Talos Production S-4 14 Sep 18 Registration of securities issued in business combination transactions Financial data

Document and Entity Information

Document and Entity Information	6 Months Ended
	Jun. 30, 2018
Document And Entity Information [Abstract]
Document Type	S4
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Trading Symbol	TALO
Entity Registrant Name	Talos Energy Inc.
Entity Central Index Key	1,724,965
Entity Filer Category	Accelerated Filer

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 78,860	$ 32,191	$ 32,231
Restricted cash	1,244	1,242	1,202
Accounts receivable, net
Trade, net	100,824	62,871	52,764
Joint interest, net	8,394	13,613	14,673
Other	7,091	12,486	12,400
Assets from price risk management activities	499	1,563	20,176
Prepaid assets	51,698	17,931	18,420
Inventory		840	1,093
Income tax receivable	16,212
Other current assets	3,910	2,148	2,492
Total current assets	268,732	144,885	155,451
Property and equipment:
Proved properties	3,412,875	2,440,811	2,235,835
Unproved properties, not subject to amortization	103,836	72,002	72,360
Other property and equipment	28,884	8,857	8,531
Total property and equipment	3,545,595	2,521,670	2,316,726
Accumulated depreciation, depletion and amortization	(1,547,656)	(1,430,890)	(1,273,538)
Total property and equipment, net	1,997,939	1,090,780	1,043,188
Other long-term assets:
Assets from price risk management activities	234	345	293
Other well equipment inventory	9,021	2,577	12,744
Other assets	8,143	706	622
Total assets	2,284,069	1,239,293	1,212,298
Current liabilities:
Accounts payable	38,731	72,681	31,230
Accrued liabilities	155,902	87,973	49,916
Accrued royalties	28,508	24,208	23,293
Current portion of long-term debt	434	24,977
Current portion of asset retirement obligations	94,334	39,741	33,556
Liabilities from price risk management activities	154,722	49,957	27,147
Accrued interest payable	7,454	8,742	11,376
Other current liabilities	15,541	15,188	14,666
Total current liabilities	495,626	323,467	191,184
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs	627,968	672,581	701,175
Asset retirement obligations	320,044	174,992	186,493
Liabilities from price risk management activities	31,766	18,781	8,755
Other long-term liabilities	122,820	103,559	117,705
Total liabilities	1,598,224	1,293,380	1,205,312
Commitments and contingencies
Equity:
Preferred stock, Value
Common stock, Value	542	312	312
Additional paid-in capital	1,323,604	489,870	489,870
Accumulated deficit	(638,301)	(544,269)	(483,196)
Total stockholders' equity (deficit)	685,845	(54,087)	6,986
Total liabilities and equity	$ 2,284,069	$ 1,239,293	$ 1,212,298

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01	$ 0.01
Preferred stock, shares authorized	30,000,000	30,000,000	30,000,000
Preferred stock, shares issued	0	0	0
Preferred stock, shares outstanding	0	0	0
Common stock, par value	$ 0.01	$ 0.01	$ 0.01
Common stock, shares authorized	270,000,000	270,000,000	270,000,000
Common stock, shares issued	54,155,768	31,244,085	31,244,085
Common stock, shares outstanding	54,155,768	31,244,085	31,244,085

CONSOLIDATED STATEMENT OF OPERA

CONSOLIDATED STATEMENT OF OPERATIONS - USD ($) $ in Thousands	3 Months Ended				6 Months Ended				12 Months Ended
	Jun. 30, 2018		Jun. 30, 2017		Jun. 30, 2018		Jun. 30, 2017		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Revenues:
Total revenue	$ 203,906		$ 95,426		$ 349,756		$ 197,250		$ 412,828		$ 258,754		$ 315,606
Operating expenses:
Direct lease operating expense	34,060		28,871		58,975		56,735		109,180		124,360		171,095
Insurance	4,259		2,688		6,934		5,409		10,743		13,101		17,965
Production taxes	564		380		955		645		1,460		1,958		3,311
Total lease operating expense	38,883		31,939		66,864		62,789		121,383		139,419		192,371
Workover and maintenance expense	17,714		8,225		24,619		17,047		32,825		24,810		29,752
Depreciation, depletion and amortization	67,726		36,157		116,766		76,088		157,352		124,689		212,689
Accretion expense	9,492		5,321		14,252		10,509		19,295		21,829		19,395
General and administrative expense	30,880		7,470		39,460		17,216		36,673		28,686		35,662
Total operating expenses	164,695		89,112		261,961		183,649		367,528		339,433		1,093,257
Operating income (loss)	39,211		6,314		87,795		13,601		45,300		(80,679)		(777,651)
Insurance	4,259		2,688		6,934		5,409		10,743		13,101		17,965
Production taxes	564		380		955		645		1,460		1,958		3,311
Write-down of oil and natural gas properties under ceiling test	0		0		0		0						603,388
Interest expense	(21,678)		(20,805)		(41,420)		(39,577)		(80,934)		(70,415)		(51,544)
Price risk management activities income (expense)	(91,176)	[1]	38,995	[1]	(143,152)	[1]	84,888	[1]	(27,563)	[2]	(57,398)	[2]	182,196	[2]
Other income (expense)	(1,269)		103		(1,078)		157		329		405		314
Total other income (expense)	(114,123)		18,293		(185,650)		45,468
Income (loss) before income taxes	(74,912)		24,607		(97,855)		59,069
Net income (loss)	$ (74,912)		$ 24,607		$ (97,855)		$ 59,069		$ (62,868)		$ (208,087)		$ (646,685)
Net income (loss) per common share:
Basic	$ (1.69)		$ 0.79		$ (2.59)		$ 1.89		$ (2.01)		$ (7.99)		$ (26.20)
Diluted	$ (1.69)		$ 0.79		$ (2.59)		$ 1.89		$ (2.01)		$ (7.99)		$ (26.20)
Weighted average common shares outstanding:
Basic	44,336,000		31,244,000		37,826,000		31,244,000		31,244		26,036		24,685
Diluted	44,336,000		31,244,000		37,826,000		31,244,000		31,244		26,036		24,685
Oil Revenue
Revenues:
Revenue	$ 180,161		$ 78,719		$ 307,854		$ 162,487		$ 344,781		$ 197,583		$ 244,167
Natural Gas Revenue
Revenues:
Revenue	16,448		12,888		29,171		26,062		48,886		42,705		55,026
NGL Revenue
Revenues:
Revenue	$ 7,297		3,436		$ 12,731		7,069		16,658		9,532		10,523
Other
Revenues:
Revenue			$ 383				$ 1,632		$ 2,503		$ 8,934		$ 5,890
[1]	The Company paid $33.6 million and received $9.2 million in net cash settlements for the three months ended June 30, 2018 and 2017, respectively, and paid $54.1 million and received $13.7 million in net cash settlements for the six months ended June 30, 2018 and 2017, respectively.
[2]	The Company received net cash settlements of $23.8 million, $172.2 million and $181.9 million for the years ended December 31, 2017, 2016 and 2015, respectively.

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - USD ($) $ in Thousands	Total	Talos and Stone	Common Stock	Additional Paid-In Capital	Retained Earnings (Accumulated Deficit)	Retained Earnings (Accumulated Deficit)Talos and Stone
Balance at Dec. 31, 2014	$ 690,502		$ 215	$ 324,576	$ 365,711
Equity based compensation	3,578				3,578
Net loss	(646,685)				(646,685)
Balance at Dec. 31, 2015	120,895		258	398,033	(277,396)
Contributions from Sponsors, net	73,500		43	73,457
Equity based compensation	2,287				2,287
Net loss	(208,087)				(208,087)
Balance at Dec. 31, 2016	6,986		312	489,870	(483,196)
Contributions from Sponsors, net	91,891		54	91,837
Equity based compensation	1,795				1,795
Net loss	(62,868)				(62,868)
Balance at Dec. 31, 2017	(54,087)		312	489,870	(544,269)
Cumulative effect adjustment	(325)				(325)
Sponsor Debt Exchange	102,000		29	101,971
Stone Combination	731,964		201	731,763
Equity based compensation		$ 4,148				$ 4,148
Net loss	(97,855)	$ (97,855)				$ (97,855)
Balance at Jun. 30, 2018	$ 685,845		$ 542	$ 1,323,604	$ (638,301)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended				12 Months Ended
	Jun. 30, 2018		Jun. 30, 2017		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Cash flows from operating activities:
Net income (loss)	$ (97,855)		$ 59,069		$ (62,868)		$ (208,087)		$ (646,685)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion expense	131,018		86,597		176,647		146,518		232,084
Amortization of deferred financing costs and original issue discount	2,607		1,629		2,383		5,996		4,955
Equity based compensation, net of amounts capitalized	1,559		495		875		1,083		1,719
Price risk management activities (income) expense	143,152	[1]	(84,888)	[1]	27,563	[2]	57,398	[2]	(182,196)	[2]
Net cash receipts (payments) on settled derivative instruments	(54,056)		13,668		23,834		172,182		181,927
Settlement of asset retirement obligations	(43,896)		(10,915)		(32,573)		(23,689)		(79,798)
Changes in operating assets and liabilities:
Accounts receivable	19,462		27,814		(9,132)		(20,096)		32,231
Other current assets	(13,576)		1,127		(4,441)		(3,040)		9,244
Accounts payable	(53,126)		10,885		2,409		(68,042)		(77,022)
Other current liabilities	52,543		(16,961)		46,364		51,240		55,659
Other non-current assets and liabilities, net	19,279		(3,257)		4,732		4,442		754
Net cash provided by operating activities	107,111		85,263		176,053		116,123		138,366
Write-down of oil and natural gas properties under ceiling test	0		0						603,388
Impairment					260		218		2,106
Net cash provided by operating activities	107,111		85,263		176,053		116,123		138,366
Cash flows from investing activities:
Exploration, development, and other capital expenditures	(140,968)		(62,535)		(155,177)		(113,032)		(245,716)
Cash paid for acquisitions, net of cash acquired	293,001		(2,244)		(2,464)		(85,886)		(39,423)
Net cash provided by (used in) investing activities	152,033		(64,779)		(157,641)		(198,918)		(285,139)
Cash flows from financing activities:
Proceeds from Bank Credit Facility	294,000		10,000		10,000		15,000		120,000
Repayment of Bank Credit Facility	(54,000)		(15,000)		(15,000)		(10,000)		(30,000)
Deferred financing costs	(17,469)								(269)
Payments of capital lease	(6,958)		(5,870)		(12,412)		(5,267)
Net cash provided by (used in) financing activities	(212,473)		(11,870)		(18,412)		91,624		108,231
Redemption of Senior Notes and other long-term debt	(25,046)		(1,000)		(1,000)
Contributions from Sponsors							93,750		75,000
Distributions to subsidiaries							(1,859)		(1,500)
Net increase (decrease) in cash, cash equivalents and restricted cash	46,671		8,614				8,829		(38,542)
Cash, cash equivalents and restricted cash:
Balance, beginning of period	33,433		33,433		33,433		24,604		63,146
Balance, end of period	80,104		42,047		33,433		33,433		24,604
Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities	38,205		30,712		40,626,000		13,832,000		30,125,000
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized	23,635		25,405		$ 47,994,000		$ 55,254,000		37,247,000
Old Bank Credit Facility
Cash flows from financing activities:
Proceeds from Bank Credit Facility			10,000
Repayment of Bank Credit Facility	$ (403,000)		$ (15,000)
GCER Bank Credit Facility
Cash flows from financing activities:
Repayment of Bank Credit Facility									$ (55,000)
[1]	The Company paid $33.6 million and received $9.2 million in net cash settlements for the three months ended June 30, 2018 and 2017, respectively, and paid $54.1 million and received $13.7 million in net cash settlements for the six months ended June 30, 2018 and 2017, respectively.
[2]	The Company received net cash settlements of $23.8 million, $172.2 million and $181.9 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Formation and Basis of Presenta

Formation and Basis of Presentation	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
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 Gulf of Mexico and in the shallow waters off the coast of Mexico. The Company’s focus in the Gulf of Mexico is the exploration, acquisition, exploitation and development of deep and shallow water assets near existing infrastructure. The shallow waters off the coast of Mexico provide the Company high impact exploration opportunities in an emerging basin. The Company uses its access to an extensive seismic database and its deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. The Company’s management and technical teams have a long history working together and have made significant discoveries in the deep and shallow waters in the Gulf of Mexico and in the shallow waters off the coast of Mexico. 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”), among Stone Energy Corporation (“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, Sailfish Energy Holdings Corporation did not conduct any material activities other than those incident to its formation and the matters contemplated by the Transaction Agreement. Substantially concurrent with the consummation of the transactions, the name of the Company was changed from Sailfish Energy Holdings Corporation to Talos Energy Inc. Pursuant to the Transaction Agreement, a series of transactions occurred on the Closing Date (the “Closing”), including the following: (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) in a series of contributions, entities related to Apollo Management VII, L.P. and Apollo Commodities Management, L.P. with respect to Series I (“Apollo Funds”), and Riverstone Energy Partners V, L.P. (“Riverstone Funds”) 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 the 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. 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. Unless otherwise indicated or the context otherwise requires, references herein to “us,” “we,” “our” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries. Basis of Presentation and Consolidation The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) as applied to interim financial statements and include each subsidiary from the date of inception. Because this is an interim periodic report presented using a condensed format, it does not include all of the annual disclosures required by GAAP. 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 cover periods prior to the Closing Date, reflects the assets, liabilities and operations of Talos Energy LLC prior to the Closing Date and does not reflect the assets, liabilities and operations of Stone prior to the Closing Date. These condensed consolidated financial statements should be read in conjunction with Talos Energy LLC’s audited financial statements and the notes thereto for the year ended December 31, 2017, which are included elsewhere in this prospectus. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the business combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos. All intercompany transactions have been eliminated. All adjustments that are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the interim periods are reflected herein. The results for any interim period are not necessarily indicative of the expected results for the entire year. The Company has evaluated subsequent events through the date the condensed consolidated financial statements were issued. For presentation purposes, as of June 30, 2018, certain balances previously disclosed as “Accounts payable” and “Other current assets” have been reclassified to “Accrued liabilities” and “Prepaid assets”, respectively. The corresponding balances as of December 31, 2017 of $73.5 million and $7.3 million were reclassified to “Accrued liabilities” and “Prepaid assets”, respectively. The balance sheet reclass between “Accounts payable” and “Accrued liabilities” is related to estimates of operating costs incurred but not yet invoiced. 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. During September 2015, the Company expanded its acreage position to include two shallow water exploration blocks off the coast of Mexico and drilled its first well in those blocks in July 2017. The business activities in Mexico, which are currently deemed immaterial, have been combined with the United States and reported as one segment. See additional information in Note 4— Property, Plant and Equipment Recently Adopted Accounting Standards Impact of the Adoption of ASC 606—Revenue from Contracts with Customers 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 does not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Gas Imbalances. Production Handling Fees. Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Boards (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842). Leases	Note 1—Formation and Basis of Presentation Formation and Nature of Business Talos Energy LLC was formed in 2011. Upon formation, Talos Energy Operating Company LLC; Talos Energy Offshore LLC; Talos Energy Operating GP, LLC; Talos Energy Holdings LLC; and Talos Production LLC became wholly-owned subsidiaries of Talos Energy LLC. Talos Production Finance Inc. was formed on January 15, 2013 as a wholly-owned subsidiary of Talos Energy LLC. Unless otherwise indicated or the context otherwise requires, references in this report to “us,” “we,” “our” or the “Company” are to Talos Energy LLC and its wholly-owned subsidiaries. On February 6, 2013, we acquired all of the equity of Energy Resource Technology GOM, LLC (“ERT”) and its subsidiary from Helix Energy Solutions Group, Inc. (“Helix”) for approximately $625.2 million (inclusive of purchase price and working capital adjustments of approximately $15.2 million), and payments for ongoing guarantees from Helix to third-parties. Additionally, the Company agreed to assign Helix an overriding royalty interest in certain properties acquired in the transaction at closing. We refer to this purchase as the “ERT Acquisition.” The ERT Acquisition was effective December 1, 2012 and closed on February 6, 2013. Prior to the closing of the ERT Acquisition, Energy Resource Technology GOM, Inc. and its wholly-owned subsidiary, CKB Petroleum, Inc., were each converted into Delaware limited liability companies, and as a result changed their names to Energy Resource Technology GOM, LLC and CKB Petroleum, LLC, respectively. On February 3, 2012, the Company completed a transaction with funds affiliated with, and controlled by, Apollo Global Management LLC (together with its consolidated subsidiaries, “Apollo”), funds affiliated with, and controlled by, Riverstone Holdings, LLC (together with its affiliates, “Riverstone” and together with Apollo, our “Sponsors”) and members of management pursuant to which the Company received a private equity capital commitment, which may be increased up to $600 million with approval from the Company’s Board of Directors. Prior to the closing of the ERT Acquisition, our Sponsors and members of management had invested an aggregate of approximately $325 million in the Company to fund a portion of the ERT Acquisition as well as to fund other asset purchases. In connection with the ERT Acquisition, the Company also issued $300 million aggregate principal amount of 9.75% Senior Notes due February 15, 2018 (the “2018 Senior Notes”) at a discount of 0.975%, (see Note 6— Debt The Company commenced commercial operations on February 6, 2013. Prior to February 6, 2013, the Company had incurred certain general and administrative expenses associated with the start-up of its operations. We are a technically driven independent exploration and production company with operations in the Gulf of Mexico and in the shallow waters off the coast of Mexico. Our focus in the Gulf of Mexico is the exploration, acquisition and development of deep and shallow water assets near existing infrastructure. The shallow waters off the coast of Mexico provide us high impact exploration opportunities in an emerging basin. We use our access to an extensive seismic database and our deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. Our management and technical teams have a long history working together and have made significant discoveries in the deep and shallow waters in the Gulf of Mexico and in the shallow waters off the coast of Mexico. The Company shall continue until it is liquidated or dissolved in accordance with the Limited Liability Company Agreement of Talos Energy LLC, as amended and restated (the “LLC Agreement”). 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 material intercompany transactions have been eliminated. All adjustments that are of a normal, recurring nature and are necessary to fairly present the Company’s financial position, results of operations and cash flows for the periods are reflected. 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. During September 2015, the Company expanded its acreage position to include two shallow water exploration blocks off the coast of Mexico and drilled our first well in July 2017. The business activities in Mexico have been combined with the United States and reported as one segment. See additional information in “Note 4— Property, Plant and Equipment Recently Adopted Accounting Standards In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805)—Clarifying the Definition of a Business Acquisitions In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash Recently Issued Accounting Standards In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Revenue Recognition Extractive Activities—Oil and Gas—Revenue Recognition

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
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 that have been implemented or changed since December 31, 2017. Income Taxes Prior to the Stone Combination, Talos Energy LLC was a partnership for federal income tax purposes and was not subject to federal income tax or state income tax (in most states). As such, Talos Energy LLC was not a taxpaying entity for federal income tax purposes and accordingly, did not recognize any expenses for such states. In connection with completing the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to 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 estimates utilized in recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating our valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, and 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 expenses, respectively. Earnings Per Common Share Basic earnings per common share (“EPS”) is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of restricted stock unit grants and outstanding warrants. See Note 9— Earnings Per Share Share-Based Compensation The Company records share-based compensation associated with restricted stock units in general and administrative expense on the condensed consolidated statement of operations, net of amounts capitalized to oil and gas properties. Share-based compensation expense is based on the grant date fair value of issued restricted stock units recognized over the vesting period of the instrument. For each restricted stock unit grant, the Company determines whether the awards represent equity or liability based awards. The fair value of equity awards are determined based on the close price of the stock on the grant date. The fair value of the liability awards are remeasured at each reporting date based on the close price of the stock at such date, until the date of settlement. See Note 7— Employee Benefits Plans and Share Based Compensation .	Note 2—Summary of Significant Accounting Policies Below are the Company’s significant accounting policies. Cash and Cash Equivalents We reflect our cash as cash and cash equivalents on our consolidated balance sheets. We consider 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 plus accrued interest, 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 $5.9 million at December 31, 2017 and $4.9 million at December 31, 2016, which approximates fair value. We establish provisions for losses on accounts receivable and for natural gas imbalances with other parties if we believe that we will not collect all or part of the outstanding balance. On a quarterly basis we review collectability and establish or adjust our allowance as necessary using the specific identification method. Other Current Assets Other current assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”). The deposits are estimates related to royalties which we are required to pay the ONRR within thirty days of the production rate. On a monthly basis we adjust the deposit based on actual royalty payments remitted to the ONRR. Inventory Inventory primarily represents oil in lease tanks and line fill in pipelines. Our inventory is stated at the net realizable value. Sales of oil are accounted for by a weighted average cost method whereby oil sold from inventory is relieved at the weighted average cost of oil remaining in inventory. Revenue Recognition and Imbalances We record revenues from the sale of oil, natural gas and natural gas liquids (“NGLs”) based on quantities of production sold to purchasers under short-term contracts (less than 12 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. We have interests with other producers in certain properties. In these cases, we use the entitlement method to account for sales of production. Under the entitlement method, revenue is recorded when title passes based on our net interest. We may receive more or less than our entitled share of production, and we record our entitled share of revenues based on entitled volumes and contracted sales prices. If we receive more than our entitled share of production, the imbalance is recorded as a liability in accrued liabilities on the consolidated balance sheets. If we receive less than our entitled share, the imbalance is recorded as an asset in other current assets on the consolidated balance sheets. Our imbalances are recorded gross on our consolidated balance sheets. At December 31, 2017, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.7 million. At December 31, 2016, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.8 million. At December 31, 2015, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.6 million. We record the gross amount of reimbursements for costs from third parties as other revenues whenever the Company is the primary obligor with respect to the source of such costs, has discretion in the selection of how the related costs are incurred and when it has assumed the credit risk associated with the reimbursement for such costs. The costs associated with these third-party reimbursements are also recorded within the applicable cost and expenses line item in the consolidated statements of operations. Our other revenues have been generated primarily through fees for processing third-party production through some of our production facilities. 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 our 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 10— 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, wells currently drilling and capitalized interest are initially excluded from the amortizable base. We transfer unproved property costs into the amortizable base when properties are determined to have proved reserves or when we have completed an evaluation of the unproved properties resulting in an impairment. We evaluate 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 we own a direct interest. Our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. 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 our 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. We perform this ceiling test calculation each quarter. In accordance with the Securities and Exchange Commission (“SEC”) rules and regulations, we utilize SEC Pricing when performing the ceiling test. We also hold 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 resulted in a write-down of our oil and natural gas properties of nil, nil and $603.4 million during the years ended December 31, 2017, 2016 and 2015, respectively. 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 we sell or convey interests in oil and natural gas properties, we reduce our oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do 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. We treat sales proceeds on non-significant sales as reductions to the cost of our oil and natural gas properties. We recognize transportation costs as a component of direct lease operating expense when we are the shipper of the product. Such costs were $10.3 million, $9.1 million and $10.5 million in the years ended December 31, 2017, 2016 and 2015, 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 five years. Other Well Equipment Inventory Other well equipment inventory primarily represents the cost of equipment to be used in our oil and natural gas drilling and development activities such as drilling pipe, tubular 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. Our inventory is stated at net realizable value. We recorded $0.3 million, $0.2 million, $2.1 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, 2017, 2016 and 2015, 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— Level 2— Level 3— 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— Cost Approach— Income Approach— 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 We are required to record our 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. Our asset retirement obligations consist of estimated costs for dismantlement, removal, site reclamation and similar activities associated with our 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 our 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 derivatives to manage market risks resulting from fluctuations in prices of oil and natural gas. 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. We classify 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 our oil and natural gas operations, they are classified as cash flows from operating activities. We do not enter into derivative agreements for trading or other speculative purposes. The fair value of commodity derivatives reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. 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, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation, market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be favorable or unfavorable. Equity Based Compensation Certain of our employees participate in the equity based compensation plan of the Company. We measure 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 our employees and recognize compensation cost on a straight-line basis in our financial statements over the vesting period of each grant according to Accounting Standards Codification 718, Compensation—Stock Compensation. Income Taxes The Company is a limited liability company and not subject to federal or state income tax (in most states). As such, the Company is not a taxpaying entity for federal income tax purposes and accordingly, does not recognize any expense for such taxes. The federal income tax liability resulting from the Company’s activities is the responsibility of the Company’s Sponsors and other Unit holders. The Company is subject to state income taxes in certain jurisdictions and under applicable state laws taxes are estimated to be immaterial. We operate in the shallow waters off the coast of Mexico under a different legal form. As a result, income taxes are provided for based upon the tax laws and rates in effect in the foreign tax authorities. Deferred income tax assets and liabilities are recorded for the expected future tax consequences of events that are recognized in our financial statements or tax returns. A valuation allowance is established to reduce deferred tax assets when it is more likely than not that the overall deferred tax asset will not be realized. At December 31, 2017 and December 31, 2016, the Company has a valuation allowances of $4.0 million and $2.3 million, which is the amount of deferred tax assets. Concentration of Credit Risk Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents, restricted cash, accounts receivable and commodity derivatives. 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 experienced no losses on these accounts. Commodity derivatives are entered into with registered swap dealers, majority of which participate in our senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has experienced no losses due to counterparty default on these instruments. We market substantially all of our oil and natural gas production from properties we operate and those we do not operate. The majority of our oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. Our customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. We perform ongoing credit evaluations of our 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 our oil, natural gas and NGL revenues, was as follows: Year Ended December 31, 2017 2016 2015 Shell Trading (US) Company 80 % 68 % 68 % Chevron U.S.A Inc. * * 14 % 16 % ** less than 10% While the loss of Shell Trading (US) Company and Chevron U.S.A. Inc. as buyers might have a material effect on the Company in the short term, we believe that the Company would be able to obtain other customers for its oil, natural gas and NGL production. Supplementary Cash Flow Information Supplementary cash flow information for each period presented was as follows (in thousands): Year Ended December 31, 2017 2016 2015 Supplemental Non-Cash Transactions: Capital expenditures included in accounts payable and accrued liabilities $ 40,626 $ 13,832 $ 30,125 Fair value of assets acquired $ — $ — $ 75,519 Fair value of liabilities assumed $ — $ — $ 75,519 Capital lease transaction $ — $ 124,300 $ — Supplemental Cash Flow Information: Interest paid, net of amounts capitalized $ 47,994 $ 55,254 $ 37,247

