,743		13,101
Production taxes									1,989		1,460		1,958
Total lease operating expense									163,319		121,383		139,419
Parent
Operating expenses:
General and administrative expense									142
Total operating expenses									142
Operating income (loss)									(142)
Income tax expense									(1,065)
Equity earnings (losses) from subsidiaries									222,747		(62,868)		(208,087)
Net income (loss)									221,540		(62,868)		(208,087)
Subsidiary Issuer
Operating expenses:
Depreciation, depletion and amortization									1,955		1,401		1,553
General and administrative expense									43,841		21,882		13,204
Total operating expenses									45,796		23,283		14,757
Operating income (loss)									(45,796)		(23,283)		(14,757)
Interest expense									(58,172)		(48,236)		(47,291)
Price risk management activities income (expense)									50,025		(22,998)		(57,398)
Other income									(1,563)		600
Equity earnings (losses) from subsidiaries									278,253		31,049		(88,641)
Net income (loss)									222,747		(62,868)		(208,087)
Guarantors
Revenues:
Total revenue									891,288		412,828		258,754
Operating expenses:
Workover and maintenance expense									64,961		32,825		24,810
Depreciation, depletion and amortization									286,760		155,947		123,132
Accretion expense									35,344		19,295		21,829
General and administrative expense									40,035		14,172		15,044
Total operating expenses									590,419		343,622		324,234
Operating income (loss)									300,869		69,206		(65,480)
Interest expense									(30,255)		(30,252)		(19,680)
Price risk management activities income (expense)									10,410		(4,565)
Other income									874		(333)		430
Income tax expense									(360)
Net income (loss)									281,538		34,056		(84,730)
Guarantors | Oil and Gas Properties
Operating expenses:
Direct lease operating expense									145,988		109,180		124,360
Insurance									15,342		10,743		13,101
Production taxes									1,989		1,460		1,958
Total lease operating expense									163,319		121,383		139,419
Non-Guarantors
Operating expenses:
Depreciation, depletion and amortization									4		4		4
General and administrative expense									1,798		619		438
Total operating expenses									1,802		623		442
Operating income (loss)									(1,802)		(623)		(442)
Interest expense									(1,687)		(2,446)		(3,444)
Other income									1,701		62		(25)
Income tax expense									(1,497)
Net income (loss)									(3,285)		(3,007)		(3,911)
Elimination
Operating expenses:
Equity earnings (losses) from subsidiaries									(501,000)		31,819		296,728
Net income (loss)									(501,000)		31,819		296,728
Oil Revenue
Revenues:
Revenue									781,815		344,781		197,583
Oil Revenue | Guarantors
Revenues:
Revenue									781,815		344,781		197,583
Natural Gas Revenue
Revenues:
Revenue									73,610		48,886		42,705
Natural Gas Revenue | Guarantors
Revenues:
Revenue									73,610		48,886		42,705
NGL Revenue
Revenues:
Revenue									35,863		16,658		9,532
NGL Revenue | Guarantors
Revenues:
Revenue									$ 35,863		16,658		9,532
Other
Revenues:
Revenue											2,503		8,934
Other | Guarantors
Revenues:
Revenue											$ 2,503		$ 8,934
[1]	The Company paid cash settlements of $111.1 million, and received cash settlements of $23.8 million and $172.2 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Condensed Consolidating Finan_6