Acquisitions

Acquisitions	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions	Note 3—Acquisitions Combination Between Talos Energy LLC and Stone Energy Corporation On May 10, 2018, the Company consummated the Transactions contemplated by the Transaction Agreement and the Exchange Agreement, pursuant to which, among other things, Talos Energy LLC and Stone became wholly-owned subsidiaries of the Company. Substantially concurrent with the consummation of the Transactions, the name of the Company was changed from Sailfish Energy Holdings Corporation to Talos Energy Inc. 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 consideration and fair value $ 731,964 The Company incurred approximately $76.2 million of transaction related costs, of which, $20.1 million was expensed and reflected in general and administrative expense on the condensed 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 condensed 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 condensed consolidated balance sheet. 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 condensed 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. 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 and the related asset retirement obligations. The Company anticipates finalizing the determination of the fair values by December 31, 2018. 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) $ 377,155 Property and equipment 876,500 Other long-term assets 18,928 Current liabilities (130,121 ) Long-term debt (235,416 ) Other long-term liabilities (175,082 ) 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. Pro Forma Financial Information (Unaudited) The following supplemental pro forma information (in thousands, except per common share amounts), presents the condensed consolidated results of operations for the three and six months ended June 30, 2018 and 2017 as if the Stone Combination had occurred on January 1, 2017. The unaudited proforma information was derived from historical combined 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. Three Months Ended Six Months Ended 2018 2017 2018 2017 Revenue $ 244,453 $ 166,669 $ 471,652 $ 340,939 Net income (loss) $ (45,696 ) $ 19,032 $ (51,211 ) $ 66,518 Basic and diluted net income (loss) per common share $ (0.84 ) $ 0.35 $ (0.95 ) $ 1.23 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.	Note 3—Acquisitions 2017 Merger Announcement Merger with Stone Energy On November 21, 2017, the Company executed an agreement to combine with Stone Energy Corporation (“Stone”) to form Talos Energy, Inc. in an all-stock transaction, which is expected to occur during the second quarter of 2018. The transaction has been unanimously approved by both our and Stone’s Board of Directors. Under the terms of the agreement, each outstanding share of Stone common stock will be exchanged for one share of Talos Energy, Inc. common stock and the current Talos Energy stakeholders will be issued an aggregate of approximately 34.2 million common shares. At closing, our stakeholders will own 63% and Stone’s shareholders will own 37% of the combined company. Talos Energy, Inc. is expected to trade on the New York Stock Exchange under the ticker symbol “TALO.” 2016 Acquisitions The acquisition 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 Additional Working Interest in the Phoenix Field On December 20, 2016, we 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 our Sponsors. Additionally, we 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 the Company’s 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 has an indefinite life pursuant to the purchase and sale agreement. We refer to the acquisition of assets from Sojitz as the “Sojitz Acquisition.” As of 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 below 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): Allocation of the Purchase Price December 20, 2016 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 ) Cash Paid $ 88,238 2015 Acquisitions The acquisitions below qualified as business combinations and were accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation. Acquisition of Additional Working Interest in Our Motormouth Discovery from Deep Gulf Energy III, LLC On April 8, 2015, the Company entered into a supplemental agreement and first amendment to a previous participation agreement dated July 1, 2014 with Deep Gulf Energy III, LLC (“DGE”) to acquire a 25% working interest in the Motormouth discovery located in the Phoenix Field in exchange for $38.5 million in cash, the assumption of estimated asset retirement obligations and the right to participate in an additional 10% working interest in our Tornado exploration prospect. The working interest acquired from DGE was previously farmed out to DGE on July 1, 2014 in order for DGE to participate in the Motormouth exploration prospect. Our Sponsors made a $75.0 million ($73.5 million net of $1.5 million of transaction fees) equity contribution in April 2015, of which a portion was used to fund the purchase price. We refer to the acquisition of assets from DGE as the “DGE Acquisition.” We completed the final purchase price allocation in 2015 which was calculated as follow (in thousands): Allocation of the Purchase Price April 8, 2015 Proved properties $ 24,316 Unproved properties, not subject to amortization 14,643 Asset retirement obligations (442 ) Cash Paid $ 38,517 Revenue attributable to the assets acquired in the DGE Acquisition during the year ended December 31, 2015 was $1.9 million. The presentation of net income attributable to the assets acquired from DGE is impracticable due to the integration of the operations upon acquisition. Acquisition of Gulf Coast Energy Resources, LLC On March 31, 2015, the Company completed the acquisition of all the issued and outstanding membership interests of Gulf Coast Energy Resources, LLC (“GCER”) from Warburg Pincus Private Equity (E&P) X-A, LP and its affiliates, Q-GCER (V) Investment Partners and GCER management and independent directors. Through this acquisition, the Company acquired all of GCER’s oil and natural gas assets which consist of proved and unproved property primarily located in the Gulf of Mexico Shelf and lower Gulf Coast areas along with current and other long-term assets. As consideration for the acquired membership interests in GCER, the Company assumed $55.0 million in long-term debt as well as the estimated asset retirement obligations and current liabilities as of March 31, 2015. Additionally, we entered into a contingent consideration arrangement in the form of an earn-out, valued at $0.1 million, if the oil and natural gas assets meet certain return on investment targets within the subsequent five years. The Company incurred approximately $0.8 million of transaction fees which were expensed and reflected in general and administrative expense during 2015. We refer to the acquisition of all the issued and outstanding membership interests in GCER as the “GCER Acquisition.” We completed the final purchase price allocation in 2015 which was calculated as follow (in thousands): Allocation of the Purchase Price March 31, 2015 Current assets $ 12,748 Proved properties 38,680 Unproved properties, not subject to amortization 22,637 Other non-current assets 536 Total assets acquired 74,601 Current portion of asset retirement obligations 107 Other current liabilities 18,632 Asset retirement obligations 744 Long-term debt, net of discount(1) 55,000 Other long-term liabilities(2) 118 Total liabilities assumed 74,601 Net assets acquired $ — (1) The long-term debt, net of discount assumed represents $55.0 million in borrowings under GCER’s senior reserve-based revolving credit facility (“GCER Bank Credit Facility”). (2) The other long-term liabilities assumed includes $0.1 million to recognize an estimated liability as of the acquisition date for the contingent consideration arrangement if the oil and natural gas assets acquired meet certain targets within the subsequent five years. The fair value of the contingent consideration was calculated using a Monte Carlo simulation analysis. Significant inputs to the analysis are based, in part, on inputs not observable in the market and thus represent Level 3 measurements in the fair value hierarchy. These inputs 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. The maximum potential payment under the contingent consideration arrangement is $6.5 million. The fair value, as adjusted, of the current assets acquired includes the following receivables (in thousands): March 31, 2015 Gross Receivable Expected Uncollectable Amount Fair Trade receivables $ 3,104 $ — $ 3,104 Joint interest receivables $ 3,484 $ (323 ) $ 3,161 Other receivables $ 196 $ — $ 196 Revenue and net loss attributable to the assets acquired in the GCER Acquisition during the year ended December 31, 2015 was $12.6 million and $9.7 million, respectively. Revenues were reduced by production costs of the assets acquired and for estimated depletion and accretion expense in calculating net loss. Depletion expense was calculated by applying the Company’s depletion rate on proved oil and natural gas properties per Boe to production attributable to the acquired assets. Accretion on the asset retirement obligation was calculated using the Company’s credit-adjusted risk-free interest rate. Total non-cash depletion and accretion expense included in the net loss for the year ended December 31, 2015 was $15.6 million.

Property, Plant and Equipment

Property, Plant and Equipment	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Oil And Gas Property [Abstract]
Property, Plant and Equipment	Note 4—Property, Plant and Equipment Proved Properties. 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, net of related deferred taxes, are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. The Company performs this ceiling test calculation each quarter utilizing SEC pricing. At June 30, 2018, the Company’s ceiling test computation of its U.S. oil and natural gas properties was based on SEC pricing of $60.03 per Bbl of oil, $2.90 per Mcf of natural gas and $28.26 per Bbl of NGLs. During the three and six months ended June 30, 2018 and 2017, the Company’s ceiling test computation did not result in a write-down of its U.S. oil and natural gas properties. Unproved Properties. Capitalized Overhead. Asset Retirement Obligations. Commitments and Contingencies 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 the Company’s asset retirement obligations. Typically, these changes result from obtaining new information about the timing of the Company’s obligations to plug, abandon and remediate oil and natural gas wells and related infrastructure and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense on the condensed 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 on the condensed consolidated balance sheets in current and non-current liabilities and the changes to that liability during the six months ended June 30, 2018 were as follows (in thousands): Asset retirement obligations at January 1, 2018 $ 214,733 Fair value of asset retirement obligations assumed 220,637 Obligations settled (43,896 ) Accretion expense 14,252 Obligations incurred 120 Changes in estimate 8,532 Asset retirement obligations at June 30, 2018 $ 414,378 Less: Current portion 94,334 Long-term portion $ 320,044	Note 4—Property, Plant and Equipment Proved Properties. Pursuant to SEC Regulation S-X, Rule 4-10, under the full cost method of accounting, our capitalized oil and natural gas costs are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. We perform this ceiling test calculation each quarter utilizing SEC Pricing. During 2017 and 2016, our ceiling test computations did not result in a write-down of our U.S oil and natural gas properties. At September 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and natural gas properties of $279.3 million based on SEC Pricing, of $61.22 per Bbl of oil, $3.29 per Mcf of natural gas and $20.65 per Bbl of NGLs. At December 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and natural gas properties of $324.1 million based on SEC Pricing of $50.72 per Bbl of oil, $2.75 per Mcf of natural gas and $17.60 per Bbl of NGLs. Unproved Properties. The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2017, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2017 2016 2015 2014 and Prior Acquisition $ 23,871 $ — $ 3,845 $ 4,089 $ 15,937 Exploration 48,131 27,137 7,174 2,621 11,199 Total unproved properties, not subject to amortization $ 72,002 $ 27,137 $ 11,019 $ 6,710 $ 27,136 The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined. We expect this process to occur over the next five years. In March 2017, the Company was the apparent high bidder on six blocks in connection with the Gulf of Mexico Federal Lease Sale 247 held by the Bureau of Ocean Energy Management (“BOEM”). The six blocks were awarded to the Company during the second quarter 2017. The Company paid BOEM approximately $2.6 million during the first and second quarter of 2017 for the awarded leases and for first year’s lease rentals. Capitalized Interest. Capitalized Overhead. Asset Retirement Obligations. In estimating the liability associated with our asset retirement obligations, we utilize 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 our asset retirement obligations. Typically, these changes result from obtaining new information about the timing of our 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 our consolidated statements of operations. If we incur an amount different from the amount accrued for decommissioning obligations, we recognize 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 the each of the years ended December 31, were as follows (in thousands): Year Ended December 31, 2017 2016 Asset retirement obligations at January 1 $ 220,049 $ 226,690 Fair value of asset retirement obligations acquired 699 6,445 Obligations settled (32,573 ) (23,689 ) Accretion expense 19,295 21,829 Obligations incurred 4,213 1,014 Changes in estimate(1) 3,050 (12,240 ) Asset retirement obligations at December 31 $ 214,733 $ 220,049 Less: Current portion at December 31 (39,741 ) (33,556 ) Noncurrent portion at December 31 $ 174,992 $ 186,493 (1) The reduction during the year ended December 31, 2016 was primarily attributable to a reduction in service costs.

Financial Instruments

Financial Instruments	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Financial Instruments [Abstract]
Financial Instruments	Note 5—Financial Instruments The following table presents the carrying amounts and estimated fair values of financial instruments (in thousands): June 30, 2018 December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value 11.00% Second-Priority Senior Secured Notes—due April 2022(1) $ 380,042 $ 410,411 $ — $ — 7.50% Senior Secured Notes—due May 2022 $ 6,060 $ 5,999 $ — $ — Bank Credit Facility—due May 2022(1) $ 231,522 $ 240,000 $ — $ — 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 Old Bank Credit Facility—due February 2019(1) $ — $ — $ 402,062 $ 403,000 Oil and Natural Gas Derivatives $ (185,755 ) $ (185,755 ) $ (66,830 ) $ (66,830 ) (1) The carrying amounts are net of discount and deferred financing costs. As of June 30, 2018 and December 31, 2017, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair values because of the short-term nature of these instruments. 11.00% Second-Priority Senior Secured Notes—due April 2022. 7.50% Senior Secured Notes—due May 2022 Bank Credit Facility—due May 2022. Debt Oil and natural gas derivatives. The following table presents the impact that derivatives not qualifying as hedging instruments had on the Company’s condensed consolidated statements of operations (in thousands): Three Months Ended Six Months Ended 2018 2017 2018 2017 Price risk management activities income (expense)(1) $ (91,176 ) $ 38,995 $ (143,152 ) $ 84,888 (2) The Company paid $33.6 million and received $9.2 million in net cash settlements for the three months ended June 30, 2018 and 2017, respectively, and paid $54.1 million and received $13.7 million in net cash settlements for the six months ended June 30, 2018 and 2017, respectively. The following table reflects the contracted volumes and weighted average prices the Company will receive under its derivative contracts as of June 30, 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 ) July 2018—December 2018 Swap 29,615 $ 54.06 $ — $ — July 2018—December 2018 Collar 1,000 $ — $ 45.00 $ 55.35 July 2018—December 2018 Put 2,000 $ — $ 49.50 $ — January 2019—December 2019 Swap 23,130 $ 54.14 $ — $ — Natural Gas—Henry Hub NYMEX: (MMBtu ) (per MMBtu ) (per MMBtu ) (per MMBtu ) July 2018—December 2018 Swap 23,747 $ 3.01 $ — $ — July 2018—December 2018 Collar 6,000 $ — $ 2.75 $ 3.24 January 2019—December 2019 Swap 10,146 $ 2.99 $ — $ — The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands): June 30, 2018 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas derivatives $ — $ 733 $ — $ 733 Liabilities: Oil and natural gas derivatives — (186,488 ) — (186,488 ) Total net liability $ — $ (185,755 ) $ — $ (185,755 ) December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas derivatives $ — $ 1,908 $ — $ 1,908 Liabilities: Oil and natural gas derivatives — (68,738 ) — (68,738 ) Total net liability $ — $ (66,830 ) $ — $ (66,830 ) Financial Statement Presentation. June 30, 2018 December 31, 2017 Assets from price risk management activities—current: Oil and natural gas derivatives $ 499 $ 1,563 Assets from price risk management activities—non-current: Oil and natural gas derivatives $ 234 $ 345 Liabilities from price risk management activities—current: Oil and natural gas derivatives $ 154,722 $ 49,957 Liabilities from price risk management activities—non-current: Oil and natural gas derivatives $ 31,766 $ 18,781 Credit Risk.	Note 5—Financial Instruments The following table presents the carrying amounts and estimated fair values of financial instruments (in thousands): December 31, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value 11.00% Bridge Loans—due April 2022 $ 169,838 $ 172,023 $ — $ — 9.75% Senior Notes—due July 2022 $ 100,681 $ 102,000 $ — $ — 9.75% Senior Notes—due February 2018 $ 24,977 $ 24,977 $ 294,964 $ 137,850 Bank Credit Facility $ 402,062 $ 403,000 $ 406,211 $ 408,000 Derivatives $ (66,830 ) $ (66,830 ) $ (15,433 ) $ (15,433 ) As of December 31, 2017 and 2016, 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. Bridge Loans, 2022 Senior Notes and 2018 Senior Notes. Debt Debt). Bank Credit Facility. Debt Oil and natural gas derivatives. The following table presents the impact that derivatives not qualifying as hedging instruments had on our consolidated statements of operations (in thousands): Year Ended December 31, 2017 2016 2015 Price risk management activities income (expense)(1) $ (27,563 ) $ (57,398 ) $ 182,196 (1) The Company received net cash settlements of $23.8 million, $172.2 million and $181.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. The following table reflects the contracted volumes and weighted average prices we will receive under our derivative contracts as of December 31, 2017: Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Crude Oil—WTI: (Bbls ) (per Bbl ) January 2018—December 2018 Swap 24,804 $ 53.79 January 2019—December 2019 Swap 15,866 $ 53.17 Natural Gas—Henry Hub NYMEX: (MMBtu ) (per MMBtu ) January 2018—December 2018 Swap 26,346 $ 3.00 January 2019—December 2019 Swap 10,146 $ 2.99 Subsequent event. Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Crude Oil—WTI: (Bbls ) (per Bbl ) January 2019—June 2019 Swap 1,008 $ 56.25 The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands): December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps $ — $ 1,908 $ — $ 1,908 Liabilities: Oil and natural gas swaps — (68,738 ) — (68,738 ) Total net liability $ — $ (66,830 ) $ — $ (66,830 ) December 31, 2016 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 20,469 $ — $ 20,469 Liabilities: Oil and natural gas swaps and costless collars — (35,902 ) — (35,902 ) Total net liability $ — $ (15,433 ) $ — $ (15,433 ) Financial Statement Presentation. December 31, December 31, Assets from price risk management activities—current: Oil and natural gas derivatives $ 1,563 $ 20,176 Assets from price risk management activities—non-current: Oil and natural gas derivatives $ 345 $ 293 Liabilities from price risk management activities—current: Oil and natural gas derivatives $ 49,957 $ 27,147 Liabilities from price risk management activities—non-current: Oil and natural gas derivatives $ 18,781 $ 8,755 Credit Risk. BBB-or

Debt

Debt	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
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 June 30, 2018 December 31, 2017 11.00% Second-Priority Senior Secured Notes—due April 2022 Principal $ 390,868 $ — Original issue discount, net of amortization (8,906 ) — Deferred financing costs, net of amortization (1,920 ) — 7.50% Senior Secured Notes—due May 2022 Principal 6,060 — Bank Credit Facility—due May 2022 Principal 240,000 — Deferred financing costs, net of amortization (8,478 ) — 4.20% Building Loan—due November 2030 Principal 10,778 — 11.00% Bridge Loans—due April 2022 Principal — 172,023 Deferred financing costs, net of amortization — (2,185 ) 9.75% Senior Notes—due July 2022 Principal — 102,000 Deferred financing costs, net of amortization — (1,319 ) 9.75% Senior Notes—due February 2018 Principal — 24,977 Old Bank Credit Facility—due February 2019 — 403,000 Deferred financing costs, net of amortization — (938 ) Total debt $ 628,402 $ 697,558 Less: current portion of long-term debt (434 ) (24,977 ) Long-term debt, net of discount and deferred financing costs $ 627,968 $ 672,581 In connection with the Stone Combination, the Company consummated the Transactions contemplated by the Exchange Agreement, 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 exchange of 7.50% Stone Senior Notes for 11.00% Senior Secured Notes was 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 $3.9 million and $4.5 million of transaction fees related to the modification which were expensed and reflected in general and administrative expense during the three months and six months ended June 30, 2018, respectively. The Company also paid $9.3 million in work fees to debt holders, which are reflected as debt discount reducing long-term debt on the condensed consolidated balance sheet. 11.00% Second-Priority Senior Secured Notes—due April 2022 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 June 30, 2018. 7.50% Senior Secured Notes—due May 2022 Bank Credit Facility—due May 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 beginning on or after September 30, 2018. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter beginning on or after September 30, 2018. 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 certain of the Company’s wholly-owned subsidiaries and each direct parent of the Company. 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. In June 2018, the Company completed the first redetermination and the borrowing base was reaffirmed at $600.0 million. The next redetermination will occur in October 2018 and scheduled redeterminations will occur each April and October thereafter. As of June 30, 2018, the Company’s borrowing base was set at $600.0 million, of which no more than $200 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 June 30, 2018. As of June 30, 2018, the Bank Credit Facility had approximately $354.0 million of undrawn commitments (taking into account $6.0 million letters of credit and $240.0 million drawn from the Bank Credit Facility). The $294.0 million in cash received from the Company’s initial drawdown under the Bank Credit Facility was used to partially repay outstanding borrowings under the Old Bank Credit Facility upon its termination in connection with the Stone Combination. Building Loan—due November 2030 9.75% Senior Notes—due February 2018	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, 2017 December 31, 2016 11.00% Bridge Loans—due April 2022 Principal $ 172,023 $ — Deferred financing costs, net of amortization (2,185 ) — 9.75% Senior Notes—due July 2022 Principal 102,000 — Deferred financing costs, net of amortization (1,319 ) — 9.75% Senior Notes—due February 2018 Principal 24,977 300,000 Original issue discount, net of amortization — (806 ) Deferred financing costs, net of amortization — (4,230 ) Bank Credit Facility—due February 2019 403,000 408,000 Deferred financing costs, net of amortization (938 ) (1,789 ) Total debt $ 697,558 $ 701,175 Less: Current portion of long-term debt (24,977 ) — Long-term debt, net of discount and deferred financing costs $ 672,581 $ 701,175 On April 3, 2017 (the “Closing Date”), the Company entered into an Exchange Agreement (the “Exchange Agreement”) pursuant to which Bain Capital Credit LP, GSO Capital Partners LP and certain affiliates of our Sponsors (the “Exchanging Noteholders”) exchanged some of the 2018 Senior Notes for Bridge Loans (as described below). Certain affiliates of the Sponsors also exchanged some of the 2018 Senior Notes for 2022 Senior Notes (as described below). The exchange of debt instruments was 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 2018 Senior 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 which were expensed and reflected in general and administrative expense during the year ended December 31, 2017, respectively. Bridge Loans. The obligations under the Credit Agreement are second-priority secured obligations behind the Bank Credit Facility. The obligations are secured by substantially all of the Company’s assets. The Company will pay interest on amounts outstanding under the Credit Agreement at 11.0% per annum, semiannually on April 15 and October 15 of each year, which commenced October 15, 2017. The Company may redeem up to 35% of the aggregate principal amount of the Bridge Loans at a price equal to 111% of the aggregate principal amount plus accrued and unpaid interest, if any, at any time prior to April 3, 2018. The Company may redeem the Bridge Loans, in whole or in part, on or after April 3, 2018 at the redemption prices set forth in the Credit Agreement. The Credit Agreement contains covenants that limit the Company’s ability (and their restricted subsidiaries’ ability) 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 transactions with affiliates; (vii) engage in sales of assets and subsidiary stock; and (viii) transfer all or substantially all of its assets or enter into merger or consolidation transactions. The Credit Agreement does not contain a financial maintenance covenant. The Credit Agreement also provides for certain customary events of default, which, if any of such defaults occurs, would permit or require the principal, premium (if any), interest or other monetary obligations on all of the then outstanding Bridge Loans to become due and payable. The Bridge Loans contain customary quarterly and annual reporting, financial and administrative covenants. 2022 Senior Notes. The Company may redeem up to 35% of the aggregate principal amount of the 2022 Senior Notes at a price equal to 109.75% of the aggregate principal amount plus accrued and unpaid interest, if any, at any time prior to April 3, 2018. The Company may redeem the 2022 Senior Notes, in whole or in part, on or after April 3, 2018 at the redemption prices set forth in the Indenture. The remainder of the terms of the 2022 Senior Notes are substantially similar to the terms of the 2018 Senior Notes. 2018 Senior Notes. Subsequent event. Bank Credit Facility. The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. In addition, the Company is obligated to pay a commitment fee rate based on the borrowing base usage of 0.375% to 0.50%. The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a consolidated debt to adjusted EBITDA figure of no greater than 3.50 to 1.00. 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 certain of our 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 in the spring and fall, with the last redetermination on May 16, 2017. On January 10, 2017, we paid down $15.0 million under our Bank Credit Facility, and on April 3, 2017, we borrowed $10.0 million from our Bank Credit Facility. In May 2017, the lenders under our Bank Credit Facility reaffirmed the borrowing base at $475.0 million during their regular semi-annual redetermination. In conjunction with the reaffirmation of the borrowing base, the Company executed the Eighth Amendment to the Bank Credit Facility effective May 16, 2017. The Eighth Amendment includes (i) an increase to the consolidated total debt to EBITDAX (as defined in the Bank Credit Facility) ratio covenant from 3.50 to 1.0 to 3.75 to 1.0 each quarter from September 30, 2017 to March 31, 2018 and (ii) a requirement to execute control agreements for all deposit accounts, securities accounts and commodities accounts in the name of the borrowers and guarantors. On October 31, 2017, the Company executed the Ninth Amendment to the Bank Credit Facility deferring the borrowing base redetermination to January 2018 to fully assess the reserve impact of our recent Tornado II discovery. As of December 31, 2017, the Company’s borrowing base was set at $475.0 million, of which no more than $200 million can be used as letters of credit. As of December 31, 2017, the Bank Credit Facility had approximately $67.1 million of undrawn commitments (taking into account $4.9 million letters of credit and $403.0 million drawn under the Bank Credit Facility). We were in compliance with all debt covenants at December 31, 2017. Subsequent event.

Employee Benefits Plans and Sha

Employee Benefits Plans and Share-Based Compensation	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
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 In connection with the Transactions, the Company maintains the Stone Energy Corporation Executive Severance Plan and Stone Energy Corporation Employee Severance Plan, which provides for the payment of severance and change in control benefits to certain individuals who, prior to the transaction, were executive officers of Stone and all full-time employees of Talos Petroleum LLC (f/k/a Stone Energy Corporation), in each case upon an involuntary termination within twelve months of Closing. The Company incurred $7.5 million of severance expense reflected in general and administrative expense on the condensed consolidated statement of operations for the three and six months ended June 30, 2018. Approximately $5.1 million of such expense remained unpaid at June 30, 2018. Long Term Incentive Plan Overview Restricted Stock Units. Talos Energy LLC Series B Units Prior to the Stone Combination, the Limited Liability Company Agreement of Talos Energy LLC (the “LLC Agreement”) 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 as described in Note 7 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 condensed consolidated balance sheet. During the six months ended June 30, 2018 and 2017, the Company recognized approximately $0.2 million and $0.5 million, respectively, as compensation expense included in general and administrative expense on the condensed consolidated statement of operations and capitalized approximately $0.2 million and $0.5 million, respectively, into its oil and natural gas properties on the condensed consolidated balance sheet. The Company’s unrecognized compensation expense at June 30, 2018 is approximately $2.9 million. Of this amount, approximately $0.7 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 21 months. 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 modification, 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”. Accelerated vesting was recognized in May 2018 to account for months between the grant date of the original Series B Units and the grant date of the New Series B Units. For the six months ended June 30, 2018 and 2017, the Company recognized approximately $1.3 million and nil, respectively, of compensation expense included in general and administrative expense on the condensed consolidated statement of operations and capitalized approximately $2.3 million and nil, respectively, into its oil and natural gas properties on the condensed 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 June 30, 2018 is approximately $2.4 million. Of this amount, approximately $0.3 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 $2.1 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 eleven months.	Note 7—Employee Incentive Programs Employee Share Ownership Program The LLC Agreement established Series A, Series B and Series C Units. Series B Units are generally intended to be used as incentives for Talos Energy LLC employees. Talos Energy LLC is initially authorized to issue 1 million Series B Units and may issue more under the LLC Agreement. With the exception of distributions to cover the assumed tax liability of the Series B Unit holders, Series B Units do not participate in cash distributions prior to vesting and until Series A Units have received cumulative cash distributions equal to (i) the original cash contributed to Talos Energy LLC for such Series A Units and (ii) 8% returns, compounded annually (the “Aggregate Series A Payout”), and Series C Units have received $25 million in cash distributions. After issuance, 80% of the Series B Units vest on a monthly basis over a four year period, subject to continued employment. The remaining 20% of the Series B Units fully vest (a) upon the occurrence of a Liquidation Event or an Approved Sale, as defined in the LLC Agreement, that results in an Aggregate Series A Payout or (b) in the case of a public offering upon the occurrence of an Aggregate Series A Payout. We had 992,850 Series B Units outstanding at December 31, 2017, 980,250 Series B Units outstanding at December 31, 2016 and 906,000 Series B Units outstanding at December 31, 2015. A summary of the Series B Unit activity for the years ended December 31, 2017, 2016 and 2015 is presented below. Number of Series B Units Weighted Average Estimated Fair Value per Unit Non-vested at December 31, 2014 642,355 $ 21.04 Vested (175,196 ) 20.43 Forfeited or cancelled (92,500 ) 22.08 Non-vested at December 31, 2015 374,659 $ 21.07 Granted 147,000 4.11 Vested (122,455 ) 17.95 Forfeited or cancelled (72,750 ) 21.22 Non-vested at December 31, 2016 326,454 $ 14.57 Granted 35,100 20.99 Vested (104,614 ) 17.16 Forfeited or cancelled (22,500 ) 15.10 Non-vested at December 31, 2017 234,440 $ 14.32 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 equity. In the years ended December 31, 2017, 2016 and 2015, we recognized approximately $0.9 million, $1.1 million and $1.7 million, respectively, in compensation expense included in general and administrative expense and capitalized approximately $0.9 million, $1.2 million and $1.9 million, respectively, into our oil and natural gas properties. The 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 Company. The fair value of each grant was estimated at the date of grant using the following weighted-average assumptions: 2017 Grants 2016 Grants Assumed value of equity (in thousands) $ 789,426 $ 196,280 Risk-free rate of interest 1.16 % 1.11 % Expected time to a liquidity event (in years) 1 3 Expected volatility of equity 40 % 70 % Discount for lack of marketability 25 % 34 % The total value of the equity is calculated in an iterative process that results in the 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 Series B Units and the volatility of the Series B Units using a Black-Scholes-Merton model. Our unrecognized compensation expense at December 31, 2017 is approximately $3.4 million. Of this amount, approximately $1.1 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 related to 135,712 Series B Units will be recognized (a) upon the occurrence of a Liquidation Event or an Approved Sale, as defined in the LLC Agreement, that results in an Aggregate Series A Payout or (b) in the case of a public offering upon the occurrence of an Aggregate Series A Payout. The weighted-average period over which the unrecognized compensation expense will be recognized is 24 months. At December 31, 2017, the Company has 7,150 Series B units authorized but not yet issued.

Income Taxes

Income Taxes	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Note 8—Income Taxes Prior to the Stone Combination, Talos Energy LLC was a partnership for federal income tax purposes and was not subject to federal income tax or state income tax (in most states). As such, Talos Energy LLC was not a taxpaying entity for federal income tax purposes and accordingly, did not recognize any expense for such states. Talos Energy LLC’s operations in the shallow waters off the coast of Mexico are conducted under a different legal form and are subject to foreign income taxes. In connection with completing 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 obligation and net operating loss carryforwards. The Company’s tax basis in assets exceeds its book basis in assets, resulting in a deferred tax asset. 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 deferred tax asset will not be realized and therefore has 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 is zero. The Company accounted for the book and tax basis difference from the Stone Combination in acquisition accounting. Due to the valuation allowance, the net income tax impact is zero. As part of the Stone Combination, entities related to the Apollo Funds and Riverstone Funds contributed entities that were under common control to the Company. At June 30, 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 equity. The Company believes it is more likely than not that the net deferred tax asset will not be realized and therefore has recorded a valuation allowance. The deferred tax balance is based on preliminary calculations and on information available to management at the time such estimates were made. Further analysis will be made upon filing the tax returns that will result in a change to the net deferred tax impact recorded. Due to the valuation allowance, the net result is expected to be zero. A summary of deferred tax balances as of June 30, 2018 is presented in the table below (in thousands): Deferred tax asset $ 213,029 Deferred tax liability (82,805 ) Net deferred tax asset 130,224 Valuation allowance (130,224 ) Net deferred tax asset $ — As a result of the Stone Combination, the Company acquired a current income tax receivable of $16.2 million primarily related to the carryback of specified liability losses.	Note 8—Income Taxes The Company is a limited liability company and not subject to federal income tax or state income tax (in most states). As such, the Company is not a taxpaying entity for federal income tax purposes and accordingly, does not recognize any expense for such taxes. The federal income tax liability resulting from the Company’s activities is the responsibility of the Company’s Sponsors and other Unit holders. The Company is subject to state income taxes in certain jurisdictions and under applicable state laws taxes are estimated to be immaterial We operate in the shallow waters off the coast of Mexico under a different legal form. As a result, we are subject to foreign tax authorities. Although the Company is subject to foreign income taxes, the Company incurred only foreign expenses in Mexico during the years ended December 31, 2017, 2016 and 2015. The Company is subject to foreign income taxes and under the foreign tax law and treaties among these governments taxes are estimated to be immaterial. Deferred income tax assets and liabilities are recorded for the expected future tax consequences of events that are recognized in our financial statements or tax returns. At December 31, 2017, the Company recorded a deferred tax asset mostly related to the foreign tax loss carry forward. 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 overall deferred tax asset will not be realized. At December 31, 2017 and December 31, 2016, the Company has a valuation allowance of $4.0 million and $2.3 million, respectively, which is the amount of deferred tax asset. Foreign tax loss carryforwards at December 31, 2017 was $13.4 million. The foreign tax loss carryforwards will start to expire in 2025. On December 22, 2017, the President signed into 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.” Tax Act makes broad and complex changes to the U.S. tax code. Since Talos is a limited liability company and treated as a pass-through entity for federal tax purposes and in most states, the Company did not recognize any income tax impact from the new Tax Act.

Earnings Per Share

Earnings Per Share	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Earnings Per Share	Note 9—Earnings Per Share Basic earnings per share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per share include the impact of restricted stock unit grants and outstanding warrants. For the three and six months ended June 30, 2018, the Company incurred net losses and accordingly excluded all potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive. As of June 30, 2018, the Company had approximately 3.5 million of outstanding warrants. These warrants have an exercise price of $42.04 per share and a term of four years.

Related Party Transactions

Related Party Transactions	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Note 10—Related Party Transactions Contributions and Distributions. Transaction Fee Agreement . Service Fee Agreement. Debt Modification Work Fees.	Note 9—Related Party Transactions Transaction Fee Agreement. Service Fee Agreement. Contributions and Distributions. Acquisitions Acquisitions).

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Commitments and Contingencies	Note 11—Commitments and Contingencies Capital Lease As of June 30, 2018, the balance of the capital lease obligation on the condensed consolidated balance sheet was $99.7 million, of which $12.7 million is included in “other current liabilities” and $87.0 million is included in “other long-term liabilities”. Performance Obligations As of June 30, 2018, the Company had secured performance bonds primarily related to plugging and abandonment of wells, removal of facilities and to guarantee the completion of the minimum work program related to the Mexico Production Sharing Contracts (“PSCs”) totaling approximately $569.3 million. The Mexico PSCs govern the exploration and extraction of the hydrocarbons in Mexico with the CNH. As of June 30, 2018, the Company has not posted any collateral on the outstanding performance bonds. Legal Proceedings 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. Other Commitments On February 8, 2018, the Company amended a previous agreement to use the Ensco 75, a jackup drilling rig, to execute a portion of its 2018 drilling program. Under the terms of the amended agreement, the Company will pay Ensco a base vessel day work rate based on the number of days contracted for a minimum of 120 days during 2018, for approximately $7.8 million. On June 1, 2018, the Company exercised its option for an additional 90 days during 2018 for approximately $6.3 million. Total commitments for 2018 for the Ensco 75 are $14.1 million. On June 18, 2018, the Company entered into an agreement for the Ensco 8503 drilling rig to execute a portion of its 2018 deepwater drilling program commencing November 1, 2018. Under the terms of the agreement, the Company will pay Ensco an operating day work rate based on the number of days contracted for a minimum of 100 days. Total commitments for 2018 and 2019 are $7.9 million and $5.1 million, respectively. In connection with the Stone Combination, the Company entered into seismic use agreements totaling $46.8 million. As of June 30, 2018, the outstanding payments due are approximately $29.8 million consisting of $6.6 million, $10.9 million, $9.9 million and $2.4 million for the remainder of 2018, 2019, 2020 and 2021, respectively.	Note 10—Commitments and Contingencies Capital Lease On August 2, 2016, ERT 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 will pay Helix an annual fixed demand charge of $49.0 million during the first two years and $45.0 million thereafter. If certain uptime rates are achieved, the Company will pay Helix a quarterly incentive payment of $0.5 million during the first two years of the agreement and $0.8 million thereafter. The Agreement replaces the previous lease agreement for the HP-I, which provided that ERT would pay Helix (i) a fixed annual demand fee of $33.0 million and (ii) a 10% throughput charge on the net consideration payable to ERT under a sales contract for the sale of hydrocarbons processed through the HP-I. 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 our consolidated balance sheet. As of December 31, 2017, the balance of the capital lease obligation on the consolidated balance sheet is $106.6 million, of which $12.9 million is included in other current liabilities and $93.7 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, 2017, minimum lease commitments for our capital lease for the years ended December 31 are as follows (in thousands): 2018 $ 46,667 2019 45,000 2020 45,000 2021 45,000 2022 45,000 Thereafter 18,750 Total minimum lease payments 245,417 Less amount represented lease operating expenses (63,607 ) Less amount represented interest (75,189 ) Present value of minimum lease payments 106,621 Less current maturities of capital lease obligations (12,952 ) Long-term capital lease obligations $ 93,669 Legal Proceedings and Other Contingencies In August 2015, we became aware of a potential unauthorized discharge on our Vermilion 195 platform in connection with an operation to bleed off production casing pressure. We immediately initiated an internal investigation of the alleged matter and concluded that an unauthorized discharge had occurred. We terminated the individuals that were determined to be responsible for the discharge. We also self-reported the matter to the U.S. Environmental Protection Agency (“EPA”) on September 17, 2015. On November 30, 2015, ERT was charged with two violations of Outer Continental Shelf Lands Act (“OCSLA”) in connection with hot work and blowout preventer testing activities, and with two violations of the Clean Water Act (“CWA”) for the self-reported activities surrounding overboard discharge sampling and unpermitted discharges, as described above. On January 6, 2016, 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 OSCLA. 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 CWA, 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. 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, 2017 and 2016, we had secured performance bonds totaling approximately $287.8 million and $338.2 million, respectively. As of December 31, 2017 and 2016, we had $4.9 million and $4.0 million, respectively, in letters of credit issued under our Bank Credit Facility. In July 2016, the BOEM announced updated financial assurance and risk management requirements for offshore leases. The Notice to Lessees (“NTL”) details procedures to determine a lessee’s ability to carry out its lease obligations—primarily the decommissioning of Outer Continental Shelf (“OCS”) facilities—and whether to require lessees to furnish additional financial assurance to meet BOEM’s estimate of the lessees decommissioning obligations. The NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure its OCS liabilities based upon the lessee’s financial capacity and financial strength. The NTL also allows lessees to meet their additional financial security requirements through the submission of a tailored plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances. In the first quarter of 2017, BOEM announced that it will extend the implementation timeline for the new NTL by an additional six months. Sole-liability leaseholders will have 60 days from the date of receipt of an order requiring additional financial security to comply. For all other holdings, leaseholders will have 120 days from the date they receive an order to provide additional security, if required. Alternatively, lessees can provide a tailored financial plan to BOEM, which will permit the use of forms of financial security other than surety bonds and pledges of treasury securities and allow companies to phase in funding of the additional security. We received notice from BOEM on December 29, 2016 ordering the Company to secure financial assurances in the form of additional security in the amount of $0.5 million. Subsequent to the December 29, 2016 order, BOEM has rescinded that order and all others dated December 29, 2016 until further notice. We remain in active discussion with our government regulators and industry peers with regard to any future rule making and financial assurance requirements. Notwithstanding BOEM’s July 2016 NTL, BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The future cost of compliance with our existing supplemental bonding requirements, the July 2016 NTL, as well as any other future BOEM directives or any other changes to BOEM’s rules applicable to us or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows, and results of operations. Subsequent event. Other Commitments On February 19, 2013, we signed a three-year agreement to use Helix’s Q4000 vessel (the “Q4000”) or equivalent substitute, a dynamic positioning semi-submersible vessel specifically designed for well intervention and construction. The contract was effective beginning on January 1, 2015 and was amended January 9, 2017. The Q4000 is expected to be utilized for certain deep water well intervention and decommissioning activities for properties operated by the Company. Under the amended terms of the agreement, the Company will pay Helix a base vessel day work rate based on the number of days contracted at a minimum of 20 days per contract year through 2019. As of December 31, 2017 the total estimated minimum payments in 2018 and 2019 are approximately $6.5 million and $6.7 million, respectively. We had no drilling rig commitments with a term that exceed one year as of December 31, 2017. Future minimum payments for drilling rig commitments as of December 31, 2017 were $3.9 million. Subsequent event. Office Lease Obligations On December 13, 2017, we entered into an eleven year operating lease beginning August 2018 for office space at Three Allen Center in Houston, Texas. In addition to the office lease executed in 2017, we have office leases in Houston, Texas; Dallas, Texas; Dulac, Louisiana and Mexico. Total future minimum lease payments in 2018, 2019, 2020, 2021 and thereafter are $4.1 million, $4.3 million, $3.8 million, $3.8 million and $30.5 million, respectively.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Condensed Consolidating Financial Information	Note 12—Condensed Consolidating Financial Information Talos owns no operating assets and has no operations independent of its subsidiaries and owns 100% of the Talos Issuers. The Talos Issuers issued 11.00% Senior Secured Notes on May 10, 2018, which are fully and unconditionally guaranteed, jointly and severally, by Talos and certain 100% owned subsidiaries (“Guarantors”) on a senior secured basis. Certain of the Company’s subsidiaries which are accounted for on a consolidated basis do not guarantee the 11.00% Senior Secured Notes (“Non-Guarantors”). The following condensed consolidating financial information presents the financial information of the Company on an unconsolidated stand-alone basis and its combined subsidiary issuers, combined guarantor and combined non-guarantor subsidiaries as of and for the periods indicated. As described in Note 1 – Formation and Basis of Presentation TALOS ENERGY INC. CONDENSED CONSOLIDATING BALANCE SHEET AS OF JUNE 30, 2018 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ 35,385 $ 40,940 $ 2,535 $ — $ 78,860 Restricted cash — — 1,244 — — 1,244 Accounts receivable, net Trade, net — — 100,824 — — 100,824 Joint interest, net — — 6,638 1,756 — 8,394 Other — — 832 6,259 — 7,091 Assets from price risk management activities — 478 21 — — 499 Prepaid assets — — 51,672 26 — 51,698 Income tax receivable — — 16,212 — — 16,212 Other current assets — — 3,910 — — 3,910 Total current assets — 35,863 222,293 10,576 — 268,732 Property and equipment: Proved properties — — 3,412,875 — — 3,412,875 Unproved properties, not subject to amortization — — 70,590 33,246 — 103,836 Other property and equipment — 27,293 1,580 11 — 28,884 Total property and equipment — 27,293 3,485,045 33,257 — 3,545,595 Accumulated depreciation, depletion and amortization — (7,080 ) (1,540,566 ) (10 ) — (1,547,656 ) Total property and equipment, net — 20,213 1,944,479 33,247 — 1,997,939 Other long-term assets: Assets from price risk management activities — 234 — — — 234 Other well equipment inventory — — 9,021 — — 9,021 Investments in subsidiaries 685,845 1,440,601 — — (2,126,446 ) — Other assets — 364 7,712 67 — 8,143 Total assets $ 685,845 $ 1,497,275 $ 2,183,505 $ 43,890 $ (2,126,446 ) $ 2,284,069 LIABILITIES AND STOCKHOLDERS’ Current liabilities: Accounts payable $ — $ 9,894 $ 28,728 $ 109 $ — $ 38,731 Accrued liabilities — 4,235 150,206 1,461 — 155,902 Accrued royalties — — 28,508 — — 28,508 Current portion of long-term debt — 434 — — — 434 Current portion of asset retirement obligations — — 94,334 — — 94,334 Liabilities from price risk management activities — 141,118 13,604 — — 154,722 Accrued interest payable — 7,064 390 — — 7,454 Other current liabilities — — 15,541 — — 15,541 Total current liabilities — 162,745 331,311 1,570 — 495,626 Long-term debt, net of discount and deferred financing costs — 621,908 6,060 — — 627,968 Asset retirement obligations — — 320,044 — — 320,044 Liabilities from price risk management activities — 26,777 4,989 — — 31,766 Other long-term liabilities — — 122,820 — — 122,820 Total liabilities — 811,430 785,224 1,570 — 1,598,224 Commitments and Contingencies (Note 10) Stockholders’ equity (deficit) 685,845 685,845 1,398,281 42,320 (2,126,446 ) 685,845 $ 685,845 $ 1,497,275 $ 2,183,505 $ 43,890 $ (2,126,446 ) $ 2,284,069 TALOS ENERGY INC. CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2017 (In thousands) Talos Talos Issuers Guarantors Non- 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 10) 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. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2018 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated Revenues: Oil revenue $ — $ — $ 180,161 $ — $ — $ 180,161 Natural gas revenue — — 16,448 — — 16,448 NGL revenue — — 7,297 — — 7,297 Total revenue — — 203,906 — — 203,906 Operating expenses: Direct lease operating expense — — 34,060 — — 34,060 Insurance — — 4,259 — — 4,259 Production taxes — — 564 — — 564 Total lease operating expense — — 38,883 — — 38,883 Workover and maintenance expense — — 17,714 — — 17,714 Depreciation, depletion and amortization — 384 67,341 1 — 67,726 Accretion expense — — 9,492 — — 9,492 General and administrative expense — 13,804 16,854 222 — 30,880 Total operating expenses — 14,188 150,284 223 — 164,695 Operating income (loss) — (14,188 ) 53,622 (223 ) — 39,211 Interest expense — (14,399 ) (6,891 ) (388 ) — (21,678 ) Price risk management activities expense — (89,970 ) (1,206 ) — — (91,176 ) Other income (expense) — (1,358 ) 132 (43 ) — (1,269 ) Equity earnings from subsidiaries (74,912 ) 45,003 — — 29,909 — Net income (loss) $ (74,912 ) $ (74,912 ) $ 45,657 $ (654 ) $ 29,909 $ (74,912 ) TALOS ENERGY INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2018 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated Revenues: Oil revenue $ — $ — $ 307,854 $ — $ — $ 307,854 Natural gas revenue — — 29,171 — — 29,171 NGL revenue — — 12,731 — — 12,731 Total revenue — — 349,756 — — 349,756 Operating expenses: Direct lease operating expense — — 58,975 — — 58,975 Insurance — — 6,934 — — 6,934 Production taxes — — 955 — — 955 Total lease operating expense — — 66,864 — — 66,864 Workover and maintenance expense — — 24,619 — — 24,619 Depreciation, depletion and amortization — 725 116,039 2 — 116,766 Accretion expense — — 14,252 — — 14,252 General and administrative expense — 18,398 20,567 495 — 39,460 Total operating expenses — 19,123 242,341 497 — 261,961 Operating income (loss) — (19,123 ) 107,415 (497 ) — 87,795 Interest expense — (26,627 ) (13,957 ) (836 ) — (41,420 ) Price risk management activities expense — (139,217 ) (3,935 ) — — (143,152 ) Other income (expense) — (1,208 ) 85 45 — (1,078 ) Equity earnings from subsidiaries (97,855 ) 88,320 — — 9,535 — Net income (loss) $ (97,855 ) $ (97,855 ) $ 89,608 $ (1,288 ) $ 9,535 $ (97,855 ) TALOS ENERGY INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2017 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated Revenues: Oil revenue $ — $ — $ 78,719 $ — $ — $ 78,719 Natural gas revenue — — 12,888 — — 12,888 NGL revenue — — 3,436 — — 3,436 Other — — 383 — — 383 Total revenue — — 95,426 — — 95,426 Operating expenses: Direct lease operating expense — — 28,871 — — 28,871 Insurance — — 2,688 — — 2,688 Production taxes — — 380 — — 380 Total lease operating expense — — 31,939 — — 31,939 Workover and maintenance expense — — 8,225 — — 8,225 Depreciation, depletion and amortization — 353 35,803 1 — 36,157 Accretion expense — — 5,321 — — 5,321 General and administrative expense — 3,775 3,531 164 — 7,470 Total operating expenses — 4,128 84,819 165 — 89,112 Operating income (loss) — (4,128 ) 10,607 (165 ) — 6,314 Interest expense — (11,487 ) (7,695 ) (1,623 ) — (20,805 ) Price risk management activities income — 36,040 2,955 — — 38,995 Other income (expense) — 150 (87 ) 40 — 103 Equity earnings from subsidiaries 24,607 4,032 — — (28,639 ) — Net income (loss) $ 24,607 $ 24,607 $ 5,780 $ (1,748 ) $ (28,639 ) $ 24,607 TALOS ENERGY INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2017 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated Revenues: Oil revenue $ — $ — $ 162,487 $ — $ — $ 162,487 Natural gas revenue — — 26,062 — — 26,062 NGL revenue — — 7,069 — — 7,069 Other — — 1,632 — — 1,632 Total revenue — — 197,250 — — 197,250 Operating expenses: Direct lease operating expense — — 56,735 — — 56,735 Insurance — — 5,409 — — 5,409 Production taxes — — 645 — — 645 Total lease operating expense — — 62,789 — — 62,789 Workover and maintenance expense — — 17,047 — — 17,047 Depreciation, depletion and amortization — 722 75,364 2 — 76,088 Accretion expense — — 10,509 — — 10,509 General and administrative expense — 10,166 6,621 429 — 17,216 Total operating expenses — 10,888 172,330 431 — 183,649 Operating income (loss) — (10,888 ) 24,920 (431 ) — 13,601 Interest expense — (23,501 ) (14,723 ) (1,353 ) — (39,577 ) Price risk management activities expense — 81,541 3,347 — — 84,888 Other income (expense) — 300 (162 ) 19 — 157 Equity earnings from subsidiaries 59,069 11,617 — — (70,686 ) — Net income (loss) $ 59,069 $ 59,069 $ 13,382 $ (1,765 ) $ (70,686 ) $ 59,069 TALOS ENERGY INC. CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2018 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ (54,941 ) $ 160,304 $ 1,748 $ — $ 107,111 Cash flows from investing activities: Exploration, development, and other capital expenditures — (20,027 ) (117,667 ) (3,274 ) — (140,968 ) Cash paid for acquisitions, net of cash acquired — — 293,001 — — 293,001 Investments in subsidiaries — (384,089 ) — — 384,089 — Distributions from subsidiaries — 677,573 9 — (677,582 ) — Net cash provided by (used in) investing activities — 273,457 175,343 (3,274 ) (293,493 ) 152,033 Cash flows from financing activities: Redemption of 2018 Senior Notes — (24,977 ) (69 ) — — (25,046 ) Proceeds from Bank Credit Facility — 294,000 — — — 294,000 Repayment of Bank Credit Facility — (54,000 ) — — — (54,000 ) Repayment of Old Bank Credit Facility — (403,000 ) — — (403,000 ) Deferred financing costs — (17,469 ) — — — (17,469 ) Payments of capital lease — — (6,958 ) — — (6,958 ) Capital contributions — — 382,089 2,000 (384,089 ) — Distributions to subsidiary issuer — — (677,573 ) (9 ) 677,582 — Net cash provided by (used in) financing activities — (205,446 ) (302,511 ) 1,991 293,493 (212,473 ) Net increase (decrease) in cash, cash equivalents and restricted cash — 13,070 33,136 465 — 46,671 Cash, cash equivalents and restricted cash: Balance, beginning of period — 22,315 9,048 2,070 — 33,433 Balance, end of period $ — $ 35,385 $ 42,184 $ 2,535 $ — $ 80,104 TALOS ENERGY INC. CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2017 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ (16,268 ) $ 84,651 $ 16,880 $ — $ 85,263 Cash flows from investing activities: Exploration, development, and other capital expenditures — (73 ) (54,770 ) (7,692 ) — (62,535 ) Cash paid for acquisitions, net of cash acquired — — (2,244 ) — — (2,244 ) Investments in subsidiaries — (287,689 ) — — 287,689 — Distributions from subsidiaries — 292,580 1,527 — (294,107 ) — Net cash provided by (used in) investing activities — 4,818 (55,487 ) (7,692 ) (6,418 ) (64,779 ) 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 — — (5,870 ) — — (5,870 ) Capital contributions — — 279,689 8,000 (287,689 ) — Distributions to subsidiaries — — (292,580 ) (1,527 ) 294,107 — Net cash provided by (used in) financing activities — (6,000 ) (18,761 ) 6,473 6,418 (11,870 ) Net increase (decrease) in cash, cash equivalents and restricted cash — (17,450 ) 10,403 15,661 — 8,614 Cash, cash equivalents and restricted cash: Balance, beginning of period — 24,349 6,752 2,332 — 33,433 Balance, end of period $ — $ 6,899 $ 17,155 $ 17,993 $ — $ 42,047	Note 11—Condensed Consolidating Financial Information Talos Energy Inc. (“Parent”) owns no operating assets and has no operations independent of its subsidiaries. Talos Production LLC and Talos Production Finance Inc. (“Subsidiary Issuers”) are 100% owned by the Parent. The Subsidiary Issuers issued 11.00% Second-Priority Senior Secured Notes (“11.00% Notes”) on May 10, 2018, which are fully and unconditionally guaranteed, jointly and severally, by the Parent and certain 100% owned subsidiaries (“Guarantors”) on a senior secured basis. Certain of the Company’s subsidiaries which are accounted for on a consolidated basis do not guarantee the 11.00% Notes (“Non-Guarantors”). The following condensed consolidating financial information presents the financial information of the Company on an unconsolidated stand-alone basis and its combined subsidiary issuers, combined guarantor and combined non-guarantor subsidiaries as of and for the periods indicated. As described in Note 15 – Subsequent Change in Reporting Entity and Financial Statement Presentation TALOS ENERGY INC. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED 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 10) 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. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2016 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ 24,349 $ 5,550 $ 2,332 $ — $ 32,231 Restricted cash — — 1,202 — — 1,202 Accounts receivable, net Trade, net — — 52,764 — — 52,764 Joint interest, net — — 7,569 7,104 — 14,673 Other — 9,476 531 2,393 — 12,400 Assets from price risk management activities — 20,176 — — — 20,176 Prepaid assets — — 18,411 9 — 18,420 Inventory — — 1,093 — — 1,093 Other current assets — — 2,492 — — 2,492 Total current assets — 54,001 89,612 11,838 — 155,451 Property and equipment: Proved properties — — 2,235,835 — — 2,235,835 Unproved properties, not subject to amortization — — 64,949 7,411 — 72,360 Other property and equipment — 7,007 1,513 11 — 8,531 Total property and equipment — 7,007 2,302,297 7,422 — 2,316,726 Accumulated depreciation, depletion and amortization — (4,954 ) (1,268,580 ) (4 ) — (1,273,538 ) Total property and equipment, net — 2,053 1,033,717 7,418 — 1,043,188 Other long-term assets: Assets from price risk management activities — 293 — — — 293 Other well equipment inventory — — 12,744 — — 12,744 Investments in subsidiaries 6,986 700,385 — — (707,371 ) — Other assets — 48 574 — — 622 Total assets $ 6,986 $ 756,780 $ 1,136,647 $ 19,256 $ (707,371 ) $ 1,212,298 LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current liabilities: Accounts payable $ — $ 133 $ 27,570 $ 3,527 $ — $ 31,230 Accrued liabilities — 1,208 48,318 390 — 49,916 Accrued royalties — — 23,293 — — 23,293 Current portion of asset retirement obligations — — 33,556 — — 33,556 Liabilities from price risk management activities — 27,147 — — — 27,147 Accrued interest payable — 11,376 — — — 11,376 Other current liabilities — — 14,666 — — 14,666 Total current liabilities — 39,864 147,403 3,917 — 191,184 Long-term debt, net of discount and deferred financing costs — 701,175 — — — 701,175 Asset retirement obligations — — 186,493 — — 186,493 Liabilities from price risk management activities — 8,755 — — — 8,755 Other long-term liabilities — — 117,705 — — 117,705 Total liabilities — 749,794 451,601 3,917 — 1,205,312 Commitments and Contingencies (Note 10) Stockholders’ equity (deficit) 6,986 6,986 685,046 15,339 (707,371 ) 6,986 $ 6,986 $ 756,780 $ 1,136,647 $ 19,256 $ (707,371 ) $ 1,212,298 TALOS ENERGY INC. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED 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. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED 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. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2015 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 244,167 $ — $ — $ 244,167 Natural gas revenue — — 55,026 — — 55,026 NGL revenue — — 10,523 — — 10,523 Other — — 5,890 — — 5,890 Total revenue — — 315,606 — — 315,606 Operating expenses: Direct lease operating expense — — 171,095 — — 171,095 Insurance — — 17,965 — — 17,965 Production taxes — — 3,311 — — 3,311 Total lease operating expense — — 192,371 — — 192,371 Workover and maintenance expense — — 29,752 — — 29,752 Depreciation, depletion and amortization — 1,528 211,161 — — 212,689 Write-down of oil and natural gas properties — — 603,388 — — 603,388 Accretion expense — — 19,395 — — 19,395 General and administrative expense — 19,630 14,541 1,491 — 35,662 Total operating expenses — 21,158 1,070,608 1,491 — 1,093,257 Operating loss — (21,158 ) (755,002 ) (1,491 ) — (777,651 ) Interest expense — (46,235 ) (4,080 ) (1,229 ) — (51,544 ) Price risk management activities income — 182,196 — — — 182,196 Other income — 129 176 9 — 314 Equity earnings from subsidiaries (646,685 ) (761,617 ) — — 1,408,302 — Net income (loss) $ (646,685 ) $ (646,685 ) $ (758,906 ) $ (2,711 ) $ 1,408,302 $ (646,685 ) TALOS ENERGY INC. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED 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. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED 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 TALOS ENERGY INC. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2015 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by operating activities $ — $ 81,598 $ 55,946 $ 822 $ — $ 138,366 Cash flows from investing activities: Exploration, development, and other capital expenditures — (2,380 ) (242,203 ) (1,133 ) — (245,716 ) Cash paid for acquisitions, net of cash acquired — — (39,423 ) — — (39,423 ) Investments in subsidiaries (73,500 ) (579,822 ) — — 653,322 — Distributions from subsidiaries — 300,891 — — (300,891 ) — Net cash provided by (used in) investing activities (73,500 ) (281,311 ) (281,626 ) (1,133 ) 352,431 (285,139 ) Cash flows from financing activities: Proceeds from Bank Credit Facility — 120,000 — — — 120,000 Repayment of Bank Credit Facility — (30,000 ) — — — (30,000 ) Repayment of GCER Bank Credit Facility — — (55,000 ) — — (55,000 ) Deferred financing costs — (269 ) — — — (269 ) Capital contributions — 73,500 578,643 1,179 (653,322 ) — Distributions to subsidiaries — — (300,779 ) (112 ) 300,891 — Contributions from Sponsors 75,000 — — — — 75,000 Distributions to Sponsors (1,500 ) — — — — (1,500 ) Net cash provided by (used in) financing activities 73,500 163,231 222,864 1,067 (352,431 ) 108,231 Net increase (decrease) in cash, cash equivalents and restricted cash — (36,482 ) (2,816 ) 756 — (38,542 ) Cash, cash equivalents and restricted cash Balance, beginning of period — 44,552 18,594 — — 63,146 Balance, end of period $ — $ 8,070 $ 15,778 $ 756 $ — $ 24,604

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data (Unaudited)	Note 12—Selected Quarterly Financial Data (Unaudited) Unaudited quarterly financial data are as follows (in thousands): March 31 June 30 September 30 December 31 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 ) Quarter Ended 2016 Revenues $ 50,656 $ 67,405 $ 63,775 $ 76,918 Operating loss $ (40,011 ) $ (20,697 ) $ (12,868 ) $ (7,103 ) Price risk management activities income (expense) $ 12,924 $ (48,930 ) $ 11,350 $ (32,742 ) Net loss $ (40,799 ) $ (84,715 ) $ (22,219 ) $ (60,354 )