Condensed Consolidating Financial Information - Summary of Consolidating Cash Flows (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$ 263,445,000	$ 176,053,000	$ 116,123,000
Cash flows from investing activities:
Exploration, development and other capital expenditures	(240,914,000)	(155,177,000)	(113,032,000)
Cash paid for acquisitions, net of cash acquired	278,409,000	(2,464,000)	(85,886,000)
Net cash provided by (used in) investing activities	37,495,000	(157,641,000)	(198,918,000)
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt	(25,257,000)	(1,000,000)
Redemption of 2018 Senior Notes		(1,000,000)
Proceeds from Bank Credit Facility	319,000,000	10,000,000	15,000,000
Repayment of Bank Credit Facility	(54,000,000)	(15,000,000)	(10,000,000)
Deferred financing costs	(17,002,000)
Payment of capital lease	(12,952,000)	(12,412,000)	(5,267,000)
Distributions to Subsidiary Issuer	0	0
Contributions from Sponsors			93,750,000
Distributions to Sponsors			(1,859,000)
Net cash provided by (used in) financing activities	(193,211,000)	(18,412,000)	91,624,000
Net increase (decrease) in cash, cash equivalents and restricted cash	107,729,000		8,829,000
Cash, cash equivalents and restricted cash:
Balance, beginning of period	33,433,000	33,433,000	24,604,000
Balance, end of period	141,162,000	33,433,000	33,433,000
Parent
Cash flows from investing activities:
Investments in subsidiaries			(91,891,000)
Net cash provided by (used in) investing activities			(91,891,000)
Cash flows from financing activities:
Contributions from Sponsors			93,750,000
Distributions to Sponsors			(1,859,000)
Net cash provided by (used in) financing activities			91,891,000
Subsidiary Issuer
Cash flows from operating activities:
Net cash provided by (used in) operating activities	(193,088,000)	(30,245,000)	124,698,000
Cash flows from investing activities:
Exploration, development and other capital expenditures	(13,404,000)	(260,000)	(301,000)
Investments in subsidiaries	(1,316,588,000)	(577,055,000)	(524,192,000)
Distributions from subsidiaries	1,694,460,000	611,526,000	411,074,000
Net cash provided by (used in) investing activities	364,468,000	34,211,000	(113,419,000)
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt	(25,152,000)
Redemption of 2018 Senior Notes		(1,000,000)
Proceeds from Bank Credit Facility	319,000,000	10,000,000	15,000,000
Repayment of Bank Credit Facility	(54,000,000)	(15,000,000)	(10,000,000)
Deferred financing costs	(17,002,000)
Net cash provided by (used in) financing activities	(180,154,000)	(6,000,000)	5,000,000
Net increase (decrease) in cash, cash equivalents and restricted cash	(8,774,000)	(2,034,000)	16,279,000
Cash, cash equivalents and restricted cash:
Balance, beginning of period	22,315,000	24,349,000	8,070,000
Balance, end of period	13,541,000	22,315,000	24,349,000
Guarantors
Cash flows from operating activities:
Net cash provided by (used in) operating activities	442,890,000	204,419,000	(2,806,000)
Cash flows from investing activities:
Exploration, development and other capital expenditures	(227,228,000)	(132,317,000)	(106,647,000)
Cash paid for acquisitions, net of cash acquired	278,409,000	(2,464,000)	(85,886,000)
Distributions from subsidiaries	9,000	6,041,000
Net cash provided by (used in) investing activities	51,190,000	(128,740,000)	(192,533,000)
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt	(105,000)
Payment of capital lease	(12,952,000)	(12,412,000)	(5,267,000)
Capital contributions	1,301,876,000	550,555,000	599,630,000
Distributions to Subsidiary Issuer	(1,689,898,000)	(611,526,000)	(408,050,000)
Net cash provided by (used in) financing activities	(401,079,000)	(73,383,000)	186,313,000
Net increase (decrease) in cash, cash equivalents and restricted cash	93,001,000	2,296,000	(9,026,000)
Cash, cash equivalents and restricted cash:
Balance, beginning of period	9,048,000	6,752,000	15,778,000
Balance, end of period	102,049,000	9,048,000	6,752,000
Non-Guarantors
Cash flows from operating activities:
Net cash provided by (used in) operating activities	13,643,000	1,879,000	(5,769,000)
Cash flows from investing activities:
Exploration, development and other capital expenditures	(282,000)	(22,600,000)	(6,084,000)
Net cash provided by (used in) investing activities	(282,000)	(22,600,000)	(6,084,000)
Cash flows from financing activities:
Capital contributions	14,712,000	26,500,000	16,453,000
Distributions to Subsidiary Issuer	(4,571,000)	(6,041,000)	(3,024,000)
Net cash provided by (used in) financing activities	10,141,000	20,459,000	13,429,000
Net increase (decrease) in cash, cash equivalents and restricted cash	23,502,000	(262,000)	1,576,000
Cash, cash equivalents and restricted cash:
Balance, beginning of period	2,070,000	2,332,000	756,000
Balance, end of period	25,572,000	2,070,000	2,332,000
Elimination
Cash flows from investing activities:
Investments in subsidiaries	1,316,588,000	577,055,000	616,083,000
Distributions from subsidiaries	(1,694,469,000)	(617,567,000)	(411,074,000)
Net cash provided by (used in) investing activities	(377,881,000)	(40,512,000)	205,009,000
Cash flows from financing activities:
Capital contributions	(1,316,588,000)	(577,055,000)	(616,083,000)
Distributions to Subsidiary Issuer	1,694,469,000	617,567,000	411,074,000
Net cash provided by (used in) financing activities	377,881,000	40,512,000	(205,009,000)
LLC Bank Credit Facility
Cash flows from financing activities:
Repayment of Bank Credit Facility	(403,000,000)	$ (15,000,000)	$ (10,000,000)
LLC Bank Credit Facility | Subsidiary Issuer
Cash flows from financing activities:
Repayment of Bank Credit Facility	$ (403,000,000)