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Supplemental Oil and Gas Disclosures (Unaudited)	Note 13—Supplemental Oil and Gas Disclosures (Unaudited) Capitalized Costs Aggregate amounts of capitalized costs relating to our oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion, depreciation and amortization as of the dates indicated are presented below (in thousands): December 31, 2017 2016 Proved properties $ 2,440,811 $ 2,235,835 Unproved oil and gas properties, not subject to amortization 72,002 72,360 Total oil and gas properties 2,512,813 2,308,195 Less: Accumulated depletion and amortization (1,423,829 ) (1,268,276 ) Net capitalized costs $ 1,088,984 $ 1,039,919 Depletion and amortization rate per Boe $ 14.85 $ 13.82 Included in the depletable basis of our proved oil and gas properties is the estimate of our 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, 2017 and 2016 our oil and gas asset retirement obligations totaled $214.7 million and $220.0 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, 2017 2016 2015 Property acquisition costs: Proved properties $ 1,108 $ 77,906 $ 68,463 Unproved properties, not subject to amortization 5,778 15,919 39,265 Total property acquisition costs 6,886 93,825 107,728 Exploration costs 82,887 27,807 25,908 Development costs 114,846 195,869 228,257 Total costs incurred $ 204,619 $ 317,501 $ 361,893 Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves We have employed 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. Our engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. Our Director of Reserves, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all of our oil and natural gas fields. All of the Company’s proved oil, natural gas and NGL reserves are located offshore in the Gulf of Mexico and lower Gulf Coast regulated by the United States, the State of Louisiana, or the State of Texas. At December 31, 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 our reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists. At December 31, 2015, 100% of proved oil, natural gas and NGL reserves attributable to our net interests in legacy oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by Ryder Scott, independent petroleum engineers and geologists and 100% of proved oil, natural gas and NGL reserves attributable to the assets acquired in the GCER Acquisition were estimated and compiled for reporting purposes by our reservoir engineers and audited by NSAI. The following table presents our estimated proved reserves at our net ownership interest: Oil Gas NGL Oil Equivalent (MBoe) Total proved reserves at December 31, 2014 46,120 136,232 4,096 72,921 Revision of previous estimates (3,435 ) (22,580 ) 207 (6,991 ) Production (5,161 ) (21,458 ) (588 ) (9,325 ) Purchases of reserves 4,029 30,527 385 9,502 Extensions and discoveries 4,801 6,503 481 6,366 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 Total proved developed reserves as of: December 31, 2015 33,016 90,432 3,383 51,471 December 31, 2016 45,753 96,122 4,032 65,805 December 31, 2017 37,460 77,577 3,315 53,704 Total proved undeveloped reserves as of: December 31, 2015 13,338 38,792 1,198 21,002 December 31, 2016 26,613 54,482 2,204 37,897 December 31, 2017 35,344 50,079 3,232 46,921 (1) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. During 2017, the Company added 12.5 MMBoe of estimated proved reserves from extensions and discoveries primarily from drilling our Tornado II exploration prospect. These were 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 asset transaction of 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. During 2015, the Company added 9.5 MMBoe of estimated proved reserves through purchases of reserves consisting of 5.1 MMBoe and 4.4 MMBoe in estimated proved reserves acquired in the GCER Acquisition and DGE Acquisition, respectively. Downward revisions of previous estimates of 7.0 MMBoe were primarily due to the significant decline in commodity prices resulting in uneconomic reserves. 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 our interest in proved oil, natural gas and NGL reserves (in thousands): December 31, 2017 2016 2015 Future cash inflows $ 4,308,863 $ 3,390,612 $ 2,786,828 Future costs: Production (815,509 ) (775,354 ) (1,363,585 ) Development and abandonment (823,164 ) (664,254 ) (646,161 ) Future net cash flows before income taxes 2,670,190 1,951,004 777,082 Future income tax expense — — — Future net cash flows before income taxes 2,670,190 1,951,004 777,082 Discount at 10% annual rate (862,521 ) (614,969 ) (174,101 ) Standardized measure of discounted future net cash flows $ 1,807,669 $ 1,336,035 $ 602,981 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 our derivative instruments. See the following table for base prices used in determining the standardized measure: Year Ended December 31, 2017 2016 2015 Oil price per Bbl $ 51.36 $ 40.02 $ 50.72 Natural gas prices per Mcf $ 3.20 $ 2.66 $ 2.75 NGL price per Bbl $ 24.64 $ 14.96 $ 17.60 Future net cash flows are discounted at the prescribed rate of 10%. We caution that actual future net cash flows may vary considerably from these estimates. Although our 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 our 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 our proved oil, natural gas and NGL reserves are as follows (in thousands): Year Ended December 31, 2017 2016 2015 Standardized measure, beginning of year $ 1,336,035 $ 602,981 $ 1,888,958 Changes during the year: Sales, net of production costs (288,942 ) (114,625 ) (117,344 ) Net change in prices and production costs 555,100 80,174 (1,879,436 ) Changes in future development costs (156,282 ) 2,292 92,182 Development costs incurred 146,687 108,484 273,532 Accretion of discount 133,603 60,298 188,896 Net change in income taxes — — — Purchases of reserves — 222,581 229,052 Extensions and discoveries 328,565 479,833 91,722 Sales of reserves — — — Net change due to revision in quantity estimates (113,629 ) (5,685 ) (103,842 ) Changes in production rates (timing) and other (133,468 ) (100,298 ) (60,739 ) Total 471,634 733,054 (1,285,977 ) Standardized measure, end of year $ 1,807,669 $ 1,336,035 $ 602,981

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	Note 14—Subsequent Events Derivative Contracts For additional information, see Note 5— Financial Instruments Bank Credit Facility For additional information, see Note 6— Debt 2018 Senior Notes For additional information, see Note 6— Debt Performance Obligations For additional information, see Note 10— Commitments and Contingencies Other Commitments For additional information, see Note 10— Commitments and Contingencies

Subsequent Change in Reporting

Subsequent Change in Reporting Entity and Financial Statement Presentation	12 Months Ended
	Dec. 31, 2017
Subsequent Change In Reporting Entity And Financial Statement Presentation [Abstract]
Subsequent Change in Reporting Entity and Financial Statement Presentation	Note 15—Subsequent Change in Reporting Entity and Financial Statement Presentation On May 10, 2018, Talos Energy Inc. consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), as discussed in Note 3— Acquisitions The financial information included in the financial statements is that of Talos Energy LLC prior to the Stone Combination because the Stone Combination was consummated after the period covered by these financial statements. Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. 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 Apollo Management VII, L.P. and Apollo Commodities Management, L.P. and an entity affiliated with Riverstone Energy Partners V, L.P., each of which hold common stock of the Company. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Equity to reflect the legal capital of Talos Energy Inc. 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 as such the financial statements are named Talos Energy Inc. (formerly known as Talos Energy LLC).

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
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 Gulf of Mexico and in the shallow waters off the coast of Mexico. The Company’s focus in the Gulf of Mexico is the exploration, acquisition, exploitation and development of deep and shallow water assets near existing infrastructure. The shallow waters off the coast of Mexico provide the Company high impact exploration opportunities in an emerging basin. The Company uses its access to an extensive seismic database and its deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. The Company’s management and technical teams have a long history working together and have made significant discoveries in the deep and shallow waters in the Gulf of Mexico and in the shallow waters off the coast of Mexico. 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”), among Stone Energy Corporation (“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, Sailfish Energy Holdings Corporation did not conduct any material activities other than those incident to its formation and the matters contemplated by the Transaction Agreement. Substantially concurrent with the consummation of the transactions, the name of the Company was changed from Sailfish Energy Holdings Corporation to Talos Energy Inc. Pursuant to the Transaction Agreement, a series of transactions occurred on the Closing Date (the “Closing”), including the following: (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) in a series of contributions, entities related to Apollo Management VII, L.P. and Apollo Commodities Management, L.P. with respect to Series I (“Apollo Funds”), and Riverstone Energy Partners V, L.P. (“Riverstone Funds”) 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 the 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. 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. Unless otherwise indicated or the context otherwise requires, references herein to “us,” “we,” “our” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.	Formation and Nature of Business Talos Energy LLC was formed in 2011. Upon formation, Talos Energy Operating Company LLC; Talos Energy Offshore LLC; Talos Energy Operating GP, LLC; Talos Energy Holdings LLC; and Talos Production LLC became wholly-owned subsidiaries of Talos Energy LLC. Talos Production Finance Inc. was formed on January 15, 2013 as a wholly-owned subsidiary of Talos Energy LLC. Unless otherwise indicated or the context otherwise requires, references in this report to “us,” “we,” “our” or the “Company” are to Talos Energy LLC and its wholly-owned subsidiaries. On February 6, 2013, we acquired all of the equity of Energy Resource Technology GOM, LLC (“ERT”) and its subsidiary from Helix Energy Solutions Group, Inc. (“Helix”) for approximately $625.2 million (inclusive of purchase price and working capital adjustments of approximately $15.2 million), and payments for ongoing guarantees from Helix to third-parties. Additionally, the Company agreed to assign Helix an overriding royalty interest in certain properties acquired in the transaction at closing. We refer to this purchase as the “ERT Acquisition.” The ERT Acquisition was effective December 1, 2012 and closed on February 6, 2013. Prior to the closing of the ERT Acquisition, Energy Resource Technology GOM, Inc. and its wholly-owned subsidiary, CKB Petroleum, Inc., were each converted into Delaware limited liability companies, and as a result changed their names to Energy Resource Technology GOM, LLC and CKB Petroleum, LLC, respectively. On February 3, 2012, the Company completed a transaction with funds affiliated with, and controlled by, Apollo Global Management LLC (together with its consolidated subsidiaries, “Apollo”), funds affiliated with, and controlled by, Riverstone Holdings, LLC (together with its affiliates, “Riverstone” and together with Apollo, our “Sponsors”) and members of management pursuant to which the Company received a private equity capital commitment, which may be increased up to $600 million with approval from the Company’s Board of Directors. Prior to the closing of the ERT Acquisition, our Sponsors and members of management had invested an aggregate of approximately $325 million in the Company to fund a portion of the ERT Acquisition as well as to fund other asset purchases. In connection with the ERT Acquisition, the Company also issued $300 million aggregate principal amount of 9.75% Senior Notes due February 15, 2018 (the “2018 Senior Notes”) at a discount of 0.975%, (see Note 6— Debt The Company commenced commercial operations on February 6, 2013. Prior to February 6, 2013, the Company had incurred certain general and administrative expenses associated with the start-up of its operations. We are a technically driven independent exploration and production company with operations in the Gulf of Mexico and in the shallow waters off the coast of Mexico. Our focus in the Gulf of Mexico is the exploration, acquisition and development of deep and shallow water assets near existing infrastructure. The shallow waters off the coast of Mexico provide us high impact exploration opportunities in an emerging basin. We use our access to an extensive seismic database and our deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. Our management and technical teams have a long history working together and have made significant discoveries in the deep and shallow waters in the Gulf of Mexico and in the shallow waters off the coast of Mexico. The Company shall continue until it is liquidated or dissolved in accordance with the Limited Liability Company Agreement of Talos Energy LLC, as amended and restated (the “LLC Agreement”).
Basis of Presentation and Consolidation	Basis of Presentation and Consolidation The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) as applied to interim financial statements and include each subsidiary from the date of inception. Because this is an interim periodic report presented using a condensed format, it does not include all of the annual disclosures required by GAAP. 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 cover periods prior to the Closing Date, reflects the assets, liabilities and operations of Talos Energy LLC prior to the Closing Date and does not reflect the assets, liabilities and operations of Stone prior to the Closing Date. These condensed consolidated financial statements should be read in conjunction with Talos Energy LLC’s audited financial statements and the notes thereto for the year ended December 31, 2017, which are included elsewhere in this prospectus. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statement of Changes in Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the business combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos. All intercompany transactions have been eliminated. All adjustments that are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the interim periods are reflected herein. The results for any interim period are not necessarily indicative of the expected results for the entire year. The Company has evaluated subsequent events through the date the condensed consolidated financial statements were issued. For presentation purposes, as of June 30, 2018, certain balances previously disclosed as “Accounts payable” and “Other current assets” have been reclassified to “Accrued liabilities” and “Prepaid assets”, respectively. The corresponding balances as of December 31, 2017 of $73.5 million and $7.3 million were reclassified to “Accrued liabilities” and “Prepaid assets”, respectively. The balance sheet reclass between “Accounts payable” and “Accrued liabilities” is related to estimates of operating costs incurred but not yet invoiced. 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. During September 2015, the Company expanded its acreage position to include two shallow water exploration blocks off the coast of Mexico and drilled its first well in those blocks in July 2017. The business activities in Mexico, which are currently deemed immaterial, have been combined with the United States and reported as one segment. See additional information in Note 4— Property, Plant and Equipment	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 material intercompany transactions have been eliminated. All adjustments that are of a normal, recurring nature and are necessary to fairly present the Company’s financial position, results of operations and cash flows for the periods are reflected. 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. During September 2015, the Company expanded its acreage position to include two shallow water exploration blocks off the coast of Mexico and drilled our first well in July 2017. The business activities in Mexico have been combined with the United States and reported as one segment. See additional information in “Note 4— Property, Plant and Equipment
Recently Adopted Or Issued Accounting Standards	Recently Adopted Accounting Standards Impact of the Adoption of ASC 606—Revenue from Contracts with Customers 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 does not disclose the value of unsatisfied performance obligations for contracts with an original expected length of one year or less or contracts for which variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Gas Imbalances. Production Handling Fees. Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Boards (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842). Leases	Recently Adopted Accounting Standards In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805)—Clarifying the Definition of a Business Acquisitions In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash Recently Issued Accounting Standards In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Revenue Recognition Extractive Activities—Oil and Gas—Revenue Recognition
Cash and Cash Equivalents		Cash and Cash Equivalents We reflect our cash as cash and cash equivalents on our consolidated balance sheets. We consider 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 plus accrued interest, 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 $5.9 million at December 31, 2017 and $4.9 million at December 31, 2016, which approximates fair value. We establish provisions for losses on accounts receivable and for natural gas imbalances with other parties if we believe that we will not collect all or part of the outstanding balance. On a quarterly basis we review collectability and establish or adjust our allowance as necessary using the specific identification method.
Other Current Assets		Other Current Assets Other current assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”). The deposits are estimates related to royalties which we are required to pay the ONRR within thirty days of the production rate. On a monthly basis we adjust the deposit based on actual royalty payments remitted to the ONRR.
Inventory		Inventory Inventory primarily represents oil in lease tanks and line fill in pipelines. Our inventory is stated at the net realizable value. Sales of oil are accounted for by a weighted average cost method whereby oil sold from inventory is relieved at the weighted average cost of oil remaining in inventory.
Revenue Recognition and Imbalances		Revenue Recognition and Imbalances We record revenues from the sale of oil, natural gas and natural gas liquids (“NGLs”) based on quantities of production sold to purchasers under short-term contracts (less than 12 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. We have interests with other producers in certain properties. In these cases, we use the entitlement method to account for sales of production. Under the entitlement method, revenue is recorded when title passes based on our net interest. We may receive more or less than our entitled share of production, and we record our entitled share of revenues based on entitled volumes and contracted sales prices. If we receive more than our entitled share of production, the imbalance is recorded as a liability in accrued liabilities on the consolidated balance sheets. If we receive less than our entitled share, the imbalance is recorded as an asset in other current assets on the consolidated balance sheets. Our imbalances are recorded gross on our consolidated balance sheets. At December 31, 2017, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.7 million. At December 31, 2016, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.8 million. At December 31, 2015, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.6 million. We record the gross amount of reimbursements for costs from third parties as other revenues whenever the Company is the primary obligor with respect to the source of such costs, has discretion in the selection of how the related costs are incurred and when it has assumed the credit risk associated with the reimbursement for such costs. The costs associated with these third-party reimbursements are also recorded within the applicable cost and expenses line item in the consolidated statements of operations. Our other revenues have been generated primarily through fees for processing third-party production through some of our production facilities.
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 our 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 10— 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, wells currently drilling and capitalized interest are initially excluded from the amortizable base. We transfer unproved property costs into the amortizable base when properties are determined to have proved reserves or when we have completed an evaluation of the unproved properties resulting in an impairment. We evaluate 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 we own a direct interest. Our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. 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 our 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. We perform this ceiling test calculation each quarter. In accordance with the Securities and Exchange Commission (“SEC”) rules and regulations, we utilize SEC Pricing when performing the ceiling test. We also hold 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 resulted in a write-down of our oil and natural gas properties of nil, nil and $603.4 million during the years ended December 31, 2017, 2016 and 2015, respectively. 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 we sell or convey interests in oil and natural gas properties, we reduce our oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do 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. We treat sales proceeds on non-significant sales as reductions to the cost of our oil and natural gas properties. We recognize transportation costs as a component of direct lease operating expense when we are the shipper of the product. Such costs were $10.3 million, $9.1 million and $10.5 million in the years ended December 31, 2017, 2016 and 2015, 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 five years.
Other Well Equipment Inventory		Other Well Equipment Inventory Other well equipment inventory primarily represents the cost of equipment to be used in our oil and natural gas drilling and development activities such as drilling pipe, tubular 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. Our inventory is stated at net realizable value. We recorded $0.3 million, $0.2 million, $2.1 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, 2017, 2016 and 2015, 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— Level 2— Level 3— 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— Cost Approach— Income Approach— 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 We are required to record our 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. Our asset retirement obligations consist of estimated costs for dismantlement, removal, site reclamation and similar activities associated with our 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 our 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 derivatives to manage market risks resulting from fluctuations in prices of oil and natural gas. 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. We classify 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 our oil and natural gas operations, they are classified as cash flows from operating activities. We do not enter into derivative agreements for trading or other speculative purposes. The fair value of commodity derivatives reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. 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, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation, market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be favorable or unfavorable.
Equity Based Compensation	Share-Based Compensation The Company records share-based compensation associated with restricted stock units in general and administrative expense on the condensed consolidated statement of operations, net of amounts capitalized to oil and gas properties. Share-based compensation expense is based on the grant date fair value of issued restricted stock units recognized over the vesting period of the instrument. For each restricted stock unit grant, the Company determines whether the awards represent equity or liability based awards. The fair value of equity awards are determined based on the close price of the stock on the grant date. The fair value of the liability awards are remeasured at each reporting date based on the close price of the stock at such date, until the date of settlement. See Note 7— Employee Benefits Plans and Share Based Compensation .	Equity Based Compensation Certain of our employees participate in the equity based compensation plan of the Company. We measure 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 our employees and recognize compensation cost on a straight-line basis in our financial statements over the vesting period of each grant according to Accounting Standards Codification 718, Compensation—Stock Compensation.
Income Taxes	Income Taxes Prior to the Stone Combination, Talos Energy LLC was a partnership for federal income tax purposes and was not subject to federal income tax or state income tax (in most states). As such, Talos Energy LLC was not a taxpaying entity for federal income tax purposes and accordingly, did not recognize any expenses for such states. In connection with completing the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to 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 estimates utilized in recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating our valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, and 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 expenses, respectively.	Income Taxes The Company is a limited liability company and not subject to federal or state income tax (in most states). As such, the Company is not a taxpaying entity for federal income tax purposes and accordingly, does not recognize any expense for such taxes. The federal income tax liability resulting from the Company’s activities is the responsibility of the Company’s Sponsors and other Unit holders. The Company is subject to state income taxes in certain jurisdictions and under applicable state laws taxes are estimated to be immaterial. We operate in the shallow waters off the coast of Mexico under a different legal form. As a result, income taxes are provided for based upon the tax laws and rates in effect in the foreign tax authorities. Deferred income tax assets and liabilities are recorded for the expected future tax consequences of events that are recognized in our financial statements or tax returns. A valuation allowance is established to reduce deferred tax assets when it is more likely than not that the overall deferred tax asset will not be realized. At December 31, 2017 and December 31, 2016, the Company has a valuation allowances of $4.0 million and $2.3 million, which is the amount of deferred tax assets.
Concentration of Credit Risk		Concentration of Credit Risk Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents, restricted cash, accounts receivable and commodity derivatives. 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 experienced no losses on these accounts. Commodity derivatives are entered into with registered swap dealers, majority of which participate in our senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has experienced no losses due to counterparty default on these instruments. We market substantially all of our oil and natural gas production from properties we operate and those we do not operate. The majority of our oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. Our customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. We perform ongoing credit evaluations of our 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 our oil, natural gas and NGL revenues, was as follows: Year Ended December 31, 2017 2016 2015 Shell Trading (US) Company 80 % 68 % 68 % Chevron U.S.A Inc. * * 14 % 16 % ** less than 10% While the loss of Shell Trading (US) Company and Chevron U.S.A. Inc. as buyers might have a material effect on the Company in the short term, we believe that the Company would be able to obtain other customers for its oil, natural gas and NGL production.
Supplementary Cash Flow Information		Supplementary Cash Flow Information Supplementary cash flow information for each period presented was as follows (in thousands): Year Ended December 31, 2017 2016 2015 Supplemental Non-Cash Transactions: Capital expenditures included in accounts payable and accrued liabilities $ 40,626 $ 13,832 $ 30,125 Fair value of assets acquired $ — $ — $ 75,519 Fair value of liabilities assumed $ — $ — $ 75,519 Capital lease transaction $ — $ 124,300 $ — Supplemental Cash Flow Information: Interest paid, net of amounts capitalized $ 47,994 $ 55,254 $ 37,247
Earnings Per Common Share	Earnings Per Common Share Basic earnings per common share (“EPS”) is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of restricted stock unit grants and outstanding warrants. See Note 9— Earnings Per Share

Financial Instruments (Tables)

Financial Instruments (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Financial Instruments [Abstract]
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 June 30, 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 ) July 2018—December 2018 Swap 29,615 $ 54.06 $ — $ — July 2018—December 2018 Collar 1,000 $ — $ 45.00 $ 55.35 July 2018—December 2018 Put 2,000 $ — $ 49.50 $ — January 2019—December 2019 Swap 23,130 $ 54.14 $ — $ — Natural Gas—Henry Hub NYMEX: (MMBtu ) (per MMBtu ) (per MMBtu ) (per MMBtu ) July 2018—December 2018 Swap 23,747 $ 3.01 $ — $ — July 2018—December 2018 Collar 6,000 $ — $ 2.75 $ 3.24 January 2019—December 2019 Swap 10,146 $ 2.99 $ — $ —	The following table reflects the contracted volumes and weighted average prices we will receive under our derivative contracts as of December 31, 2017: Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Crude Oil—WTI: (Bbls ) (per Bbl ) January 2018—December 2018 Swap 24,804 $ 53.79 January 2019—December 2019 Swap 15,866 $ 53.17 Natural Gas—Henry Hub NYMEX: (MMBtu ) (per MMBtu ) January 2018—December 2018 Swap 26,346 $ 3.00 January 2019—December 2019 Swap 10,146 $ 2.99 Subsequent event. Production Period Instrument Type Average Daily Volumes Weighted Average Swap Price Crude Oil—WTI: (Bbls ) (per Bbl ) January 2019—June 2019 Swap 1,008 $ 56.25
Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments	The following table presents the carrying amounts and estimated fair values of financial instruments (in thousands): June 30, 2018 December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value 11.00% Second-Priority Senior Secured Notes—due April 2022(1) $ 380,042 $ 410,411 $ — $ — 7.50% Senior Secured Notes—due May 2022 $ 6,060 $ 5,999 $ — $ — Bank Credit Facility—due May 2022(1) $ 231,522 $ 240,000 $ — $ — 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 Old Bank Credit Facility—due February 2019(1) $ — $ — $ 402,062 $ 403,000 Oil and Natural Gas Derivatives $ (185,755 ) $ (185,755 ) $ (66,830 ) $ (66,830 ) (1) The carrying amounts are net of discount and deferred financing costs.	The following table presents the carrying amounts and estimated fair values of financial instruments (in thousands): December 31, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value 11.00% Bridge Loans—due April 2022 $ 169,838 $ 172,023 $ — $ — 9.75% Senior Notes—due July 2022 $ 100,681 $ 102,000 $ — $ — 9.75% Senior Notes—due February 2018 $ 24,977 $ 24,977 $ 294,964 $ 137,850 Bank Credit Facility $ 402,062 $ 403,000 $ 406,211 $ 408,000 Derivatives $ (66,830 ) $ (66,830 ) $ (15,433 ) $ (15,433 )
Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed Consolidated Statements of Operations	The following table presents the impact that derivatives not qualifying as hedging instruments had on the Company’s condensed consolidated statements of operations (in thousands): Three Months Ended Six Months Ended 2018 2017 2018 2017 Price risk management activities income (expense)(1) $ (91,176 ) $ 38,995 $ (143,152 ) $ 84,888 (2) The Company paid $33.6 million and received $9.2 million in net cash settlements for the three months ended June 30, 2018 and 2017, respectively, and paid $54.1 million and received $13.7 million in net cash settlements for the six months ended June 30, 2018 and 2017, respectively.	The following table presents the impact that derivatives not qualifying as hedging instruments had on our consolidated statements of operations (in thousands): Year Ended December 31, 2017 2016 2015 Price risk management activities income (expense)(1) $ (27,563 ) $ (57,398 ) $ 182,196 (1) The Company received net cash settlements of $23.8 million, $172.2 million and $181.9 million for the years ended December 31, 2017, 2016 and 2015, respectively.
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): June 30, 2018 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas derivatives $ — $ 733 $ — $ 733 Liabilities: Oil and natural gas derivatives — (186,488 ) — (186,488 ) Total net liability $ — $ (185,755 ) $ — $ (185,755 ) December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas derivatives $ — $ 1,908 $ — $ 1,908 Liabilities: Oil and natural gas derivatives — (68,738 ) — (68,738 ) Total net liability $ — $ (66,830 ) $ — $ (66,830 )	The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands): December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps $ — $ 1,908 $ — $ 1,908 Liabilities: Oil and natural gas swaps — (68,738 ) — (68,738 ) Total net liability $ — $ (66,830 ) $ — $ (66,830 ) December 31, 2016 Level 1 Level 2 Level 3 Total Assets: Oil and natural gas swaps and costless collars $ — $ 20,469 $ — $ 20,469 Liabilities: Oil and natural gas swaps and costless collars — (35,902 ) — (35,902 ) Total net liability $ — $ (15,433 ) $ — $ (15,433 )
Schedule of Fair Value of Derivative Financial Instruments	The following table presents the fair value of derivative financial instruments at June 30, 2018 and December 31, 2017 (in thousands): June 30, 2018 December 31, 2017 Assets from price risk management activities—current: Oil and natural gas derivatives $ 499 $ 1,563 Assets from price risk management activities—non-current: Oil and natural gas derivatives $ 234 $ 345 Liabilities from price risk management activities—current: Oil and natural gas derivatives $ 154,722 $ 49,957 Liabilities from price risk management activities—non-current: Oil and natural gas derivatives $ 31,766 $ 18,781	The following table presents the fair value of derivative financial instruments at December 31, 2017 and 2016 (in thousands): December 31, December 31, Assets from price risk management activities—current: Oil and natural gas derivatives $ 1,563 $ 20,176 Assets from price risk management activities—non-current: Oil and natural gas derivatives $ 345 $ 293 Liabilities from price risk management activities—current: Oil and natural gas derivatives $ 49,957 $ 27,147 Liabilities from price risk management activities—non-current: Oil and natural gas derivatives $ 18,781 $ 8,755

Debt (Tables)

Debt (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
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 June 30, 2018 December 31, 2017 11.00% Second-Priority Senior Secured Notes—due April 2022 Principal $ 390,868 $ — Original issue discount, net of amortization (8,906 ) — Deferred financing costs, net of amortization (1,920 ) — 7.50% Senior Secured Notes—due May 2022 Principal 6,060 — Bank Credit Facility—due May 2022 Principal 240,000 — Deferred financing costs, net of amortization (8,478 ) — 4.20% Building Loan—due November 2030 Principal 10,778 — 11.00% Bridge Loans—due April 2022 Principal — 172,023 Deferred financing costs, net of amortization — (2,185 ) 9.75% Senior Notes—due July 2022 Principal — 102,000 Deferred financing costs, net of amortization — (1,319 ) 9.75% Senior Notes—due February 2018 Principal — 24,977 Old Bank Credit Facility—due February 2019 — 403,000 Deferred financing costs, net of amortization — (938 ) Total debt $ 628,402 $ 697,558 Less: current portion of long-term debt (434 ) (24,977 ) Long-term debt, net of discount and deferred financing costs $ 627,968 $ 672,581	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, 2017 December 31, 2016 11.00% Bridge Loans—due April 2022 Principal $ 172,023 $ — Deferred financing costs, net of amortization (2,185 ) — 9.75% Senior Notes—due July 2022 Principal 102,000 — Deferred financing costs, net of amortization (1,319 ) — 9.75% Senior Notes—due February 2018 Principal 24,977 300,000 Original issue discount, net of amortization — (806 ) Deferred financing costs, net of amortization — (4,230 ) Bank Credit Facility—due February 2019 403,000 408,000 Deferred financing costs, net of amortization (938 ) (1,789 ) Total debt $ 697,558 $ 701,175 Less: Current portion of long-term debt (24,977 ) — Long-term debt, net of discount and deferred financing costs $ 672,581 $ 701,175