Selected Quarterly Financial _3

Selected Quarterly Financial Data - Schedule Of Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 258,664	$ 282,868	$ 203,906	$ 145,850	$ 115,616	$ 99,962	$ 95,426	$ 101,824	$ 891,288		$ 412,828		$ 258,754
Operating income	73,973	91,361	39,211	48,584	18,370	13,329	6,314	7,287	253,129		45,300		(80,679)
Price risk management activities income (expense)	256,917	(53,330)	(91,176)	(51,976)	(84,365)	(28,086)	38,995	45,893	60,435	[1]	(27,563)	[1]	(57,398)	[1]
Net income (loss)	$ 306,286	$ 13,109	$ (74,912)	$ (22,943)	$ (85,760)	$ (36,177)	$ 24,607	$ 34,462	$ 221,540		$ (62,868)		$ (208,087)
Net income (loss) per common share:
Basic	$ 5.66	$ 0.24	$ (1.69)	$ (0.73)	$ (2.74)	$ (1.16)	$ 0.79	$ 1.10	$ 4.81		$ (2.01)		$ (7.99)
Diluted	$ 5.66	$ 0.24	$ (1.69)	$ (0.73)	$ (2.74)	$ (1.16)	$ 0.79	$ 1.10	$ 4.81		$ (2.01)		$ (7.99)
Weighted average common shares outstanding:
Basic	54,156	54,156	44,336	31,244	31,244	31,244	31,244	31,244	46,058		31,244		26,036
Diluted	54,159	54,164	44,336	31,244	31,244	31,244	31,244	31,244	46,061		31,244		26,036
[1]	The Company paid cash settlements of $111.1 million, and received cash settlements of $23.8 million and $172.2 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Supplemental Oil and Gas Disc_3

Supplemental Oil and Gas Disclosures - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization (Details) $ in Thousands	Dec. 31, 2018USD ($)$ / MBoe	Dec. 31, 2017USD ($)$ / MBoe
Extractive Industries [Abstract]
Proved properties	$ 3,629,430	$ 2,440,811
Unproved oil and gas properties, not subject to amortization	108,209	72,002
Total oil and gas properties	3,737,639	2,512,813
Less: Accumulated depletion and amortization	(1,709,614)	(1,423,829)
Net capitalized costs	$ 2,028,025	$ 1,088,984
Depletion and amortization rate per Boe | $ / MBoe	17.07	14.85

Supplemental Oil and Gas Disc_4

Supplemental Oil and Gas Disclosures - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)MMBoe	Dec. 31, 2017USD ($)MMBoe	Dec. 31, 2016USD ($)MMBoe
Reserve Quantities [Line Items]
Oil and gas asset retirement obligations | $	$ 382,817	$ 214,733	$ 220,049
Percentage of proved oil, natural gas and NGL reserves attributable to all of oil and natural gas properties	100.00%	100.00%	100.00%
Estimated proved reserves	51.1
Purchases of estimated proved reserves	62.8		13.9
Estimated proved reserves from extensions and discoveries	5.6	12.5	26.6
Decrease of production	16.7	10.5
Revision of previous estimates		5.1
Prescribed rate of discounted future net cash flows	10.00%
Stone Energy Corporation
Reserve Quantities [Line Items]
Purchases of estimated proved reserves	59.3
Whistler Energy II, LLC
Reserve Quantities [Line Items]
Purchases of estimated proved reserves	3.5

Supplemental Oil and Gas Disc_5

Supplemental Oil and Gas Disclosures - Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property acquisition costs:
Proved properties	$ 850,515	$ 1,108	$ 77,906
Unproved properties, not subject to amortization	65,063	5,778	15,919
Total property acquisition costs	915,578	6,886	93,825
Exploration costs	93,780	82,887	27,807
Development costs	215,467	114,846	195,869
Total costs incurred	$ 1,224,825	$ 204,619	$ 317,501