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Summary of Deferred Tax Balances	A summary of deferred tax balances as of June 30, 2018 is presented in the table below (in thousands): Deferred tax asset $ 213,029 Deferred tax liability (82,805 ) Net deferred tax asset 130,224 Valuation allowance (130,224 ) Net deferred tax asset $ —

Condensed Consolidating Finan27

Condensed Consolidating Financial Information (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
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 subsidiary issuers, combined guarantor and combined non-guarantor subsidiaries as of and for the periods indicated. As described in Note 1 – Formation and Basis of Presentation TALOS ENERGY INC. CONDENSED CONSOLIDATING BALANCE SHEET AS OF JUNE 30, 2018 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ 35,385 $ 40,940 $ 2,535 $ — $ 78,860 Restricted cash — — 1,244 — — 1,244 Accounts receivable, net Trade, net — — 100,824 — — 100,824 Joint interest, net — — 6,638 1,756 — 8,394 Other — — 832 6,259 — 7,091 Assets from price risk management activities — 478 21 — — 499 Prepaid assets — — 51,672 26 — 51,698 Income tax receivable — — 16,212 — — 16,212 Other current assets — — 3,910 — — 3,910 Total current assets — 35,863 222,293 10,576 — 268,732 Property and equipment: Proved properties — — 3,412,875 — — 3,412,875 Unproved properties, not subject to amortization — — 70,590 33,246 — 103,836 Other property and equipment — 27,293 1,580 11 — 28,884 Total property and equipment — 27,293 3,485,045 33,257 — 3,545,595 Accumulated depreciation, depletion and amortization — (7,080 ) (1,540,566 ) (10 ) — (1,547,656 ) Total property and equipment, net — 20,213 1,944,479 33,247 — 1,997,939 Other long-term assets: Assets from price risk management activities — 234 — — — 234 Other well equipment inventory — — 9,021 — — 9,021 Investments in subsidiaries 685,845 1,440,601 — — (2,126,446 ) — Other assets — 364 7,712 67 — 8,143 Total assets $ 685,845 $ 1,497,275 $ 2,183,505 $ 43,890 $ (2,126,446 ) $ 2,284,069 LIABILITIES AND STOCKHOLDERS’ Current liabilities: Accounts payable $ — $ 9,894 $ 28,728 $ 109 $ — $ 38,731 Accrued liabilities — 4,235 150,206 1,461 — 155,902 Accrued royalties — — 28,508 — — 28,508 Current portion of long-term debt — 434 — — — 434 Current portion of asset retirement obligations — — 94,334 — — 94,334 Liabilities from price risk management activities — 141,118 13,604 — — 154,722 Accrued interest payable — 7,064 390 — — 7,454 Other current liabilities — — 15,541 — — 15,541 Total current liabilities — 162,745 331,311 1,570 — 495,626 Long-term debt, net of discount and deferred financing costs — 621,908 6,060 — — 627,968 Asset retirement obligations — — 320,044 — — 320,044 Liabilities from price risk management activities — 26,777 4,989 — — 31,766 Other long-term liabilities — — 122,820 — — 122,820 Total liabilities — 811,430 785,224 1,570 — 1,598,224 Commitments and Contingencies (Note 10) Stockholders’ equity (deficit) 685,845 685,845 1,398,281 42,320 (2,126,446 ) 685,845 $ 685,845 $ 1,497,275 $ 2,183,505 $ 43,890 $ (2,126,446 ) $ 2,284,069 TALOS ENERGY INC. CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2017 (In thousands) Talos Talos Issuers Guarantors Non- 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 10) 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. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2018 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated Revenues: Oil revenue $ — $ — $ 180,161 $ — $ — $ 180,161 Natural gas revenue — — 16,448 — — 16,448 NGL revenue — — 7,297 — — 7,297 Total revenue — — 203,906 — — 203,906 Operating expenses: Direct lease operating expense — — 34,060 — — 34,060 Insurance — — 4,259 — — 4,259 Production taxes — — 564 — — 564 Total lease operating expense — — 38,883 — — 38,883 Workover and maintenance expense — — 17,714 — — 17,714 Depreciation, depletion and amortization — 384 67,341 1 — 67,726 Accretion expense — — 9,492 — — 9,492 General and administrative expense — 13,804 16,854 222 — 30,880 Total operating expenses — 14,188 150,284 223 — 164,695 Operating income (loss) — (14,188 ) 53,622 (223 ) — 39,211 Interest expense — (14,399 ) (6,891 ) (388 ) — (21,678 ) Price risk management activities expense — (89,970 ) (1,206 ) — — (91,176 ) Other income (expense) — (1,358 ) 132 (43 ) — (1,269 ) Equity earnings from subsidiaries (74,912 ) 45,003 — — 29,909 — Net income (loss) $ (74,912 ) $ (74,912 ) $ 45,657 $ (654 ) $ 29,909 $ (74,912 ) TALOS ENERGY INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2018 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated Revenues: Oil revenue $ — $ — $ 307,854 $ — $ — $ 307,854 Natural gas revenue — — 29,171 — — 29,171 NGL revenue — — 12,731 — — 12,731 Total revenue — — 349,756 — — 349,756 Operating expenses: Direct lease operating expense — — 58,975 — — 58,975 Insurance — — 6,934 — — 6,934 Production taxes — — 955 — — 955 Total lease operating expense — — 66,864 — — 66,864 Workover and maintenance expense — — 24,619 — — 24,619 Depreciation, depletion and amortization — 725 116,039 2 — 116,766 Accretion expense — — 14,252 — — 14,252 General and administrative expense — 18,398 20,567 495 — 39,460 Total operating expenses — 19,123 242,341 497 — 261,961 Operating income (loss) — (19,123 ) 107,415 (497 ) — 87,795 Interest expense — (26,627 ) (13,957 ) (836 ) — (41,420 ) Price risk management activities expense — (139,217 ) (3,935 ) — — (143,152 ) Other income (expense) — (1,208 ) 85 45 — (1,078 ) Equity earnings from subsidiaries (97,855 ) 88,320 — — 9,535 — Net income (loss) $ (97,855 ) $ (97,855 ) $ 89,608 $ (1,288 ) $ 9,535 $ (97,855 ) TALOS ENERGY INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2017 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated Revenues: Oil revenue $ — $ — $ 78,719 $ — $ — $ 78,719 Natural gas revenue — — 12,888 — — 12,888 NGL revenue — — 3,436 — — 3,436 Other — — 383 — — 383 Total revenue — — 95,426 — — 95,426 Operating expenses: Direct lease operating expense — — 28,871 — — 28,871 Insurance — — 2,688 — — 2,688 Production taxes — — 380 — — 380 Total lease operating expense — — 31,939 — — 31,939 Workover and maintenance expense — — 8,225 — — 8,225 Depreciation, depletion and amortization — 353 35,803 1 — 36,157 Accretion expense — — 5,321 — — 5,321 General and administrative expense — 3,775 3,531 164 — 7,470 Total operating expenses — 4,128 84,819 165 — 89,112 Operating income (loss) — (4,128 ) 10,607 (165 ) — 6,314 Interest expense — (11,487 ) (7,695 ) (1,623 ) — (20,805 ) Price risk management activities income — 36,040 2,955 — — 38,995 Other income (expense) — 150 (87 ) 40 — 103 Equity earnings from subsidiaries 24,607 4,032 — — (28,639 ) — Net income (loss) $ 24,607 $ 24,607 $ 5,780 $ (1,748 ) $ (28,639 ) $ 24,607 TALOS ENERGY INC. CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2017 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated Revenues: Oil revenue $ — $ — $ 162,487 $ — $ — $ 162,487 Natural gas revenue — — 26,062 — — 26,062 NGL revenue — — 7,069 — — 7,069 Other — — 1,632 — — 1,632 Total revenue — — 197,250 — — 197,250 Operating expenses: Direct lease operating expense — — 56,735 — — 56,735 Insurance — — 5,409 — — 5,409 Production taxes — — 645 — — 645 Total lease operating expense — — 62,789 — — 62,789 Workover and maintenance expense — — 17,047 — — 17,047 Depreciation, depletion and amortization — 722 75,364 2 — 76,088 Accretion expense — — 10,509 — — 10,509 General and administrative expense — 10,166 6,621 429 — 17,216 Total operating expenses — 10,888 172,330 431 — 183,649 Operating income (loss) — (10,888 ) 24,920 (431 ) — 13,601 Interest expense — (23,501 ) (14,723 ) (1,353 ) — (39,577 ) Price risk management activities expense — 81,541 3,347 — — 84,888 Other income (expense) — 300 (162 ) 19 — 157 Equity earnings from subsidiaries 59,069 11,617 — — (70,686 ) — Net income (loss) $ 59,069 $ 59,069 $ 13,382 $ (1,765 ) $ (70,686 ) $ 59,069 TALOS ENERGY INC. CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2018 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ (54,941 ) $ 160,304 $ 1,748 $ — $ 107,111 Cash flows from investing activities: Exploration, development, and other capital expenditures — (20,027 ) (117,667 ) (3,274 ) — (140,968 ) Cash paid for acquisitions, net of cash acquired — — 293,001 — — 293,001 Investments in subsidiaries — (384,089 ) — — 384,089 — Distributions from subsidiaries — 677,573 9 — (677,582 ) — Net cash provided by (used in) investing activities — 273,457 175,343 (3,274 ) (293,493 ) 152,033 Cash flows from financing activities: Redemption of 2018 Senior Notes — (24,977 ) (69 ) — — (25,046 ) Proceeds from Bank Credit Facility — 294,000 — — — 294,000 Repayment of Bank Credit Facility — (54,000 ) — — — (54,000 ) Repayment of Old Bank Credit Facility — (403,000 ) — — (403,000 ) Deferred financing costs — (17,469 ) — — — (17,469 ) Payments of capital lease — — (6,958 ) — — (6,958 ) Capital contributions — — 382,089 2,000 (384,089 ) — Distributions to subsidiary issuer — — (677,573 ) (9 ) 677,582 — Net cash provided by (used in) financing activities — (205,446 ) (302,511 ) 1,991 293,493 (212,473 ) Net increase (decrease) in cash, cash equivalents and restricted cash — 13,070 33,136 465 — 46,671 Cash, cash equivalents and restricted cash: Balance, beginning of period — 22,315 9,048 2,070 — 33,433 Balance, end of period $ — $ 35,385 $ 42,184 $ 2,535 $ — $ 80,104 TALOS ENERGY INC. CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2017 (In thousands) (Unaudited) Talos Talos Issuers Guarantors Non- Elimination Consolidated Cash flows from operating activities: Net cash provided by (used in) operating activities $ — $ (16,268 ) $ 84,651 $ 16,880 $ — $ 85,263 Cash flows from investing activities: Exploration, development, and other capital expenditures — (73 ) (54,770 ) (7,692 ) — (62,535 ) Cash paid for acquisitions, net of cash acquired — — (2,244 ) — — (2,244 ) Investments in subsidiaries — (287,689 ) — — 287,689 — Distributions from subsidiaries — 292,580 1,527 — (294,107 ) — Net cash provided by (used in) investing activities — 4,818 (55,487 ) (7,692 ) (6,418 ) (64,779 ) 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 — — (5,870 ) — — (5,870 ) Capital contributions — — 279,689 8,000 (287,689 ) — Distributions to subsidiaries — — (292,580 ) (1,527 ) 294,107 — Net cash provided by (used in) financing activities — (6,000 ) (18,761 ) 6,473 6,418 (11,870 ) Net increase (decrease) in cash, cash equivalents and restricted cash — (17,450 ) 10,403 15,661 — 8,614 Cash, cash equivalents and restricted cash: Balance, beginning of period — 24,349 6,752 2,332 — 33,433 Balance, end of period $ — $ 6,899 $ 17,155 $ 17,993 $ — $ 42,047	The following condensed consolidating financial information presents the financial information of the Company on an unconsolidated stand-alone basis and its combined subsidiary issuers, combined guarantor and combined non-guarantor subsidiaries as of and for the periods indicated. As described in Note 15 – Subsequent Change in Reporting Entity and Financial Statement Presentation TALOS ENERGY INC. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED 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 10) 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. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2016 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ 24,349 $ 5,550 $ 2,332 $ — $ 32,231 Restricted cash — — 1,202 — — 1,202 Accounts receivable, net Trade, net — — 52,764 — — 52,764 Joint interest, net — — 7,569 7,104 — 14,673 Other — 9,476 531 2,393 — 12,400 Assets from price risk management activities — 20,176 — — — 20,176 Prepaid assets — — 18,411 9 — 18,420 Inventory — — 1,093 — — 1,093 Other current assets — — 2,492 — — 2,492 Total current assets — 54,001 89,612 11,838 — 155,451 Property and equipment: Proved properties — — 2,235,835 — — 2,235,835 Unproved properties, not subject to amortization — — 64,949 7,411 — 72,360 Other property and equipment — 7,007 1,513 11 — 8,531 Total property and equipment — 7,007 2,302,297 7,422 — 2,316,726 Accumulated depreciation, depletion and amortization — (4,954 ) (1,268,580 ) (4 ) — (1,273,538 ) Total property and equipment, net — 2,053 1,033,717 7,418 — 1,043,188 Other long-term assets: Assets from price risk management activities — 293 — — — 293 Other well equipment inventory — — 12,744 — — 12,744 Investments in subsidiaries 6,986 700,385 — — (707,371 ) — Other assets — 48 574 — — 622 Total assets $ 6,986 $ 756,780 $ 1,136,647 $ 19,256 $ (707,371 ) $ 1,212,298 LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current liabilities: Accounts payable $ — $ 133 $ 27,570 $ 3,527 $ — $ 31,230 Accrued liabilities — 1,208 48,318 390 — 49,916 Accrued royalties — — 23,293 — — 23,293 Current portion of asset retirement obligations — — 33,556 — — 33,556 Liabilities from price risk management activities — 27,147 — — — 27,147 Accrued interest payable — 11,376 — — — 11,376 Other current liabilities — — 14,666 — — 14,666 Total current liabilities — 39,864 147,403 3,917 — 191,184 Long-term debt, net of discount and deferred financing costs — 701,175 — — — 701,175 Asset retirement obligations — — 186,493 — — 186,493 Liabilities from price risk management activities — 8,755 — — — 8,755 Other long-term liabilities — — 117,705 — — 117,705 Total liabilities — 749,794 451,601 3,917 — 1,205,312 Commitments and Contingencies (Note 10) Stockholders’ equity (deficit) 6,986 6,986 685,046 15,339 (707,371 ) 6,986 $ 6,986 $ 756,780 $ 1,136,647 $ 19,256 $ (707,371 ) $ 1,212,298 TALOS ENERGY INC. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED 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. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED 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. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2015 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated Revenues: Oil revenue $ — $ — $ 244,167 $ — $ — $ 244,167 Natural gas revenue — — 55,026 — — 55,026 NGL revenue — — 10,523 — — 10,523 Other — — 5,890 — — 5,890 Total revenue — — 315,606 — — 315,606 Operating expenses: Direct lease operating expense — — 171,095 — — 171,095 Insurance — — 17,965 — — 17,965 Production taxes — — 3,311 — — 3,311 Total lease operating expense — — 192,371 — — 192,371 Workover and maintenance expense — — 29,752 — — 29,752 Depreciation, depletion and amortization — 1,528 211,161 — — 212,689 Write-down of oil and natural gas properties — — 603,388 — — 603,388 Accretion expense — — 19,395 — — 19,395 General and administrative expense — 19,630 14,541 1,491 — 35,662 Total operating expenses — 21,158 1,070,608 1,491 — 1,093,257 Operating loss — (21,158 ) (755,002 ) (1,491 ) — (777,651 ) Interest expense — (46,235 ) (4,080 ) (1,229 ) — (51,544 ) Price risk management activities income — 182,196 — — — 182,196 Other income — 129 176 9 — 314 Equity earnings from subsidiaries (646,685 ) (761,617 ) — — 1,408,302 — Net income (loss) $ (646,685 ) $ (646,685 ) $ (758,906 ) $ (2,711 ) $ 1,408,302 $ (646,685 ) TALOS ENERGY INC. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED 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. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED 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 TALOS ENERGY INC. (FORMERLY KNOWN AS TALOS ENERGY LLC) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2015 (In thousands) Parent Subsidiary Issuers Guarantors Non- Guarantors Elimination Consolidated Cash flows from operating activities: Net cash provided by operating activities $ — $ 81,598 $ 55,946 $ 822 $ — $ 138,366 Cash flows from investing activities: Exploration, development, and other capital expenditures — (2,380 ) (242,203 ) (1,133 ) — (245,716 ) Cash paid for acquisitions, net of cash acquired — — (39,423 ) — — (39,423 ) Investments in subsidiaries (73,500 ) (579,822 ) — — 653,322 — Distributions from subsidiaries — 300,891 — — (300,891 ) — Net cash provided by (used in) investing activities (73,500 ) (281,311 ) (281,626 ) (1,133 ) 352,431 (285,139 ) Cash flows from financing activities: Proceeds from Bank Credit Facility — 120,000 — — — 120,000 Repayment of Bank Credit Facility — (30,000 ) — — — (30,000 ) Repayment of GCER Bank Credit Facility — — (55,000 ) — — (55,000 ) Deferred financing costs — (269 ) — — — (269 ) Capital contributions — 73,500 578,643 1,179 (653,322 ) — Distributions to subsidiaries — — (300,779 ) (112 ) 300,891 — Contributions from Sponsors 75,000 — — — — 75,000 Distributions to Sponsors (1,500 ) — — — — (1,500 ) Net cash provided by (used in) financing activities 73,500 163,231 222,864 1,067 (352,431 ) 108,231 Net increase (decrease) in cash, cash equivalents and restricted cash — (36,482 ) (2,816 ) 756 — (38,542 ) Cash, cash equivalents and restricted cash Balance, beginning of period — 44,552 18,594 — — 63,146 Balance, end of period $ — $ 8,070 $ 15,778 $ 756 $ — $ 24,604

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
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 our oil, natural gas and NGL revenues, was as follows: Year Ended December 31, 2017 2016 2015 Shell Trading (US) Company 80 % 68 % 68 % Chevron U.S.A Inc. * * 14 % 16 % ** less than 10%
Summary of Supplementary Cash Flow Information	Supplementary cash flow information for each period presented was as follows (in thousands): Year Ended December 31, 2017 2016 2015 Supplemental Non-Cash Transactions: Capital expenditures included in accounts payable and accrued liabilities $ 40,626 $ 13,832 $ 30,125 Fair value of assets acquired $ — $ — $ 75,519 Fair value of liabilities assumed $ — $ — $ 75,519 Capital lease transaction $ — $ 124,300 $ — Supplemental Cash Flow Information: Interest paid, net of amounts capitalized $ 47,994 $ 55,254 $ 37,247

Acquisitions (Tables)

Acquisitions (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Summary of Preliminary 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) $ 377,155 Property and equipment 876,500 Other long-term assets 18,928 Current liabilities (130,121 ) Long-term debt (235,416 ) Other long-term liabilities (175,082 ) Allocated purchase price $ 731,964 (1) Includes $293.0 million of cash acquired. The fair values of current assets acquired includes trade receivables and joint interest receivables of $43.3 million and $3.5 million, respectively, which the Company expects all to be realizable.
Summary of Purchase Price	The following table summarizes the purchase price (in thousands, except per share data): Stone Energy common stock—issued and outstanding as of May 9, 2018 20,038 Stone Energy common stock price $ 35.49 Common stock value $ 711,149 Stone Energy common stock warrants—issued and outstanding as of May 9, 2018 3,528 Stone Energy common stock warrants price $ 5.90 Common stock warrants value $ 20,815 Total consideration and fair value $ 731,964
Supplemental Proforma Information	The following supplemental pro forma information (in thousands, except per common share amounts), presents the condensed consolidated results of operations for the three and six months ended June 30, 2018 and 2017 as if the Stone Combination had occurred on January 1, 2017. The unaudited proforma information was derived from historical combined 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. Three Months Ended Six Months Ended 2018 2017 2018 2017 Revenue $ 244,453 $ 166,669 $ 471,652 $ 340,939 Net income (loss) $ (45,696 ) $ 19,032 $ (51,211 ) $ 66,518 Basic and diluted net income (loss) per common share $ (0.84 ) $ 0.35 $ (0.95 ) $ 1.23
Sojitz Energy Venture Inc
Summary of Preliminary Allocation of Purchase Price to Assets Acquired and Liabilities Assumed		The following table below 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): Allocation of the Purchase Price December 20, 2016 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 ) Cash Paid $ 88,238
Deep Gulf Energy III, LLC
Summary of Preliminary Allocation of Purchase Price to Assets Acquired and Liabilities Assumed		We completed the final purchase price allocation in 2015 which was calculated as follow (in thousands): Allocation of the Purchase Price April 8, 2015 Proved properties $ 24,316 Unproved properties, not subject to amortization 14,643 Asset retirement obligations (442 ) Cash Paid $ 38,517
Gulf Coast Energy Resources, LLC
Summary of Preliminary Allocation of Purchase Price to Assets Acquired and Liabilities Assumed		We completed the final purchase price allocation in 2015 which was calculated as follow (in thousands): Allocation of the Purchase Price March 31, 2015 Current assets $ 12,748 Proved properties 38,680 Unproved properties, not subject to amortization 22,637 Other non-current assets 536 Total assets acquired 74,601 Current portion of asset retirement obligations 107 Other current liabilities 18,632 Asset retirement obligations 744 Long-term debt, net of discount(1) 55,000 Other long-term liabilities(2) 118 Total liabilities assumed 74,601 Net assets acquired $ — (1) The long-term debt, net of discount assumed represents $55.0 million in borrowings under GCER’s senior reserve-based revolving credit facility (“GCER Bank Credit Facility”). (2) The other long-term liabilities assumed includes $0.1 million to recognize an estimated liability as of the acquisition date for the contingent consideration arrangement if the oil and natural gas assets acquired meet certain targets within the subsequent five years. The fair value of the contingent consideration was calculated using a Monte Carlo simulation analysis. Significant inputs to the analysis are based, in part, on inputs not observable in the market and thus represent Level 3 measurements in the fair value hierarchy. These inputs 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. The maximum potential payment under the contingent consideration arrangement is $6.5 million.
Schedule of Fair Value Current Assets Acquired Includes Receivables		The fair value, as adjusted, of the current assets acquired includes the following receivables (in thousands): March 31, 2015 Gross Receivable Expected Uncollectable Amount Fair Trade receivables $ 3,104 $ — $ 3,104 Joint interest receivables $ 3,484 $ (323 ) $ 3,161 Other receivables $ 196 $ — $ 196

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
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, 2017, by the year in which such costs were incurred (in thousands): Year Ended December 31, Total 2017 2016 2015 2014 and Prior Acquisition $ 23,871 $ — $ 3,845 $ 4,089 $ 15,937 Exploration 48,131 27,137 7,174 2,621 11,199 Total unproved properties, not subject to amortization $ 72,002 $ 27,137 $ 11,019 $ 6,710 $ 27,136
Schedule of Asset Retirement Obligations	The discounted asset retirement obligations included on the condensed consolidated balance sheets in current and non-current liabilities and the changes to that liability during the six months ended June 30, 2018 were as follows (in thousands): Asset retirement obligations at January 1, 2018 $ 214,733 Fair value of asset retirement obligations assumed 220,637 Obligations settled (43,896 ) Accretion expense 14,252 Obligations incurred 120 Changes in estimate 8,532 Asset retirement obligations at June 30, 2018 $ 414,378 Less: Current portion 94,334 Long-term portion $ 320,044	The discounted asset retirement obligations included in the consolidated balance sheets in current and non-current liabilities, and the changes in that liability during the each of the years ended December 31, were as follows (in thousands): Year Ended December 31, 2017 2016 Asset retirement obligations at January 1 $ 220,049 $ 226,690 Fair value of asset retirement obligations acquired 699 6,445 Obligations settled (32,573 ) (23,689 ) Accretion expense 19,295 21,829 Obligations incurred 4,213 1,014 Changes in estimate(1) 3,050 (12,240 ) Asset retirement obligations at December 31 $ 214,733 $ 220,049 Less: Current portion at December 31 (39,741 ) (33,556 ) Noncurrent portion at December 31 $ 174,992 $ 186,493 (1) The reduction during the year ended December 31, 2016 was primarily attributable to a reduction in service costs.

Employee Incentive Programs (Ta

Employee Incentive Programs (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Series B Unit Activity	A summary of the Series B Unit activity for the years ended December 31, 2017, 2016 and 2015 is presented below. Number of Series B Units Weighted Average Estimated Fair Value per Unit Non-vested at December 31, 2014 642,355 $ 21.04 Vested (175,196 ) 20.43 Forfeited or cancelled (92,500 ) 22.08 Non-vested at December 31, 2015 374,659 $ 21.07 Granted 147,000 4.11 Vested (122,455 ) 17.95 Forfeited or cancelled (72,750 ) 21.22 Non-vested at December 31, 2016 326,454 $ 14.57 Granted 35,100 20.99 Vested (104,614 ) 17.16 Forfeited or cancelled (22,500 ) 15.10 Non-vested at December 31, 2017 234,440 $ 14.32
Summary of Fair Value Grant Estimated Using Weighted Average Assumptions	The fair value of each grant was estimated at the date of grant using the following weighted-average assumptions: 2017 Grants 2016 Grants Assumed value of equity (in thousands) $ 789,426 $ 196,280 Risk-free rate of interest 1.16 % 1.11 % Expected time to a liquidity event (in years) 1 3 Expected volatility of equity 40 % 70 % Discount for lack of marketability 25 % 34 %

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Schedule of Future Minimum Lease Commitments	As of December 31, 2017, minimum lease commitments for our capital lease for the years ended December 31 are as follows (in thousands): 2018 $ 46,667 2019 45,000 2020 45,000 2021 45,000 2022 45,000 Thereafter 18,750 Total minimum lease payments 245,417 Less amount represented lease operating expenses (63,607 ) Less amount represented interest (75,189 ) Present value of minimum lease payments 106,621 Less current maturities of capital lease obligations (12,952 ) Long-term capital lease obligations $ 93,669

Selected Quarterly Financial 33

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2017
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 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 ) Quarter Ended 2016 Revenues $ 50,656 $ 67,405 $ 63,775 $ 76,918 Operating loss $ (40,011 ) $ (20,697 ) $ (12,868 ) $ (7,103 ) Price risk management activities income (expense) $ 12,924 $ (48,930 ) $ 11,350 $ (32,742 ) Net loss $ (40,799 ) $ (84,715 ) $ (22,219 ) $ (60,354 )

Supplemental Oil and Gas Disc34

Supplemental Oil and Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion, Depreciation and Amortization	Aggregate amounts of capitalized costs relating to our oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion, depreciation and amortization as of the dates indicated are presented below (in thousands): December 31, 2017 2016 Proved properties $ 2,440,811 $ 2,235,835 Unproved oil and gas properties, not subject to amortization 72,002 72,360 Total oil and gas properties 2,512,813 2,308,195 Less: Accumulated depletion and amortization (1,423,829 ) (1,268,276 ) Net capitalized costs $ 1,088,984 $ 1,039,919 Depletion and amortization rate per Boe $ 14.85 $ 13.82
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, 2017 2016 2015 Property acquisition costs: Proved properties $ 1,108 $ 77,906 $ 68,463 Unproved properties, not subject to amortization 5,778 15,919 39,265 Total property acquisition costs 6,886 93,825 107,728 Exploration costs 82,887 27,807 25,908 Development costs 114,846 195,869 228,257 Total costs incurred $ 204,619 $ 317,501 $ 361,893
Schedule of Estimated Proved Reserves at Net Ownership Interest	The following table presents our estimated proved reserves at our net ownership interest: Oil Gas NGL Oil Equivalent (MBoe) Total proved reserves at December 31, 2014 46,120 136,232 4,096 72,921 Revision of previous estimates (3,435 ) (22,580 ) 207 (6,991 ) Production (5,161 ) (21,458 ) (588 ) (9,325 ) Purchases of reserves 4,029 30,527 385 9,502 Extensions and discoveries 4,801 6,503 481 6,366 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 Total proved developed reserves as of: December 31, 2015 33,016 90,432 3,383 51,471 December 31, 2016 45,753 96,122 4,032 65,805 December 31, 2017 37,460 77,577 3,315 53,704 Total proved undeveloped reserves as of: December 31, 2015 13,338 38,792 1,198 21,002 December 31, 2016 26,613 54,482 2,204 37,897 December 31, 2017 35,344 50,079 3,232 46,921 (1) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
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 our interest in proved oil, natural gas and NGL reserves (in thousands): December 31, 2017 2016 2015 Future cash inflows $ 4,308,863 $ 3,390,612 $ 2,786,828 Future costs: Production (815,509 ) (775,354 ) (1,363,585 ) Development and abandonment (823,164 ) (664,254 ) (646,161 ) Future net cash flows before income taxes 2,670,190 1,951,004 777,082 Future income tax expense — — — Future net cash flows before income taxes 2,670,190 1,951,004 777,082 Discount at 10% annual rate (862,521 ) (614,969 ) (174,101 ) Standardized measure of discounted future net cash flows $ 1,807,669 $ 1,336,035 $ 602,981
Schedule of Base Prices Used in Determining Standardized Measure	See the following table for base prices used in determining the standardized measure: Year Ended December 31, 2017 2016 2015 Oil price per Bbl $ 51.36 $ 40.02 $ 50.72 Natural gas prices per Mcf $ 3.20 $ 2.66 $ 2.75 NGL price per Bbl $ 24.64 $ 14.96 $ 17.60
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 our proved oil, natural gas and NGL reserves are as follows (in thousands): Year Ended December 31, 2017 2016 2015 Standardized measure, beginning of year $ 1,336,035 $ 602,981 $ 1,888,958 Changes during the year: Sales, net of production costs (288,942 ) (114,625 ) (117,344 ) Net change in prices and production costs 555,100 80,174 (1,879,436 ) Changes in future development costs (156,282 ) 2,292 92,182 Development costs incurred 146,687 108,484 273,532 Accretion of discount 133,603 60,298 188,896 Net change in income taxes — — — Purchases of reserves — 222,581 229,052 Extensions and discoveries 328,565 479,833 91,722 Sales of reserves — — — Net change due to revision in quantity estimates (113,629 ) (5,685 ) (103,842 ) Changes in production rates (timing) and other (133,468 ) (100,298 ) (60,739 ) Total 471,634 733,054 (1,285,977 ) Standardized measure, end of year $ 1,807,669 $ 1,336,035 $ 602,981

Formation and Basis of Presen35

Formation and Basis of Presentation - Additional Information (Details)	May 10, 2018USD ($)$ / sharesshares	Nov. 21, 2017USD ($)shares	Feb. 06, 2013USD ($)	Jun. 30, 2018USD ($)Segment	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016	Dec. 29, 2016USD ($)	Apr. 15, 2015	Feb. 03, 2013USD ($)
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Common stock par value | $ / shares	$ 0.01
Percentage of voting interest acquired	63.00%	63.00%
Senior notes, maturity date				Feb. 28, 2019		Feb. 28, 2019
Reclassification from accounts payable to accrued liabilities						$ 73,500,000
Reclassification from other current assets to prepaid assets						$ 7,300,000
Number of reportable segment | Segment				1
Private equity capital commitment receivable				$ 600,000,000
Proceeds from contributions from affiliates for acquisition and other asset purchases				$ 0	$ 0
Interest rate, stated percentage								$ 500,000
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
Senior Notes
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate									11.00%
Senior Notes | 9.75% Senior Notes
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Proceeds from issuance of senior notes		$ 102,000,000
Debt instrument interest rate		9.75%		9.75%
Shares issued on exchange agreement | shares		2,874,049
Senior Notes | 9.75% Senior Notes – due July 2022
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Debt instrument interest rate				9.75%		9.75%	9.75%
Senior notes, maturity date				Jul. 31, 2022		Jul. 5, 2022	Jul. 5, 2022
Senior notes, principal amount						$ 102,000,000
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%
Proceeds from Issuance of senior secured notes in exchange of 11% senior secured notes		$ 137,400,000
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		$ 172,000,000
Stone Energy Corporation
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Closing date of merger agreement				May 10, 2018
Percentage of voting interest acquired	37.00%	37.00%
Total consideration and fair value	$ 731,964,000
Talos Production LLC
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Percentage of voting interest acquired	100.00%
Share issed on merger | shares	31,244,085
E R T Acquisition | Nine Point Seven Five Two Thousand Eighteen Senior Notes
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Senior notes, maturity date						Feb. 15, 2018
Proceeds from contributions from affiliates for acquisition and other asset purchases						$ 325,000,000
Senior notes, principal amount						300,000,000
Interest rate, stated percentage						9,750,000
Discount rate						$ 975,000
Private Equity Funds
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Private equity capital commitment receivable										$ 600,000,000
Helix Energy Solutions Group Inc | E R T Acquisition
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Total consideration and fair value			$ 625,200,000
Purchase price and working capital adjustments			$ 15,200,000

Acquisitions - Summary of Purch

Acquisitions - Summary of Purchase Price (Details) - USD ($) $ / shares in Units, $ in Thousands	May 10, 2018	Jun. 30, 2018	May 09, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Common stock value		$ 542		$ 312	$ 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 consideration and fair value	$ 731,964

Acquisitions - Summary of Preli

Acquisitions - Summary of Preliminary Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Parenthetical) (Details) - USD ($) $ in Thousands	May 10, 2018	Mar. 31, 2015
Stone Energy Corporation
Business Acquisition [Line Items]
Cash acquired	$ 293,000
Long-term debt, net of discount	235,416
Payout under the earn-out	175,082
Stone Energy Corporation | Trade Accounts Receivable
Business Acquisition [Line Items]
Primary fair values of receivables acquired	43,300
Stone Energy Corporation | Joint Interest Receivables
Business Acquisition [Line Items]
Primary fair values of receivables acquired	$ 3,500
Gulf Coast Energy Resources, LLC
Business Acquisition [Line Items]
Long-term debt, net of discount		$ 55,000
Payout under the earn-out		118
Payout under the earn-out		6,500
Recognize estimated liability if the oil and natural gas assets acquired meet certain targets within the subsequent five years | Gulf Coast Energy Resources, LLC
Business Acquisition [Line Items]
Payout under the earn-out		$ 100

Acquisitions - Summary of Suppl

Acquisitions - Summary of Supplemental Proforma Information (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Business Acquisition Pro Forma Information [Abstract]
Revenue	$ 244,453	$ 166,669	$ 471,652	$ 340,939
Net income (loss)	$ (45,696)	$ 19,032	$ (51,211)	$ 66,518
Basic and diluted net income (loss) per common share	$ (0.84)	$ 0.35	$ (0.95)	$ 1.23

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil And Gas Property [Abstract]
Asset retirement obligations			$ 214,733	$ 220,049	$ 220,049	$ 226,690
Fair value of asset retirement obligations assumed			220,637
Obligations settled			(43,896)		(32,573)	(23,689)
Accretion expense	$ 9,492	$ 5,321	14,252	$ 10,509	19,295	21,829	$ 19,395
Obligations incurred			120		4,213	1,014
Changes in estimate			8,532		3,050	(12,240)
Asset retirement obligations	414,378		414,378		214,733	220,049	$ 226,690
Current portion of asset retirement obligations	94,334		94,334		39,741	33,556
Noncurrent portion	$ 320,044		$ 320,044		174,992	186,493
Fair value of asset retirement obligations acquired					$ 699	$ 6,445

Financial Instruments - Schedul

Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Carrying Amount			$ 402,062
Fair Value			403,000
Oil and Natural Gas Derivatives
Debt Instrument [Line Items]
Carrying Amount		$ (185,755)	(66,830)
Fair Value		(185,755)	(66,830)
Derivatives
Debt Instrument [Line Items]
Carrying Amount			(66,830)	$ (15,433)
Fair Value			(66,830)	(15,433)
11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Carrying Amount	[1]	380,042
Fair Value	[1]	410,411
7.50% Senior Secured Notes – due May 2022
Debt Instrument [Line Items]
Carrying Amount		6,060
Fair Value		5,999
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 February 2018
Debt Instrument [Line Items]
Carrying Amount			24,977	294,964
Fair Value			24,977	137,850
9.75% Senior Notes – due July 2022
Debt Instrument [Line Items]
Carrying Amount	[1]		100,681
Fair Value	[1]		102,000
Bank Credit Facility – due May 2022
Debt Instrument [Line Items]
Carrying Amount	[1]	231,522
Fair Value	[1]	$ 240,000
Bank Credit Facility
Debt Instrument [Line Items]
Carrying Amount			402,062	406,211
Fair Value			$ 403,000	$ 408,000
[1]	The carrying amounts are net of discount and deferred financing costs.

Financial Instruments - Sched41

Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016	Apr. 15, 2015
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
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
Bank Credit Facility – due May 2022
Debt Instrument [Line Items]
Senior notes, maturity date	May 10, 2022	May 10, 2022
Bridge Loans | 11.00% Second-Priority Senior Secured Notes – due April 2022
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%	11.00%	11.00%
Senior notes, maturity date	Apr. 30, 2022	Apr. 3, 2022	Apr. 3, 2022
Senior Notes
Debt Instrument [Line Items]
Debt instrument interest rate				11.00%
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%
Senior notes, maturity date	Apr. 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%	9.75%	9.75%
Senior notes, maturity date	Jul. 31, 2022	Jul. 5, 2022	Jul. 5, 2022
Senior Notes | 9.75% Senior Notes – due February 2018
Debt Instrument [Line Items]
Debt instrument interest rate	9.75%	9.75%	9.75%
Senior notes, maturity date	Feb. 28, 2018	Feb. 15, 2018	Feb. 15, 2018

Financial Instruments - Additio

Financial Instruments - Additional Information (Details)	6 Months Ended		12 Months Ended
	Jun. 30, 2018USD ($)counterparty	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016	May 10, 2018USD ($)	Apr. 15, 2015
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes, maturity date	Feb. 28, 2019		Feb. 28, 2019
Private equity capital commitment receivable	$ 600,000,000
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 June 30, 2018.
Redemption of senior notes	$ 25,046,000	$ 1,000,000	$ 1,000,000
Bank Credit Facility
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Number of counterparties | counterparty	6
Investment Grade Credit Rating
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Number of counterparties | counterparty	8
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]
Debt instrument interest rate	7.50%		7.50%
Senior notes, maturity date	May 31, 2022		May 31, 2022
Senior notes, principal amount					$ 6,100,000
New Bank Credit Facility
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Senior notes, maturity date	May 10, 2022
New Bank Credit Facility | Old Bank Credit Facility
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Private equity capital commitment receivable					$ 600,000,000
11.00% Bridge Loans – due April 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	11.00%		11.00%
Senior notes, maturity date	Apr. 3, 2022		Apr. 3, 2022
9.75% Senior Notes – due July 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [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
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	9.75%		9.75%
Senior notes, maturity date	Feb. 15, 2018		Feb. 15, 2018
Debt instrument, repurchase amount	$ 25,000,000
Stone Energy Corporation | 11.00% Second-Priority Senior Secured Notes – due April 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	11.00%
Senior notes, maturity date	Apr. 30, 2022
Senior notes, principal amount	$ 390,900,000
Stone Energy Corporation | 7.50% Senior Secured Notes – due May 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	7.50%
Senior notes, maturity date	May 31, 2022
Senior notes, principal amount	$ 6,100,000
Level 2
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument redemption, description			The fair value of our Bridge Loans is estimated as face value as no market has developed and the holders of the Bridge Loans were the largest holders of the 2018 Senior Notes prior to the April 3, 2017 conversion. The fair value of the 2022 Senior Notes and 2018 Senior Notes are estimated to equal the face value based on the April 3, 2017 conversion and May 15, 2017 redemption of $1.0 million of the 2018 Senior Notes at par. These fair values represent Level 2 fair value measurements (see Note 6 – Debt).
Bridge Loans | 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%
Bridge Loans | 11.00% Bridge Loans – due April 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	11.00%		11.00%	11.00%
Senior notes, maturity date	Apr. 30, 2022		Apr. 3, 2022	Apr. 3, 2022
Senior notes, principal amount			$ 172,000,000
Senior Notes
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate						11.00%
Redemption of senior notes			$ 1,000,000
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	11.00%
Senior notes, maturity date	Apr. 30, 2022
Senior Notes | 7.50% Senior Secured Notes – due May 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	7.50%
Senior notes, maturity date	May 31, 2022
Senior Notes | 9.75% Senior Notes – due July 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	9.75%		9.75%	9.75%
Senior notes, maturity date	Jul. 31, 2022		Jul. 5, 2022	Jul. 5, 2022
Senior notes, principal amount			$ 102,000,000
Senior Notes | 9.75% Senior Notes – due February 2018
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instrument interest rate	9.75%		9.75%	9.75%
Senior notes, maturity date	Feb. 28, 2018		Feb. 15, 2018	Feb. 15, 2018
Senior notes, principal amount			$ 25,000,000

Financial Instruments - Sched43

Financial Instruments - Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed Consolidated Statements of Operations (Parenthetical) (Details) - USD ($) $ in Thousands	3 Months Ended											6 Months Ended				12 Months Ended
	Jun. 30, 2018		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017		Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2018		Jun. 30, 2017		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Net cash receipts (payments) on settled derivative instruments	$ (33,600)				$ 9,200							$ (54,100)		$ 13,700
Price risk management activities income (expense)	$ (91,176)	[1]	$ (84,365)	$ (28,086)	$ 38,995	[1]	$ 45,893	$ (32,742)	$ 11,350	$ (48,930)	$ 12,924	(143,152)	[1]	84,888	[1]	$ (27,563)	[2]	$ (57,398)	[2]	$ 182,196	[2]
Received net cash settlements												$ (54,056)		$ 13,668		$ 23,834		$ 172,182		$ 181,927
[1]	The Company paid $33.6 million and received $9.2 million in net cash settlements for the three months ended June 30, 2018 and 2017, respectively, and paid $54.1 million and received $13.7 million in net cash settlements for the six months ended June 30, 2018 and 2017, respectively.
[2]	The Company received net cash settlements of $23.8 million, $172.2 million and $181.9 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Financial Instruments - Sched44

Financial Instruments - Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under Derivative Contracts (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2018MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2017MMBTU$ / bbl$ / MMBTUbbl
July Two Thousand Eighteen To December Two Thousand Eighteen Production | Henry Hub | NYMEX | Swap
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type	Swap
Average Daily Volumes | MMBTU	23,747
Weighted Average Swap Price | $ / MMBTU	3.01
July Two Thousand Eighteen To December Two Thousand Eighteen Production | Henry Hub | NYMEX | Collar
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type	Collar
Average Daily Volumes | MMBTU	6,000
Weighted Average Put Price	2.75
Weighted Average Call Price	3.24
January 2019 - December 2019 | Henry Hub | NYMEX | Swap
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type	Swap	Swap
Average Daily Volumes | bbl	10,146
Average Daily Volumes | MMBTU		10,146
Weighted Average Swap Price	2.99	2.99
January 2018 - December 2018 | Henry Hub | NYMEX | Swap
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type		Swap
Average Daily Volumes | MMBTU		26,346
Weighted Average Swap Price | $ / MMBTU		3
Crude Oil | WTI | July Two Thousand Eighteen To December Two Thousand Eighteen Production | Swap
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type	Swap
Average Daily Volumes | bbl	29,615
Weighted Average Swap Price	54.06
Crude Oil | WTI | July Two Thousand Eighteen To December Two Thousand Eighteen Production | Collar
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type	Collar
Average Daily Volumes | bbl	1,000
Weighted Average Put Price	45
Weighted Average Call Price	55.35
Crude Oil | WTI | July Two Thousand Eighteen To December Two Thousand Eighteen Production | Put
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type	Put
Average Daily Volumes | bbl	2,000
Weighted Average Put Price	49.50
Crude Oil | WTI | January 2019 - December 2019 | Swap
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type	Swap	Swap
Average Daily Volumes | bbl	23,130	15,866
Weighted Average Swap Price	54.14	53.17
Crude Oil | WTI | January 2018 - December 2018 | Swap
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type		Swap
Average Daily Volumes | bbl		24,804
Weighted Average Swap Price		53.79
Crude Oil | WTI | January 2019 – June 2019 | Swap
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Instrument Type		Swap
Average Daily Volumes | bbl		1,008
Weighted Average Swap Price		56.25

Financial Instruments - Summary

Financial Instruments - Summary of Additional Information Related to Financial Instruments Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil And Natural Gas Swaps
Liabilities:
Total net liability	$ (185,755)	$ (66,830)
Fair Value on Recurring Basis
Liabilities:
Total net liability	(185,755)	(66,830)	$ (15,433)
Fair Value on Recurring Basis | Oil And Natural Gas Swaps
Assets:
Oil and natural gas derivatives	733	1,908	20,469
Liabilities:
Oil and natural gas derivatives	(186,488)	(68,738)	(35,902)
Fair Value on Recurring Basis | Level 2
Liabilities:
Total net liability	(185,755)	(66,830)	(15,433)
Fair Value on Recurring Basis | Level 2 | Oil And Natural Gas Swaps
Assets:
Oil and natural gas derivatives	733	1,908	20,469
Liabilities:
Oil and natural gas derivatives	$ (186,488)	$ (68,738)	$ (35,902)

Financial Instruments - Sched46

Financial Instruments - Schedule of Fair Value of Derivative Financial Instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Price Risk Derivatives [Line Items]
Assets from price risk management activities – current	$ 499	$ 1,563	$ 20,176
Assets from price risk management activities – non-current	234	345	293
Liabilities from price risk management activities – current	154,722	49,957	27,147
Liabilities from price risk management activities – non-current	31,766	18,781	8,755
Oil and Natural Gas Derivatives
Price Risk Derivatives [Line Items]
Assets from price risk management activities – current	499	1,563	20,176
Assets from price risk management activities – non-current	234	345	293
Liabilities from price risk management activities – current	154,722	49,957	27,147
Liabilities from price risk management activities – non-current	$ 31,766	$ 18,781	$ 8,755

Debt - Summary of Detail Compri

Debt - Summary of Detail Comprising Debt and Related Book Values (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Principal	$ 240,000
Original issue discount, net of amortization	(8,906)
Total debt	628,402	$ 697,558	$ 701,175
Less: current portion of long-term debt	(434)	(24,977)
Long-term debt, net of discount and deferred financing costs	627,968	672,581	701,175
4.20% Building Loan - due November 2030
Debt Instrument [Line Items]
Principal	10,800
Senior Notes
Debt Instrument [Line Items]
Principal		172,000
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Principal	390,868
Deferred financing costs, net of amortization	(1,920)
Senior Notes | 7.50% Senior Secured Notes – due May 2022
Debt Instrument [Line Items]
Principal	6,060
Senior Notes | 9.75% Senior Notes – due July 2022
Debt Instrument [Line Items]
Principal		102,000
Deferred financing costs, net of amortization		(1,319)
Senior Notes | 9.75% Senior Notes – due February 2018
Debt Instrument [Line Items]
Principal		24,977	300,000
Original issue discount, net of amortization			(806)
Deferred financing costs, net of amortization			(4,230)
Bank Credit Facility | Bank Credit Facility – due May 2022
Debt Instrument [Line Items]
Deferred financing costs, net of amortization	(8,478)
Bank Credit Facility | Old Bank Credit Facility – due February 2019
Debt Instrument [Line Items]
Principal		403,000
Deferred financing costs, net of amortization		(938)
Bank Credit Facility | Bank Credit Facility – due February 2019
Debt Instrument [Line Items]
Principal		403,000	408,000
Deferred financing costs, net of amortization		(938)	$ (1,789)
Building Loan | 4.20% Building Loan - due November 2030
Debt Instrument [Line Items]
Principal	10,778
Bridge Loans
Debt Instrument [Line Items]
Principal		172,000
Bridge Loans | 11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Principal	$ 172,000
Bridge Loans | 11.00% Bridge Loans – due April 2022
Debt Instrument [Line Items]
Principal		172,023
Deferred financing costs, net of amortization		$ (2,185)

Debt - Summary of Detail Comp48

Debt - Summary of Detail Comprising Debt and Related Book Values (Parenthetical) (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016	Apr. 15, 2015
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
Bank Credit Facility – due February 2019
Debt Instrument [Line Items]
Senior notes, maturity date		Feb. 6, 2019
Senior Notes
Debt Instrument [Line Items]
Debt instrument interest rate				11.00%
Senior Notes | 11.00% Second-Priority Senior Secured Notes – due April 2022
Debt Instrument [Line Items]
Debt instrument interest rate	11.00%
Senior notes, maturity date	Apr. 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%	9.75%	9.75%
Senior notes, maturity date	Jul. 31, 2022	Jul. 5, 2022	Jul. 5, 2022
Senior Notes | 9.75% Senior Notes – due February 2018
Debt Instrument [Line Items]
Debt instrument interest rate	9.75%	9.75%	9.75%
Senior notes, maturity date	Feb. 28, 2018	Feb. 15, 2018	Feb. 15, 2018
Bank Credit Facility | Bank Credit Facility – due May 2022
Debt Instrument [Line Items]
Senior notes, maturity date	May 31, 2022
Bank Credit Facility | Old Bank Credit Facility – due February 2019
Debt Instrument [Line Items]
Senior notes, maturity date	Feb. 28, 2019
Bank Credit Facility | Bank Credit Facility – due February 2019
Debt Instrument [Line Items]
Senior notes, maturity date		Feb. 28, 2019
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 | 11.00% Second-Priority Senior Secured Notes – due April 2022
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%	11.00%	11.00%
Senior notes, maturity date	Apr. 30, 2022	Apr. 3, 2022	Apr. 3, 2022

Debt - Additional information (

Debt - Additional information (Details) - USD ($)

Apr. 03, 2017

Jan. 10, 2017

Aug. 15, 2017

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Sep. 30, 2017

Jun. 30, 2018

Jun. 30, 2017

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

May 10, 2018

Feb. 15, 2018

Nov. 21, 2017

May 31, 2017

May 15, 2017

Apr. 15, 2015

Debt Instrument [Line Items]

Principal

$ 240,000,000

$ 240,000,000

Payments of debt issuance costs

3,900,000

4,500,000

Work fees to debt holders

$ 9,300,000

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 June 30, 2018.

Debt instrument maturity date

Feb. 28, 2019

Feb. 28, 2019

Credit facility, maximum borrowing capacity

$ 600,000,000

$ 600,000,000

Proceeds from Bank Credit Facility

294,000,000

$ 10,000,000

$ 10,000,000

$ 15,000,000

$ 120,000,000

Repayment of bank credit facility

$ 54,000,000

$ 15,000,000

$ 15,000,000

10,000,000

$ 30,000,000

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

Debt Instrument [Line Items]

Debt instrument, interest rate, stated percentage

11.00%

11.00%

11.00%

Debt instrument maturity date

Apr. 30, 2022

Apr. 30, 2022

7.50% Senior Secured Notes – due May 2022

Debt Instrument [Line Items]

Debt instrument, interest rate, stated percentage

7.50%

7.50%

7.50%

Debt instrument frequency of periodic payment

semiannually

Debt instrument payment terms

semiannually each May 31 and November 30

Debt instrument, face amount

$ 6,100,000

Debt instrument maturity date

May 31, 2022

May 31, 2022

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%

4.20% Building Loan - due November 2030

Debt Instrument [Line Items]

Principal

$ 10,800,000

$ 10,800,000

Debt instrument, interest rate, stated percentage

4.20%

4.20%

EBITDA to net interest

2.00%

Debt instrument frequency of periodic payment

180 equal monthly installments

Debt instrument maturity date

Nov. 20, 2030

Debt instrument, periodic payment

$ 0.1

11.00% Bridge Loans – due April 2022

Debt Instrument [Line Items]

Debt instrument, interest rate, stated percentage

11.00%

11.00%

11.00%

Debt instrument maturity date

Apr. 3, 2022

Apr. 3, 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

$ 600,000,000

Bank Credit Facility – due February 2019

Debt Instrument [Line Items]

Debt instrument maturity date

Feb. 6, 2019

Credit facility, maximum borrowing capacity

600,000,000

$ 600,000,000

$ 475,000,000

$ 475,000,000

Commitment fee percentage

0.50%

Debt covenant to EBITDAX

350.00%

Undrawn commitment under credit facility

354,000,000

$ 354,000,000

67,100,000

Letters of credit outstanding amount

6,000,000

6,000,000

4,900,000

Line of credit outstanding amount

240,000,000

240,000,000

403,000,000

Proceeds from Bank Credit Facility

$ 10,000,000

294,000,000

Repayment of bank credit facility

$ 15,000,000

Bank Credit Facility – due February 2019 | Letter of Credit

Debt Instrument [Line Items]

Credit facility, maximum borrowing capacity

$ 200,000,000

$ 200,000,000

$ 200,000,000

Bank Credit Facility – due February 2019 | Maximum

Debt Instrument [Line Items]

Commitment fee percentage

0.50%

Debt covenant to EBITDAX

350.00%

Bank Credit Facility – due February 2019 | Maximum | Scenario, Forecast

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%

2.75%

Bank Credit Facility – due February 2019 | Maximum | Base Rate

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

2.75%

1.75%

Bank Credit Facility – due February 2019 | Minimum

Debt Instrument [Line Items]

Commitment fee percentage

0.375%

Bank Credit Facility – due February 2019 | Minimum | Scenario, Forecast

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%

1.75%

Bank Credit Facility – due February 2019 | Minimum | Base Rate

Debt Instrument [Line Items]

Debt Instrument, Basis Spread on Variable Rate

1.75%

0.75%

9.75% Senior Notes – due February 2018

Debt Instrument [Line Items]

Debt instrument, interest rate, stated percentage

9.75%

9.75%

9.75%

Debt instrument maturity date

Feb. 15, 2018

Feb. 15, 2018

Debt instrument, repurchase amount

$ 25,000,000

$ 25,000,000

2018 Senior Note

Debt Instrument [Line Items]

Principal

$ 102,000,000

Debt instrument, repurchase amount

$ 1,000,000

2022 Senior Note

Debt Instrument [Line Items]

Principal

$ 102,000,000

Debt instrument, interest rate, stated percentage

9.75%

Debt instrument, redemption price, percentage

109.75%

Debt instrument, interest rate terms

semiannually on February 15 and August 15 of each year

2022 Senior Note | Maximum

Debt Instrument [Line Items]

Percentage of principal amount of debt redeemed

35.00%

Senior Notes

Debt Instrument [Line Items]

Principal

$ 172,000,000

Debt instrument, interest rate, stated percentage

11.00%

Payments of debt issuance costs

4,300,000

Senior Notes | 9.75% Senior Notes

Debt Instrument [Line Items]

Principal

$ 102,000,000

$ 102,000,000

Debt instrument, interest rate, stated percentage

9.75%

9.75%

9.75%

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

Debt Instrument [Line Items]

Principal

$ 390,868,000

$ 390,868,000

Debt instrument, interest rate, stated percentage

11.00%

11.00%

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 | 7.50% Senior Secured Notes – due May 2022

Debt Instrument [Line Items]

Principal

$ 6,060,000

$ 6,060,000

Debt instrument, interest rate, stated percentage

7.50%

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 | 9.75% Senior Notes – due February 2018

Debt Instrument [Line Items]

Principal

$ 24,977,000

$ 300,000,000

Debt instrument, interest rate, stated percentage

9.75%

9.75%

9.75%

9.75%

Debt instrument, face amount

$ 25,000,000

Debt instrument maturity date

Feb. 28, 2018

Feb. 15, 2018

Feb. 15, 2018

Bridge Loans

Debt Instrument [Line Items]

Principal

$ 172,000,000

Debt instrument, redemption price, percentage

111.00%

Debt instrument maturity Period

fifth anniversary

Bridge Loans | Maximum

Debt Instrument [Line Items]

Percentage of principal amount of debt redeemed

35.00%

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

Debt Instrument [Line Items]

Principal

$ 172,000,000

$ 172,000,000

Debt instrument, interest rate, stated percentage

11.00%

11.00%

Bridge Loans | 11.00% Bridge Loans – due April 2022

Debt Instrument [Line Items]

Principal

$ 172,023,000

Debt instrument, interest rate, stated percentage

11.00%

11.00%

11.00%

11.00%

Debt instrument, face amount

$ 172,000,000

Debt instrument maturity date

Apr. 30, 2022

Apr. 3, 2022

Apr. 3, 2022

Stone Notes | 7.50% Senior Secured Notes – due May 2022

Debt Instrument [Line Items]

Principal

$ 81,500,000

$ 81,500,000

Debt instrument, interest rate, stated percentage

7.50%

7.50%

Subsequent Event | Bank Credit Facility – due February 2019

Debt Instrument [Line Items]