Supplemental Oil and Gas Disc_6

Supplemental Oil and Gas Disclosures - Schedule of Estimated Proved Reserves at Net Ownership Interest (Details)	12 Months Ended
	Dec. 31, 2018MBoeMMBoeMBblsMMcf	Dec. 31, 2017MBoeMMBoeMBblsMMcf	Dec. 31, 2016MBoeMMBoeMBblsMMcf
Reserve Quantities [Line Items]
Revision of previous estimates | MMBoe		(5.1)
Production | MMBoe	(16.7)	(10.5)
Purchases of reserves | MMBoe	62.8		13.9
Extensions and discoveries | MMBoe	5.6	12.5	26.6
Total proved reserves, ending balance | MMBoe	51.1
Oil (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	72,804	72,366	46,354
Revision of previous estimates	2,595	(2,673)	(1,712)
Production	(11,771)	(7,048)	(5,126)
Purchases of reserves	44,788		11,128
Extensions and discoveries	4,123	10,159	21,722
Total proved reserves, ending balance	112,539	72,804	72,366
Total proved developed reserves	85,530	37,460	45,753
Total proved undeveloped reserves	27,009	35,344	26,613
Gas (MMcf)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MMcf	127,656	150,604	129,224
Revision of previous estimates | MMcf	(37,933)	(15,860)	10,024
Production | MMcf	(22,771)	(16,308)	(19,001)
Purchases of reserves | MMcf	95,661		11,208
Extensions and discoveries | MMcf	8,411	9,220	19,149
Total proved reserves, ending balance | MMcf	171,024	127,656	150,604
Total proved developed reserves | MMcf	131,364	77,577	96,122
Total proved undeveloped reserves | MMcf	39,660	50,079	54,482
NGL (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	6,547	6,236	4,581
Revision of previous estimates	3,187	250	(352)
Production	(1,176)	(706)	(603)
Purchases of reserves	2,074		950
Extensions and discoveries	64	767	1,660
Total proved reserves, ending balance	10,696	6,547	6,236
Total proved developed reserves	8,104	3,315	4,032
Total proved undeveloped reserves	2,592	3,232	2,204
Oil Equivalent (MBoe)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MBoe	100,625	103,702	72,473
Revision of previous estimates | MBoe	(539)	(5,067)	(394)
Production | MBoe	(16,742)	(10,472)	(8,896)
Purchases of reserves | MBoe	62,806		13,946
Extensions and discoveries | MBoe	5,589	12,462	26,573
Total proved reserves, ending balance | MBoe	151,739	100,625	103,702
Total proved developed reserves | MBoe	115,528	53,704	65,805
Total proved undeveloped reserves | MBoe	36,211	46,921	37,897

Supplemental Oil and Gas Disc_7

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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Future cash inflows	$ 8,654,631	$ 4,308,863	$ 3,390,612
Future costs:
Production	(1,740,850)	(815,509)	(775,354)
Development and abandonment	(1,349,005)	(823,164)	(664,254)
Future net cash flows before income taxes	5,564,776	2,670,190	1,951,004
Future income tax expense	(862,473)	0	0
Future net cash flows after income taxes	4,702,303	2,670,190	1,951,004
Discount at 10% annual rate	(1,362,057)	(862,521)	(614,969)
Standardized measure of discounted future net cash flows	$ 3,340,246	$ 1,807,669	$ 1,336,035	$ 602,981

Supplemental Oil and Gas Disc_8

Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Base Prices Used in Determining Standardized Measure (Details)	12 Months Ended
	Dec. 31, 2018$ / bbl$ / Mcf	Dec. 31, 2017$ / bbl$ / Mcf	Dec. 31, 2016$ / bbl$ / Mcf
Oil
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Base prices	69.42	51.36	40.02
Natural Gas
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Base prices | $ / Mcf	3.08	3.20	2.66
NGL
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Base prices	29.50	24.64	14.96

Supplemental Oil and Gas Disc_9

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Extractive Industries [Abstract]
Standardized measure, beginning of year	$ 1,807,669	$ 1,336,035	$ 602,981
Changes during the year:
Sales and transfers of oil, net gas and NGLs produced during the period	(727,969)	(288,942)	(114,625)
Net change in prices and production costs	1,578,330	555,100	80,174
Changes in estimated future development costs	32,328	(156,282)	2,292
Previously estimated development costs incurred	45,937	146,687	108,484
Accretion of discount	180,767	133,603	60,298
Net change in income taxes	(585,017)
Purchases of reserves	943,519		222,581
Extensions and discoveries	148,068	328,565	479,833
Net change due to revision in quantity estimates	190,853	(113,629)	(5,685)
Changes in production rates (timing) and other	(274,239)	(133,468)	(100,298)
Total	1,532,577	471,634	733,054
Standardized measure, end of year	$ 3,340,246	$ 1,807,669	$ 1,336,035

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - Subsequent Event - Gunflint Acquisition $ in Millions	Jan. 11, 2019USD ($)
Subsequent Event [Line Items]
Percentage of voting interest acquired	9.60%
Purchase price	$ 29.6