Debt covenant to EBITDAX

375.00%

Subsequent Event | 2018 Senior Note

Debt Instrument [Line Items]

Debt instrument, repurchase amount

$ 25,000,000

Sponsors

Debt Instrument [Line Items]

Work fees to debt holders

$ 4,100,000

Sponsors | Bridge Loans

Debt Instrument [Line Items]

Principal

$ 39,800,000

Employee Benefits Plans and S50

Employee Benefits Plans and Share-Based Compensation - Additional Information (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	6 Months Ended		12 Months Ended
	May 21, 2018	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Capitalized costs, Oil and natural gas properties					$ 1,088,984	$ 1,039,919
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share based compensation grants	22,963
Options conversion percentage in common stock shares			60.00%
Options conversion percentage in cash			40.00%
Compensation expense recognized period			11 months
Compensation expense unrecognized		$ 700	$ 700
Compensation expense liabilities			$ 300
Executive Severance Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Termination period			12 months
Compensation expense accrued		5,100	$ 5,100
Executive Severance Plan | General and Administrative Expense
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Compensation expense recognized		$ 7,500	$ 7,500
Long Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-Based Compensation authorized to grant		5,415,576	5,415,576
Share-Based Compensation issued			0
Talos Energy LLC Series B Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Capitalized costs, Oil and natural gas properties		$ 200	$ 200	$ 500	900	1,200	$ 1,900
Unrecognized compensation expense					3,400
Unrecognized compensation expense to be recognized over remainder of requisite service period					$ 1,100
Requisite service period					4 years
Talos Energy LLC Series B Units | Series A Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Compensation expense recognized period					24 months
Percentage of compounded annual returns attained covenant			8.00%		8.00%
Unrecognized compensation expense to be recognized upon recoganization of Series A payout					$ 2,200
Talos Energy LLC Series B Units | Series C Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Distribution paid			$ 25,000		$ 25,000
Talos Energy LLC Series B Units | Series B Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-Based Compensation authorized to grant					1,000,000
Compensation expense recognized period			21 months
Unrecognized compensation expense		2,900	$ 2,900
Unrecognized compensation expense to be recognized over remainder of requisite service period		700	$ 700
Requisite service period			4 years
Unrecognized compensation expense to be recognized upon recoganization of Series A payout		2,200	$ 2,200
Talos Energy LLC Series B Units | General and Administrative Expense
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Compensation expense			200	500	$ 900	$ 1,100	$ 1,700
New Talos Energy LLC Series B Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Capitalized costs, Oil and natural gas properties		2,300	2,300
Unrecognized compensation expense		2,400	2,400
Unrecognized compensation expense to be recognized over remainder of requisite service period		300	$ 300
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]
Distribution paid			$ 102,000
Percentage of units to be vested covenant			80.00%
Vesting period			4 years
New Talos Energy LLC Series B Units | New Series A Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Compensation expense recognized period			11 months
Unrecognized compensation expense to be recognized upon recoganization of Series A payout		$ 2,100	$ 2,100
New Talos Energy LLC Series B Units | General and Administrative Expense
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Compensation expense			$ 1,300

Income Taxes - Summary of Defer

Income Taxes - Summary of Deferred Tax Balances (Details) - USD ($)	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Deferred tax asset	$ 213,029,000
Deferred tax liability	(82,805,000)
Net deferred tax asset	130,224,000
Valuation allowance	(130,224,000)	$ (4,000,000)	$ (2,300,000)
Net deferred tax asset	$ 0

Earnings Per Share - Additional

Earnings Per Share - Additional Information (Details) shares in Millions	6 Months Ended
	Jun. 30, 2018$ / sharesshares
Earnings Per Share [Abstract]
Warrants, Outstanding | shares	3.5
Warrants, exercise price | $ / shares	$ 42.04
Warrants, Term	4 years

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	May 10, 2018	Mar. 31, 2015
Related Party Transaction [Line Items]
Proceeds from contributions from affiliates for acquisition and other asset purchases			$ 0	$ 0
Distributions to parent or sponsors			0	0
Work fees to debt holders			$ 9,300,000
Stone Energy Corporation
Related Party Transaction [Line Items]
Closing date of merger agreement			May 10, 2018
Long-term debt, net of discount								$ 235,416,000
Gulf Coast Energy Resources, LLC
Related Party Transaction [Line Items]
Long-term debt, net of discount									$ 55,000,000
Sponsors
Related Party Transaction [Line Items]
Work fees to debt holders			$ 4,100,000
Franklin and McKay Noteholders
Related Party Transaction [Line Items]
Work fees to debt holders			$ 3,300,000
Transaction Fee Agreement | Sponsors
Related Party Transaction [Line Items]
Transaction fee equal to percentage of capital contributions			2.00%		2.00%
Transaction fees related to capital contributions			$ 0	0	$ 0	$ 1,900,000	$ 1,500,000
Contributions and Distributions | Sponsors
Related Party Transaction [Line Items]
Proceeds from contributions from affiliates for acquisition and other asset purchases					0
Transaction fees related to capital contributions						1,900,000	1,500,000
Capital contribution, gross						93,800,000	75,000,000
Capital contribution, net						91,900,000	73,500,000
Contributions and Distributions | Sponsors | Gulf Coast Energy Resources, LLC
Related Party Transaction [Line Items]
Long-term debt, net of discount							55,000,000
Shareholder Service | Transaction Fee Agreement | Sponsors | Stone Energy Corporation
Related Party Transaction [Line Items]
Closing date of merger agreement			May 10, 2018
Shareholder Service | Service Fee Agreement | Sponsors
Related Party Transaction [Line Items]
Service fee	$ 400,000	$ 200,000	$ 500,000	$ 300,000	500,000	$ 500,000	$ 500,000
Shareholder Service | Service Fee Agreement | Sponsors | Maximum
Related Party Transaction [Line Items]
Service fee			$ 500,000		$ 500,000
Shareholder Service | Service Fee Agreement | Sponsors | Stone Energy Corporation
Related Party Transaction [Line Items]
Closing date of merger agreement			May 10, 2018

Condensed Consolidating Finan54

Condensed Consolidating Financial Information - Summary of Condensed Consolidating Financial Position (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 78,860	$ 32,191	$ 32,231
Restricted cash	1,244	1,242	1,202
Accounts receivable, net
Trade, net	100,824	62,871	52,764
Joint interest, net	8,394	13,613	14,673
Other	7,091	12,486	12,400
Assets from price risk management activities	499	1,563	20,176
Prepaid assets	51,698	17,931	18,420
Inventory		840	1,093
Income tax receivable	16,212
Other current assets	3,910	2,148	2,492
Total current assets	268,732	144,885	155,451
Property and equipment:
Proved properties	3,412,875	2,440,811	2,235,835
Unproved properties, not subject to amortization	103,836	72,002	72,360
Other property and equipment	28,884	8,857	8,531
Total property and equipment	3,545,595	2,521,670	2,316,726
Accumulated depreciation, depletion and amortization	(1,547,656)	(1,430,890)	(1,273,538)
Total property and equipment, net	1,997,939	1,090,780	1,043,188
Other long-term assets:
Assets from price risk management activities	234	345	293
Other well equipment inventory	9,021	2,577	12,744
Other assets	8,143	706	622
Total assets	2,284,069	1,239,293	1,212,298
Current liabilities:
Accounts payable	38,731	72,681	31,230
Accrued liabilities	155,902	87,973	49,916
Accrued royalties	28,508	24,208	23,293
Current portion of long-term debt	434	24,977
Current portion of asset retirement obligations	94,334	39,741	33,556
Liabilities from price risk management activities	154,722	49,957	27,147
Accrued interest payable	7,454	8,742	11,376
Other current liabilities	15,541	15,188	14,666
Total current liabilities	495,626	323,467	191,184
Accrued liabilities	155,902	87,973	49,916
Accrued royalties	28,508	24,208	23,293
Current portion of long-term debt	434	24,977
Current portion of asset retirement obligations	94,334	39,741	33,556
Liabilities from price risk management activities	154,722	49,957	27,147
Accrued interest payable	7,454	8,742	11,376
Other current liabilities	15,541	15,188	14,666
Total current liabilities	495,626	323,467	191,184
Long-term debt, net of discount and deferred financing costs	627,968	672,581	701,175
Asset retirement obligations	320,044	174,992	186,493
Liabilities from price risk management activities	31,766	18,781	8,755
Other long-term liabilities	122,820	103,559	117,705
Total liabilities	1,598,224	1,293,380	1,205,312
Commitments and contingencies
Stockholders' equity (deficit) \ Member’s equity (deficit)	685,845	(54,087)	6,986	$ 120,895	$ 690,502
Total liabilities and equity	2,284,069	1,239,293	1,212,298
Long-term debt, net of discount and deferred financing costs	627,968	672,581	701,175
Asset retirement obligations	320,044	174,992	186,493
Liabilities from price risk management activities	31,766	18,781	8,755
Other long-term liabilities	122,820	103,559	117,705
Total liabilities	1,598,224	1,293,380	1,205,312
Commitments and contingencies
Stockholders' equity (deficit) \ Member’s equity (deficit)	685,845	(54,087)	6,986	$ 120,895	$ 690,502
Total liabilities and equity	2,284,069	1,239,293	1,212,298
Talos
Other long-term assets:
Investments in subsidiaries	685,845	(54,087)	6,986
Total assets	685,845	(54,087)	6,986
Current liabilities:
Commitments and contingencies
Stockholders' equity (deficit) \ Member’s equity (deficit)	685,845	(54,087)	707,371
Total liabilities and equity	685,845	(54,087)	6,986
Commitments and contingencies
Stockholders' equity (deficit) \ Member’s equity (deficit)	685,845	(54,087)	707,371
Total liabilities and equity	685,845	(54,087)	6,986
Talos Issuers
Current assets:
Cash and cash equivalents	35,385	22,315	24,349
Accounts receivable, net
Other		938	9,476
Assets from price risk management activities	478	1,406	20,176
Total current assets	35,863	24,659	54,001
Property and equipment:
Other property and equipment	27,293	7,266	7,007
Total property and equipment	27,293	7,266	7,007
Accumulated depreciation, depletion and amortization	(7,080)	(6,355)	(4,954)
Total property and equipment, net	20,213	911	2,053
Other long-term assets:
Assets from price risk management activities	234	345	293
Investments in subsidiaries	1,440,601	697,663	700,385
Other assets	364	364	48
Total assets	1,497,275	723,942	756,780
Current liabilities:
Accounts payable	9,894	1,124	133
Accrued liabilities	4,235	6,516	1,208
Current portion of long-term debt	434	24,977
Liabilities from price risk management activities	141,118	46,580	27,147
Accrued interest payable	7,064	8,742	11,376
Total current liabilities	162,745	87,939	39,864
Accrued liabilities	4,235	6,516	1,208
Current portion of long-term debt	434	24,977
Liabilities from price risk management activities	141,118	46,580	27,147
Accrued interest payable	7,064	8,742	11,376
Total current liabilities	162,745	87,939	39,864
Long-term debt, net of discount and deferred financing costs	621,908	672,581	701,175
Liabilities from price risk management activities	26,777	17,509	8,755
Total liabilities	811,430	778,029	749,794
Commitments and contingencies
Stockholders' equity (deficit) \ Member’s equity (deficit)	685,845	(54,087)	6,986
Total liabilities and equity	1,497,275	723,942	756,780
Long-term debt, net of discount and deferred financing costs	621,908	672,581	701,175
Liabilities from price risk management activities	26,777	17,509	8,755
Total liabilities	811,430	778,029	749,794
Commitments and contingencies
Stockholders' equity (deficit) \ Member’s equity (deficit)	685,845	(54,087)	6,986
Total liabilities and equity	1,497,275	723,942	756,780
Guarantors
Current assets:
Cash and cash equivalents	40,940	7,806	5,550
Restricted cash	1,244	1,242	1,202
Accounts receivable, net
Trade, net	100,824	62,871	52,764
Joint interest, net	6,638	11,659	7,569
Other	832	5,863	531
Assets from price risk management activities	21	157
Prepaid assets	51,672	17,919	18,411
Inventory		840	1,093
Income tax receivable	16,212
Other current assets	3,910	2,148	2,492
Total current assets	222,293	110,505	89,612
Property and equipment:
Proved properties	3,412,875	2,440,811	2,235,835
Unproved properties, not subject to amortization	70,590	41,259	64,949
Other property and equipment	1,580	1,580	1,513
Total property and equipment	3,485,045	2,483,650	2,302,297
Accumulated depreciation, depletion and amortization	(1,540,566)	(1,424,527)	(1,268,580)
Total property and equipment, net	1,944,479	1,059,123	1,033,717
Other long-term assets:
Other well equipment inventory	9,021	2,577	12,744
Other assets	7,712	326	574
Total assets	2,183,505	1,172,531	1,136,647
Current liabilities:
Accounts payable	28,728	70,458	27,570
Accrued liabilities	150,206	80,464	48,318
Accrued royalties	28,508	24,208	23,293
Current portion of asset retirement obligations	94,334	39,741	33,556
Liabilities from price risk management activities	13,604	3,377
Accrued interest payable	390
Other current liabilities	15,541	15,188	14,666
Total current liabilities	331,311	233,436	147,403
Accrued liabilities	150,206	80,464	48,318
Accrued royalties	28,508	24,208	23,293
Current portion of asset retirement obligations	94,334	39,741	33,556
Liabilities from price risk management activities	13,604	3,377
Accrued interest payable	390
Other current liabilities	15,541	15,188	14,666
Total current liabilities	331,311	233,436	147,403
Long-term debt, net of discount and deferred financing costs	6,060
Asset retirement obligations	320,044	174,992	186,493
Liabilities from price risk management activities	4,989	1,272
Other long-term liabilities	122,820	103,559	117,705
Total liabilities	785,224	513,259	451,601
Commitments and contingencies
Stockholders' equity (deficit) \ Member’s equity (deficit)	1,398,281	659,272	685,046
Total liabilities and equity	2,183,505	1,172,531	1,136,647
Long-term debt, net of discount and deferred financing costs	6,060
Asset retirement obligations	320,044	174,992	186,493
Liabilities from price risk management activities	4,989	1,272
Other long-term liabilities	122,820	103,559	117,705
Total liabilities	785,224	513,259	451,601
Commitments and contingencies
Stockholders' equity (deficit) \ Member’s equity (deficit)	1,398,281	659,272	685,046
Total liabilities and equity	2,183,505	1,172,531	1,136,647
Non-Guarantors
Current assets:
Cash and cash equivalents	2,535	2,070	2,332
Accounts receivable, net
Joint interest, net	1,756	1,954	7,104
Other	6,259	5,685	2,393
Prepaid assets	26	12	9
Total current assets	10,576	9,721	11,838
Property and equipment:
Unproved properties, not subject to amortization	33,246	30,743	7,411
Other property and equipment	11	11
Total property and equipment	33,257	30,754	7,422
Accumulated depreciation, depletion and amortization	(10)	(8)	(4)
Total property and equipment, net	33,247	30,746	7,418
Other long-term assets:
Other assets	67	16
Total assets	43,890	40,483	19,256
Current liabilities:
Accounts payable	109	1,099	3,527
Accrued liabilities	1,461	993	390
Total current liabilities	1,570	2,092	3,917
Accrued liabilities	1,461	993	390
Total current liabilities	1,570	2,092	3,917
Total liabilities	1,570	2,092	3,917
Commitments and contingencies
Stockholders' equity (deficit) \ Member’s equity (deficit)	42,320	38,391	15,339
Total liabilities and equity	43,890	40,483	19,256
Total liabilities	1,570	2,092	3,917
Commitments and contingencies
Stockholders' equity (deficit) \ Member’s equity (deficit)	42,320	38,391	15,339
Total liabilities and equity	43,890	40,483	19,256
Elimination
Other long-term assets:
Investments in subsidiaries	(2,126,446)	(643,576)	(6,986)
Total assets	(2,126,446)	(643,576)	(707,371)
Current liabilities:
Commitments and contingencies
Stockholders' equity (deficit) \ Member’s equity (deficit)	(2,126,446)	(643,576)	(707,371)
Total liabilities and equity	(2,126,446)	(643,576)	(707,371)
Commitments and contingencies
Stockholders' equity (deficit) \ Member’s equity (deficit)	(2,126,446)	(643,576)	(707,371)
Total liabilities and equity	$ (2,126,446)	$ (643,576)	$ (707,371)

Summary of Significant Accoun55

Summary of Significant Accounting Policies - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Aug. 31, 2016
Summary Of Significant Accounting Policies [Line Items]
Allowance for uncollectible accounts					$ 5,900	$ 4,900
Capital lease asset								$ 124,300
Write-down of oil and natural gas properties under ceiling test	$ 0	$ 0	$ 0	$ 0			$ 603,388
Transportation costs					10,300	9,100	10,500
Impairment to adjust other well equipment inventory					260	218	2,106
Valuation allowances	130,224		130,224		4,000	2,300
Prepaid assets	51,698		51,698		17,931	18,420
Accrued liabilities	$ 155,902		$ 155,902		$ 87,973	49,916
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, estimated useful lives					3 years
Maximum
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, estimated useful lives					5 years
Measurement Input Discount Rate
Summary Of Significant Accounting Policies [Line Items]
Present value of future net revenues from proved reserves, discounted rate			10.00%		10.00%
Other Current Assets
Summary Of Significant Accounting Policies [Line Items]
Imbalance receivable					$ 2,100	2,100	2,100
Prepaid assets					7,300
Accrued Liabilities
Summary Of Significant Accounting Policies [Line Items]
Imbalance payable					2,700	$ 2,800	$ 2,600
Accounts Payable
Summary Of Significant Accounting Policies [Line Items]
Accrued liabilities					$ 73,500

Summary of Significant Accoun56

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Shell Trading (US) Company
Concentration Risk [Line Items]
Concentration risk, percentage	80.00%	68.00%	68.00%
Chevron U.S.A Inc
Concentration Risk [Line Items]
Concentration risk, percentage		14.00%	16.00%

Summary of Significant Accoun57

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Concentration risk, percentage		14.00%	16.00%
Maximum
Concentration Risk [Line Items]
Concentration risk, percentage	10.00%

Summary of Significant Accoun58

Summary of Significant Accounting Policies - Summary of Supplementary Cash Flow Information (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities	$ 38,205	$ 30,712	$ 40,626,000	$ 13,832,000	$ 30,125,000
Fair value of assets acquired					75,519,000
Fair value of liabilities assumed					75,519,000
Capital lease transaction				124,300,000
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized	$ 23,635	$ 25,405	$ 47,994,000	$ 55,254,000	$ 37,247,000

Acquisitions - Additional Infor

Acquisitions - Additional Information (Details) $ in Thousands	May 10, 2018USD ($)	Nov. 21, 2017shares	Dec. 20, 2016USD ($)$ / bbl	Apr. 08, 2015USD ($)	Mar. 31, 2015USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2015USD ($)	Apr. 15, 2015
Business Acquisition [Line Items]
Common stock received for each share | shares		34.2
Percentage of voting interest acquired	63.00%	63.00%
Stone Energy Corporation
Business Acquisition [Line Items]
Percentage of voting interest acquired	37.00%	37.00%
Total consideration and fair value	$ 731,964
Long-term debt, net of discount	235,416
Payout under the earn-out	$ 175,082
Acquisition, transaction related cost						$ 76,200
Acquisition, transaction related fees to note holders and for seismic use agreements						56,100
Acquisition, transaction related fees paid to note holders						9,300
Acquisition, transaction related fees for seismic use agreements						46,800
Sojitz Energy Venture Inc
Business Acquisition [Line Items]
Percentage of voting interest acquired			15.00%
Business acquisition purchase price in cash			$ 85,800
Total consideration and fair value			93,800
Business acquisition purchase price net			91,900
Business acquisition transaction fees			$ 1,900
Consideration earn out percentage			5.00%
Oil price realized | $ / bbl			65
Payout under the earn-out			$ 10,000
Purchase price and working capital adjustments							$ 2,500
Deep Gulf Energy III, LLC
Business Acquisition [Line Items]
Percentage of voting interest acquired				25.00%
Business acquisition purchase price in cash				$ 38,500
Total consideration and fair value				75,000
Business acquisition purchase price net				73,500
Business acquisition transaction fees				$ 1,500
Deep Gulf Energy III, LLC | Tornado exploration prospect
Business Acquisition [Line Items]
Percentage of voting interest acquired				10.00%
Gulf Coast Energy Resources, LLC
Business Acquisition [Line Items]
Business acquisition transaction fees					$ 800
Payout under the earn-out					6,500
Long-term debt, net of discount					55,000
Payout under the earn-out					118
Revenue attributable to the assets acquired								$ 12,600
Net loss attributable to the assets acquired								9,700
Depletion and accretion expense								$ 15,600
Gulf Coast Energy Resources, LLC | Recognize estimated liability if the oil and natural gas assets acquired meet certain targets within the subsequent five years
Business Acquisition [Line Items]
Payout under the earn-out					$ 100
Talos Energy
Business Acquisition [Line Items]
Percentage of voting interest acquired	63.00%
General and Administrative Expense | Stone Energy Corporation
Business Acquisition [Line Items]
Acquisition, transaction related cost						$ 20,100
Senior Notes
Business Acquisition [Line Items]
Debt instrument interest rate									11.00%
Senior Notes | Second Priority Senior Secured Notes
Business Acquisition [Line Items]
Debt instrument interest rate						11.00%

Acquisitions - Summary of Pre60

Acquisitions - Summary of Preliminary Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	May 10, 2018	Dec. 20, 2016	Apr. 08, 2015	Mar. 31, 2015
Sojitz Energy Venture Inc
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)
Cash Paid		$ 88,238
Deep Gulf Energy III, LLC
Business Acquisition [Line Items]
Proved properties			$ 24,316
Unproved properties, not subject to amortization			14,643
Asset retirement obligations			(442)
Cash Paid			$ 38,517
Gulf Coast Energy Resources, LLC
Business Acquisition [Line Items]
Proved properties				$ 38,680
Unproved properties, not subject to amortization				22,637
Asset retirement obligations				(744)
Cash Paid
Current assets				12,748
Other non-current assets				536
Total assets acquired				74,601
Current portion of asset retirement obligations				107
Other current liabilities				18,632
Long-term debt, net of discount				55,000
Other long-term liabilities				118
Total liabilities assumed				$ 74,601
Stone Energy Corporation
Business Acquisition [Line Items]
Current assets	$ 377,155
Other non-current assets	18,928
Long-term debt, net of discount	235,416
Other long-term liabilities	175,082
Property and equipment	876,500
Current liabilities	(130,121)
Allocated purchase price	$ 731,964

Acquisitions - Schedule of Fair

Acquisitions - Schedule of Fair Value Current Assets Acquired Includes Receivables (Details) $ in Thousands	Mar. 31, 2015USD ($)
Trade Accounts Receivable
Business Acquisition [Line Items]
Gross Receivable	$ 3,104
Fair Value	3,104
Joint Interest Receivables
Business Acquisition [Line Items]
Gross Receivable	3,484
Expected Uncollectable Amount	(323)
Fair Value	3,161
Other receivables
Business Acquisition [Line Items]
Gross Receivable	196
Fair Value	$ 196

Property, Plant and Equipment62

Property, Plant and Equipment - Additional Information (Details) $ in Thousands	3 Months Ended			6 Months Ended		9 Months Ended	12 Months Ended
	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)LeaseBlock	Mar. 31, 2017USD ($)LeaseBlock	Jun. 30, 2018USD ($)$ / bbl$ / Mcf	Jun. 30, 2017USD ($)LeaseBlock	Sep. 30, 2015USD ($)$ / bbl$ / Mcf	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)$ / bbl$ / Mcf	Aug. 31, 2016USD ($)	Sep. 04, 2015LeaseBlock
Property, Plant and Equipment [Line Items]
capital lease							$ 93,669			$ 124,300
Write-down of oil and natural gas properties under ceiling test	$ 0	$ 0		$ 0	$ 0				$ 603,388
Unweighted average first day of month commodity price for crude oil for prior twelve months | $ / bbl				60.03
Unweighted average first day of month commodity price for natural gas for prior twelve months | $ / Mcf				2.90
Unweighted average first day of month commodity price for natural gas liquids for prior twelve months | $ / bbl				28.26
Unproved properties, number of lease blocks awarded | LeaseBlock			6								2
Unproved properties, number of high bids in bureau of ocean energy management phase Two evaluation process | LeaseBlock		6			6
Lease rentals expense		$ 2,600	$ 2,600
Capitalized interest							600	400	3,900
Capitalized overhead costs	$ 4,500	$ 3,100		$ 7,500	$ 6,500		$ 13,700	$ 12,500	14,100
US
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties under ceiling test						$ 279,300			$ 324,100
Unweighted average first day of month commodity price for crude oil for prior twelve months | $ / bbl						61.22			50.72
Unweighted average first day of month commodity price for natural gas for prior twelve months | $ / Mcf						3.29			2.75
Unweighted average first day of month commodity price for natural gas liquids for prior twelve months | $ / bbl						20.65			17.60
Measurement Input Discount Rate
Property, Plant and Equipment [Line Items]
Present value of future net revenues from proved reserves, discounted rate				10.00%			10.00%

Property, Plant and Equipment63

Property, Plant and Equipment - Summary of Oil and Natural Gas Property Costs Not Being Amortized (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	$ 23,871
Exploration	48,131
Total unproved properties, not subject to amortization	72,002
2,017
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Exploration	27,137
Total unproved properties, not subject to amortization	27,137
2,016
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	3,845
Exploration	7,174
Total unproved properties, not subject to amortization	11,019
2,015
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	4,089
Exploration	2,621
Total unproved properties, not subject to amortization	6,710
2014 and Prior
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	15,937
Exploration	11,199
Total unproved properties, not subject to amortization	$ 27,136

Employee Incentive Programs - A

Employee Incentive Programs - Additional information (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Capitalized costs, Oil and natural gas properties			$ 1,088,984	$ 1,039,919
Series B Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units outstanding			234,440	326,454	374,659	642,355
Talos Energy LLC Series B Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Capitalized costs, Oil and natural gas properties	$ 200	$ 500	$ 900	$ 1,200	$ 1,900
Unrecognized compensation expense			3,400
Unrecognized compensation expense to be recognized over remainder of requisite service period			$ 1,100
Requisite service period			4 years
Talos Energy LLC Series B Units | General and Administrative Expense
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Compensation expense	200	$ 500	$ 900	$ 1,100	$ 1,700
Talos Energy LLC Series B Units | Series B Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-Based Compensation authorized to grant			1,000,000
Units outstanding			992,850	980,250	906,000
Unrecognized compensation expense	2,900
Unrecognized compensation expense to be recognized over remainder of requisite service period	$ 700
Requisite service period	4 years
Unrecognized compensation expense to be recognized upon recoganization of Series A payout	$ 2,200
Units expected to be recognized			135,712
Compensation expense recognized period	21 months
Units authorized and not yet issued			7,150
Talos Energy LLC Series B Units | Series B Units | Monthly Basis Subject to Continued Employment.
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of units to be vested covenant			80.00%
Vesting period			4 years
Talos Energy LLC Series B Units | Series B Units | Upon Occurrence of Liquidation Event or Approved Sale or Public Offering
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of units to be vested covenant			20.00%
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%		8.00%
Unrecognized compensation expense to be recognized upon recoganization of Series A payout			$ 2,200
Compensation expense recognized period			24 months
Talos Energy LLC Series B Units | Series C Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Distribution paid	$ 25,000		$ 25,000

Employee Incentive Programs - S

Employee Incentive Programs - Summary of Series B Unit Activity (Details) - Series B Units - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Non-vested number of units, beginning of the period	326,454	374,659	642,355
Non-vested number of units, Granted	35,100	147,000
Non-vested number of units, Vested	(104,614)	(122,455)	(175,196)
Non-vested number of units, Forfeited or cancelled	(22,500)	(72,750)	(92,500)
Non-vested number of units, end of the period	234,440	326,454	374,659
Non-vested weighted average estimated fair value, beginning of the period	$ 14.57	$ 21.07	$ 21.04
Non-vested weighted average estimated fair value, Granted	20.99	4.11
Non-vested weighted average estimated fair value, Vested	17.16	17.95	20.43
Non-vested weighted average estimated fair value, Forfeited or cancelled	15.10	21.22	22.08
Non-vested weighted average estimated fair value, end of the period	$ 14.32	$ 14.57	$ 21.07

Employee Incentive Programs -66

Employee Incentive Programs - Summary of Fair Value Grant Estimated Using Weighted Average Assumptions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Assumed value of equity (in thousands)	$ 789,426	$ 196,280
Risk-free rate of interest	1.16%	1.11%
Expected time to a liquidity event (in years)	1 year	3 years
Expected volatility of equity	40.00%	70.00%
Discount for lack of marketability	25.00%	34.00%

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Jun. 30, 2018	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Deferred tax assets, valuation allowance	$ 4,000,000	$ 130,224,000	$ 2,300,000
Foreign tax loss carryforwards	$ 13,400,000
Foreign tax loss carryforwards expiration year	2,025
Net deferred tax balance		0
Income taxes receivable, current		$ 16,200,000

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($)

Jun. 18, 2018

Jun. 18, 2018

Jun. 01, 2018

Jun. 01, 2018

Feb. 08, 2018

Feb. 08, 2018

Apr. 06, 2016

Dec. 31, 2017

Jun. 30, 2018

Feb. 07, 2018

Jan. 23, 2018

Dec. 31, 2016

Dec. 29, 2016

Aug. 02, 2016

Loss Contingencies [Line Items]

Fixed annual demand fee

$ 245,417,000

Capital Lease obligations

$ 93,700,000

$ 99,700,000

$ 124,300,000

Amount of penalty paid

$ 4,200,000

Term of Probation

3 years

Interest rate, stated percentage

$ 500,000

Helix’s Q4000 Vessel

Loss Contingencies [Line Items]

Minimum number of days contracted

20 days

Agreement payments due in 2019

$ 6,500,000

Agreement payments for 2019

6,700,000

Drilling Rig

Loss Contingencies [Line Items]

Agreement payments exceed one year term

0

Agreement payments

3,900,000

Ensco 75 Jackup Drilling Rig

Loss Contingencies [Line Items]

Minimum number of days contracted

90 days

90 days

120 days

120 days

Agreement payments

$ 6,300,000

$ 6,300,000

$ 7,800,000

$ 7,800,000

14,100,000

Ensco 8503 Drilling Rig

Loss Contingencies [Line Items]

Minimum number of days contracted

100 days

100 days

Agreement payments due in 2019

5,100,000

Agreement payments

7,900,000

Subsequent Event

Loss Contingencies [Line Items]

Cancellation of performance bonds

$ 22,300,000

Subsequent Event | Ensco 75 Jackup Drilling Rig

Loss Contingencies [Line Items]

Minimum number of days contracted

60 days

Agreement payments due in 2019

$ 7,800,000

$ 7,800,000

$ 3,900,000

Bank Credit Facility | Letter of Credit

Loss Contingencies [Line Items]

Credit facility

4,900,000

$ 4,000,000

Production Sharing Contracts | Mexico

Loss Contingencies [Line Items]

Performance obligations

287,800,000

569,300,000

$ 338,200,000

Other Current Liabilities

Loss Contingencies [Line Items]

Capital Lease obligations

106,600,000

12,700,000

Other Long-term Liabilities

Loss Contingencies [Line Items]

Capital Lease obligations

12,900,000

87,000,000

Seven-Year Lease Agreement

Loss Contingencies [Line Items]

Lease agreement term

7 years

Annual fixed demand charge during first two years

$ 49,000,000

Anual fixed demand charge thereafter

45,000,000

Quarterly incentive payment to be paid during first two ywears

500,000

Quarterly incentive to be paid thereafter

800,000

Fixed annual demand fee

$ 33,000,000

Throughput charge, percentage

10.00%

Office Lease Obligations

Loss Contingencies [Line Items]

Operating leases, future minimum payments due in 2018

4,100,000

Operating leases, future minimum payments due in 2019

4,300,000

Operating leases, future minimum payments due in 2020

3,800,000

Operating leases, future minimum payments due in 2021

3,800,000

Operating leases, future minimum payments due in thereafter

$ 30,500,000

Stone Energy Corporation

Loss Contingencies [Line Items]

Performance obligations

46,800,000

Agreement payments for 2019

10,900,000

Agreement payments

29,800,000

Agreement payments for remainder of 2018

6,600,000

Agreement payments for 2020

9,900,000

Agreement payments for 2021

$ 2,400,000

Commitments and Contingencies69

Commitments and Contingencies - Schedule of Future Minimum Lease Commitments (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Aug. 31, 2016
Leases [Abstract]
2,018	$ 46,667
2,019	45,000
2,020	45,000
2,021	45,000
2,022	45,000
Thereafter	18,750
Total minimum lease payments	245,417
Less amount represented lease operating expenses	(63,607)
Less amount represented interest	(75,189)
Present value of minimum lease payments	106,621
Less current maturities of capital lease obligations	(12,952)
Long-term capital lease obligations	$ 93,669	$ 124,300

Condensed Consolidating Finan70

Condensed Consolidating Financial Information - Additional Information (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	May 10, 2018
Percentage of equity interest	100.00%	100.00%
11.00% Second-Priority Senior Secured Notes
Debt instrument interest rate			11.00%

Condensed Consolidating Finan71

Condensed Consolidating Financial Information - Summary of Condensed Consolidating Results Of Operations (Details) - USD ($) $ in Thousands	3 Months Ended											6 Months Ended				12 Months Ended
	Jun. 30, 2018		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017		Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2018		Jun. 30, 2017		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Revenues:
Total revenue	$ 203,906		$ 115,616	$ 99,962	$ 95,426		$ 101,824	$ 76,918	$ 63,775	$ 67,405	$ 50,656	$ 349,756		$ 197,250		$ 412,828		$ 258,754		$ 315,606
Operating expenses:
Direct lease operating expense	34,060				28,871							58,975		56,735		109,180		124,360		171,095
Insurance	4,259				2,688							6,934		5,409		10,743		13,101		17,965
Production taxes	564				380							955		645		1,460		1,958		3,311
Total lease operating expense	38,883				31,939							66,864		62,789		121,383		139,419		192,371
Workover and maintenance expense	17,714				8,225							24,619		17,047		32,825		24,810		29,752
Depreciation, depletion and amortization	67,726				36,157							116,766		76,088		157,352		124,689		212,689
Write-down of oil and natural gas properties under ceiling test	0				0							0		0						603,388
Accretion expense	9,492				5,321							14,252		10,509		19,295		21,829		19,395
General and administrative expense	30,880				7,470							39,460		17,216		36,673		28,686		35,662
Total operating expenses	164,695				89,112							261,961		183,649		367,528		339,433		1,093,257
Operating income (loss)	39,211		18,370	13,329	6,314		7,287	(7,103)	(12,868)	(20,697)	(40,011)	87,795		13,601		45,300		(80,679)		(777,651)
Interest expense	(21,678)				(20,805)							(41,420)		(39,577)		(80,934)		(70,415)		(51,544)
Price risk management activities income (expense)	(91,176)	[1]	(84,365)	(28,086)	38,995	[1]	45,893	(32,742)	11,350	(48,930)	12,924	(143,152)	[1]	84,888	[1]	(27,563)	[2]	(57,398)	[2]	182,196	[2]
Other income (expense)	(1,269)				103							(1,078)		157		329		405		314
Net income (loss)	(74,912)		$ (85,760)	$ (36,177)	24,607		$ 34,462	$ (60,354)	$ (22,219)	$ (84,715)	$ (40,799)	(97,855)		59,069		(62,868)		(208,087)		(646,685)
Talos
Operating expenses:
Equity earnings from subsidiaries	(74,912)				24,607							(97,855)		59,069		(62,868)		(208,087)		(646,685)
Net income (loss)	(74,912)				24,607							(97,855)		59,069		(62,868)		(208,087)		(646,685)
Talos Issuers
Operating expenses:
Depreciation, depletion and amortization	384				353							725		722		1,401		1,553		1,528
General and administrative expense	13,804				3,775							18,398		10,166		21,882		13,204		19,630
Total operating expenses	14,188				4,128							19,123		10,888		23,283		14,757		21,158
Operating income (loss)	(14,188)				(4,128)							(19,123)		(10,888)		(23,283)		(14,757)		(21,158)
Interest expense	(14,399)				(11,487)							(26,627)		(23,501)		(48,236)		(47,291)		(46,235)
Price risk management activities income (expense)	(89,970)				36,040							(139,217)		81,541		(22,998)		(57,398)		182,196
Other income (expense)	(1,358)				150							(1,208)		300		600				129
Equity earnings from subsidiaries	45,003				4,032							88,320		11,617		31,049		(88,641)		(761,617)
Net income (loss)	(74,912)				24,607							(97,855)		59,069		(62,868)		(208,087)		(646,685)
Guarantors
Revenues:
Total revenue	203,906				95,426							349,756		197,250		412,828		258,754		315,606
Operating expenses:
Direct lease operating expense	34,060				28,871							58,975		56,735		109,180		124,360		171,095
Insurance	4,259				2,688							6,934		5,409		10,743		13,101		17,965
Production taxes	564				380							955		645		1,460		1,958		3,311
Total lease operating expense	38,883				31,939							66,864		62,789		121,383		139,419		192,371
Workover and maintenance expense	17,714				8,225							24,619		17,047		32,825		24,810		29,752
Depreciation, depletion and amortization	67,341				35,803							116,039		75,364		155,947		123,132		211,161
Write-down of oil and natural gas properties under ceiling test																				603,388
Accretion expense	9,492				5,321							14,252		10,509		19,295		21,829		19,395
General and administrative expense	16,854				3,531							20,567		6,621		14,172		15,044		14,541
Total operating expenses	150,284				84,819							242,341		172,330		343,622		324,234		1,070,608
Operating income (loss)	53,622				10,607							107,415		24,920		69,206		(65,480)		(755,002)
Interest expense	(6,891)				(7,695)							(13,957)		(14,723)		(30,252)		(19,680)		(4,080)
Price risk management activities income (expense)	(1,206)				2,955							(3,935)		3,347		(4,565)
Other income (expense)	132				(87)							85		(162)		(333)		430		176
Net income (loss)	45,657				5,780							89,608		13,382		34,056		(84,730)		(758,906)
Non-Guarantors
Operating expenses:
Depreciation, depletion and amortization	1				1							2		2		4		4
General and administrative expense	222				164							495		429		619		438		1,491
Total operating expenses	223				165							497		431		623		442		1,491
Operating income (loss)	(223)				(165)							(497)		(431)		(623)		(442)		(1,491)
Interest expense	(388)				(1,623)							(836)		(1,353)		(2,446)		(3,444)		(1,229)
Other income (expense)	(43)				40							45		19		62		(25)		9
Net income (loss)	(654)				(1,748)							(1,288)		(1,765)		(3,007)		(3,911)		(2,711)
Elimination
Operating expenses:
Equity earnings from subsidiaries	29,909				(28,639)							9,535		(70,686)		31,819		296,728		1,408,302
Net income (loss)	29,909				(28,639)							9,535		(70,686)		31,819		296,728		1,408,302
Oil Revenue
Revenues:
Revenue	180,161				78,719							307,854		162,487		344,781		197,583		244,167
Oil Revenue | Guarantors
Revenues:
Revenue	180,161				78,719							307,854		162,487		344,781		197,583		244,167
Natural Gas Revenue
Revenues:
Revenue	16,448				12,888							29,171		26,062		48,886		42,705		55,026
Natural Gas Revenue | Guarantors
Revenues:
Revenue	16,448				12,888							29,171		26,062		48,886		42,705		55,026
NGL Revenue
Revenues:
Revenue	7,297				3,436							12,731		7,069		16,658		9,532		10,523
NGL Revenue | Guarantors
Revenues:
Revenue	$ 7,297				3,436							$ 12,731		7,069		16,658		9,532		10,523
Other
Revenues:
Revenue					383									1,632		2,503		8,934		5,890
Other | Guarantors
Revenues:
Revenue					$ 383									$ 1,632		$ 2,503		$ 8,934		$ 5,890
[1]	The Company paid $33.6 million and received $9.2 million in net cash settlements for the three months ended June 30, 2018 and 2017, respectively, and paid $54.1 million and received $13.7 million in net cash settlements for the six months ended June 30, 2018 and 2017, respectively.
[2]	The Company received net cash settlements of $23.8 million, $172.2 million and $181.9 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Condensed Consolidating Finan72

Condensed Consolidating Financial Information - Summary of Condensed Consolidating Cash Flows (Details) - USD ($)	6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$ 107,111,000	$ 85,263,000	$ 176,053,000	$ 116,123,000	$ 138,366,000
Cash flows from investing activities:
Exploration, development, and other capital expenditures	(140,968,000)	(62,535,000)	(155,177,000)	(113,032,000)	(245,716,000)
Cash paid for acquisitions, net of cash acquired	293,001,000	(2,244,000)	(2,464,000)	(85,886,000)	(39,423,000)
Net cash provided by (used in) investing activities	152,033,000	(64,779,000)	(157,641,000)	(198,918,000)	(285,139,000)
Cash flows from financing activities:
Repayment of Old Bank Credit Facility	(403,000,000)
Redemption of Senior Notes and other long-term debt	(25,046,000)	(1,000,000)	(1,000,000)
Proceeds from Bank Credit Facility	294,000,000	10,000,000	10,000,000	15,000,000	120,000,000
Repayment of Bank Credit Facility	(54,000,000)	(15,000,000)	(15,000,000)	(10,000,000)	(30,000,000)
Deferred financing costs	(17,469,000)				(269,000)
Payments of capital lease	(6,958,000)	(5,870,000)	(12,412,000)	(5,267,000)
Distributions to subsidiary issuer	0	0
Contributions from Sponsors				93,750,000	75,000,000
Distributions to subsidiaries				(1,859,000)	(1,500,000)
Net cash provided by (used in) financing activities	(212,473,000)	(11,870,000)	(18,412,000)	91,624,000	108,231,000
Net increase (decrease) in cash, cash equivalents and restricted cash	46,671,000	8,614,000		8,829,000	(38,542,000)
Cash, cash equivalents and restricted cash:
Balance, beginning of period	33,433,000	33,433,000	33,433,000	24,604,000	63,146,000
Balance, end of period	80,104,000	42,047,000	33,433,000	33,433,000	24,604,000
GCER Bank Credit Facility
Cash flows from financing activities:
Repayment of Bank Credit Facility					(55,000,000)
Old Bank Credit Facility
Cash flows from financing activities:
Proceeds from Bank Credit Facility		10,000,000
Repayment of Bank Credit Facility	(403,000,000)	(15,000,000)
Talos
Cash flows from investing activities:
Investments in subsidiaries				(91,891,000)	(73,500,000)
Net cash provided by (used in) investing activities				(91,891,000)	(73,500,000)
Cash flows from financing activities:
Contributions from Sponsors				93,750,000	75,000,000
Distributions to subsidiaries				(1,859,000)	(1,500,000)
Net cash provided by (used in) financing activities				91,891,000	73,500,000
Talos Issuers
Cash flows from operating activities:
Net cash provided by (used in) operating activities	(54,941,000)	(16,268,000)	(30,245,000)	124,698,000	81,598,000
Cash flows from investing activities:
Exploration, development, and other capital expenditures	(20,027,000)	(73,000)	(260,000)	(301,000)	(2,380,000)
Investments in subsidiaries	(384,089,000)	(287,689,000)	(577,055,000)	(524,192,000)	(579,822,000)
Distributions from subsidiaries	677,573,000	292,580,000	611,526,000	411,074,000	300,891,000
Net cash provided by (used in) investing activities	273,457,000	4,818,000	34,211,000	(113,419,000)	(281,311,000)
Cash flows from financing activities:
Repayment of Old Bank Credit Facility	(403,000,000)
Redemption of Senior Notes and other long-term debt	(24,977,000)	(1,000,000)	(1,000,000)
Proceeds from Bank Credit Facility	294,000,000	10,000,000	10,000,000	15,000,000	120,000,000
Repayment of Bank Credit Facility	(54,000,000)	(15,000,000)	(15,000,000)	(10,000,000)	(30,000,000)
Deferred financing costs	(17,469,000)				(269,000)
Capital contributions					73,500,000
Net cash provided by (used in) financing activities	(205,446,000)	(6,000,000)	(6,000,000)	5,000,000	163,231,000
Net increase (decrease) in cash, cash equivalents and restricted cash	13,070,000	(17,450,000)	(2,034,000)	16,279,000	(36,482,000)
Cash, cash equivalents and restricted cash:
Balance, beginning of period	22,315,000	24,349,000	24,349,000	8,070,000	44,552,000
Balance, end of period	35,385,000	6,899,000	22,315,000	24,349,000	8,070,000
Talos Issuers | Old Bank Credit Facility
Cash flows from financing activities:
Repayment of Bank Credit Facility	(403,000,000)
Guarantors
Cash flows from operating activities:
Net cash provided by (used in) operating activities	160,304,000	84,651,000	204,419,000	(2,806,000)	55,946,000
Cash flows from investing activities:
Exploration, development, and other capital expenditures	(117,667,000)	(54,770,000)	(132,317,000)	(106,647,000)	(242,203,000)
Cash paid for acquisitions, net of cash acquired	293,001,000	(2,244,000)	(2,464,000)	(85,886,000)	(39,423,000)
Distributions from subsidiaries	9,000	1,527,000	6,041,000
Net cash provided by (used in) investing activities	175,343,000	(55,487,000)	(128,740,000)	(192,533,000)	(281,626,000)
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt	(69,000)
Payments of capital lease	(6,958,000)	(5,870,000)	(12,412,000)	(5,267,000)
Capital contributions	382,089,000	279,689,000	550,555,000	599,630,000	578,643,000
Distributions to subsidiary issuer	(677,573,000)	(292,580,000)	(611,526,000)	(408,050,000)	(300,779,000)
Contributions from Sponsors	382,089,000	279,689,000
Distributions to subsidiaries	(677,573,000)	(292,580,000)
Net cash provided by (used in) financing activities	(302,511,000)	(18,761,000)	(73,383,000)	186,313,000	222,864,000
Net increase (decrease) in cash, cash equivalents and restricted cash	33,136,000	10,403,000	2,296,000	(9,026,000)	(2,816,000)
Cash, cash equivalents and restricted cash:
Balance, beginning of period	9,048,000	6,752,000	6,752,000	15,778,000	18,594,000
Balance, end of period	42,184,000	17,155,000	9,048,000	6,752,000	15,778,000
Guarantors | GCER Bank Credit Facility
Cash flows from financing activities:
Repayment of Bank Credit Facility					(55,000,000)
Non-Guarantors
Cash flows from operating activities:
Net cash provided by (used in) operating activities	1,748,000	16,880,000	1,879,000	(5,769,000)	822,000
Cash flows from investing activities:
Exploration, development, and other capital expenditures	(3,274,000)	(7,692,000)	(22,600,000)	(6,084,000)	(1,133,000)
Net cash provided by (used in) investing activities	(3,274,000)	(7,692,000)	(22,600,000)	(6,084,000)	(1,133,000)
Cash flows from financing activities:
Capital contributions	2,000,000	8,000,000	26,500,000	16,453,000	1,179,000
Distributions to subsidiary issuer	(9,000)	(1,527,000)	(6,041,000)	(3,024,000)	(112,000)
Contributions from Sponsors	2,000,000	8,000,000
Distributions to subsidiaries	(9,000)	(1,527,000)
Net cash provided by (used in) financing activities	1,991,000	6,473,000	20,459,000	13,429,000	1,067,000
Net increase (decrease) in cash, cash equivalents and restricted cash	465,000	15,661,000	(262,000)	1,576,000	756,000
Cash, cash equivalents and restricted cash:
Balance, beginning of period	2,070,000	2,332,000	2,332,000	756,000
Balance, end of period	2,535,000	17,993,000	2,070,000	2,332,000	756,000
Elimination
Cash flows from investing activities:
Investments in subsidiaries	384,089,000	287,689,000	577,055,000	616,083,000	653,322,000
Distributions from subsidiaries	(677,582,000)	(294,107,000)	(617,567,000)	(411,074,000)	(300,891,000)
Net cash provided by (used in) investing activities	(293,493,000)	(6,418,000)	(40,512,000)	205,009,000	352,431,000
Cash flows from financing activities:
Capital contributions	(384,089,000)	(287,689,000)	(577,055,000)	(616,083,000)	(653,322,000)
Distributions to subsidiary issuer	677,582,000	294,107,000	617,567,000	411,074,000	300,891,000
Contributions from Sponsors	(384,089,000)	(287,689,000)
Distributions to subsidiaries	677,582,000	294,107,000
Net cash provided by (used in) financing activities	$ 293,493,000	$ 6,418,000	$ 40,512,000	$ (205,009,000)	$ (352,431,000)

Selected Quarterly Financial 73

Selected Quarterly Financial Data - Schedule Of Quarterly Financial Data (Details) - USD ($) $ in Thousands	3 Months Ended											6 Months Ended				12 Months Ended
	Jun. 30, 2018		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017		Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2018		Jun. 30, 2017		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 203,906		$ 115,616	$ 99,962	$ 95,426		$ 101,824	$ 76,918	$ 63,775	$ 67,405	$ 50,656	$ 349,756		$ 197,250		$ 412,828		$ 258,754		$ 315,606
Operating income (loss)	39,211		18,370	13,329	6,314		7,287	(7,103)	(12,868)	(20,697)	(40,011)	87,795		13,601		45,300		(80,679)		(777,651)
Price risk management activities income (expense)	(91,176)	[1]	(84,365)	(28,086)	38,995	[1]	45,893	(32,742)	11,350	(48,930)	12,924	(143,152)	[1]	84,888	[1]	(27,563)	[2]	(57,398)	[2]	182,196	[2]
Net loss	$ (74,912)		$ (85,760)	$ (36,177)	$ 24,607		$ 34,462	$ (60,354)	$ (22,219)	$ (84,715)	$ (40,799)	$ (97,855)		$ 59,069		$ (62,868)		$ (208,087)		$ (646,685)
[1]	The Company paid $33.6 million and received $9.2 million in net cash settlements for the three months ended June 30, 2018 and 2017, respectively, and paid $54.1 million and received $13.7 million in net cash settlements for the six months ended June 30, 2018 and 2017, respectively.
[2]	The Company received net cash settlements of $23.8 million, $172.2 million and $181.9 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Supplemental Oil and Gas Disc74

Supplemental Oil and Gas Disclosures - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion, Depreciation and Amortization (Details) $ in Thousands	Jun. 30, 2018USD ($)	Dec. 31, 2017USD ($)$ / MBoe	Dec. 31, 2016USD ($)$ / MBoe
Extractive Industries [Abstract]
Proved properties	$ 3,412,875	$ 2,440,811	$ 2,235,835
Unproved oil and gas properties, not subject to amortization		72,002	72,360
Total oil and gas properties		2,512,813	2,308,195
Less: Accumulated depletion and amortization		(1,423,829)	(1,268,276)
Net capitalized costs		$ 1,088,984	$ 1,039,919
Depletion and amortization rate per Boe | $ / MBoe		14.85	13.82

Supplemental Oil and Gas Disc75

Supplemental Oil and Gas Disclosures - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MMBoe	Dec. 31, 2016USD ($)MMBoe	Dec. 31, 2015USD ($)MMBoe	Jun. 30, 2018USD ($)
Reserve Quantities [Line Items]
Oil and gas asset retirement obligations | $	$ 214,733	$ 220,049	$ 226,690	$ 414,378
Percentage of proved oil, natural gas and NGL reserves attributable to all of oil and natural gas properties	100.00%	100.00%
Percentage of proved oil, natural gas and NGL reserves attributable to net interests in legacy oil and natural gas properties			100.00%
Estimated proved reserves from extensions and discoveries	12.5	26.6
Decrease of production	10.5
Revision of previous estimates	5.1		7
Purchases of estimated proved reserves		13.9	9.5
Prescribed rate of discounted future net cash flows	10.00%
GCER Acquisition
Reserve Quantities [Line Items]
Percentage of proved oil, natural gas and NGL reserves attributable to assets acquired			100.00%
GCER acquisition
Reserve Quantities [Line Items]
Purchases of estimated proved reserves			5.1
DGE Acquisition.
Reserve Quantities [Line Items]
Purchases of estimated proved reserves			4.4

Supplemental Oil and Gas Disc76

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Property acquisition costs:
Proved properties	$ 1,108	$ 77,906	$ 68,463
Unproved properties, not subject to amortization	5,778	15,919	39,265
Total property acquisition costs	6,886	93,825	107,728
Exploration costs	82,887	27,807	25,908
Development costs	114,846	195,869	228,257
Total costs incurred	$ 204,619	$ 317,501	$ 361,893

Supplemental Oil and Gas Disc77

Supplemental Oil and Gas Disclosures - Schedule of Estimated Proved Reserves at Net Ownership Interest (Details)	12 Months Ended
	Dec. 31, 2017MBoeMMBoeMBblsMMcf	Dec. 31, 2016MBoeMMBoeMBblsMMcf	Dec. 31, 2015MBoeMMBoeMBblsMMcf
Reserve Quantities [Line Items]
Revision of previous estimates | MMBoe	(5.1)		(7)
Production | MMBoe	(10.5)
Purchases of reserves | MMBoe		13.9	9.5
Extensions and discoveries | MMBoe	12.5	26.6
Oil (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	72,366	46,354	46,120
Revision of previous estimates	(2,673)	(1,712)	(3,435)
Production	(7,048)	(5,126)	(5,161)
Purchases of reserves		11,128	4,029
Extensions and discoveries	10,159	21,722	4,801
Total proved reserves, ending balance	72,804	72,366	46,354
Total proved developed reserves	37,460	45,753	33,016
Total proved undeveloped reserves	35,344	26,613	13,338
Gas (MMcf)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MMcf	150,604	129,224	136,232
Revision of previous estimates | MMcf	(15,860)	10,024	(22,580)
Production | MMcf	(16,308)	(19,001)	(21,458)
Purchases of reserves | MMcf		11,208	30,527
Extensions and discoveries | MMcf	9,220	19,149	6,503
Total proved reserves, ending balance | MMcf	127,656	150,604	129,224
Total proved developed reserves | MMcf	77,577	96,122	90,432
Total proved undeveloped reserves | MMcf	50,079	54,482	38,792
NGL (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	6,236	4,581	4,096
Revision of previous estimates	250	(352)	207
Production	(706)	(603)	(588)
Purchases of reserves		950	385
Extensions and discoveries	767	1,660	481
Total proved reserves, ending balance	6,547	6,236	4,581
Total proved developed reserves	3,315	4,032	3,383
Total proved undeveloped reserves	3,232	2,204	1,198
Oil Equivalent (MBoe)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MBoe	103,702	72,473	72,921
Revision of previous estimates | MBoe	(5,067)	(394)	(6,991)
Production | MBoe	(10,472)	(8,896)	(9,325)
Purchases of reserves | MBoe		13,946	9,502
Extensions and discoveries | MBoe	12,462	26,573	6,366
Total proved reserves, ending balance | MBoe	100,625	103,702	72,473
Total proved developed reserves | MBoe	53,704	65,805	51,471
Total proved undeveloped reserves | MBoe	46,921	37,897	21,002

Supplemental Oil and Gas Disc78

Supplemental Oil and Gas Disclosures - Schedule of Standardized Measure of Discounted Future Net Cash Flows Related to Interest in Proved Oil, Natural Gas and NGL Reserves (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Future cash inflows	$ 4,308,863	$ 3,390,612	$ 2,786,828
Future costs:
Production	(815,509)	(775,354)	(1,363,585)
Development and abandonment	(823,164)	(664,254)	(646,161)
Future net cash flows before income taxes	2,670,190	1,951,004	777,082
Future income tax expense	0	0	0
Future net cash flows before income taxes	2,670,190	1,951,004	777,082
Discount at 10% annual rate	(862,521)	(614,969)	(174,101)
Standardized measure of discounted future net cash flows	$ 1,807,669	$ 1,336,035	$ 602,981	$ 1,888,958

Supplemental Oil and Gas Disc79

Supplemental Oil and Gas Disclosures - Schedule of Base Prices Used in Determining Standardized Measure (Details)	12 Months Ended
	Dec. 31, 2017$ / bbl$ / Mcf	Dec. 31, 2016$ / bbl$ / Mcf	Dec. 31, 2015$ / bbl$ / Mcf
Oil
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Base prices	51.36	40.02	50.72
Natural Gas
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Base prices | $ / Mcf	3.20	2.66	2.75
NGL
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Base prices	24.64	14.96	17.60

Supplemental Oil and Gas Disc80

Supplemental Oil and Gas Disclosures - Schedule of Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Standardized measure, beginning of year	$ 1,336,035	$ 602,981	$ 1,888,958
Changes during the year:
Sales, net of production costs	(288,942)	(114,625)	(117,344)
Net change in prices and production costs	555,100	80,174	(1,879,436)
Changes in future development costs	(156,282)	2,292	92,182
Development costs incurred	146,687	108,484	273,532
Accretion of discount	133,603	60,298	188,896
Purchases of reserves		222,581	229,052
Extensions and discoveries	328,565	479,833	91,722
Net change due to revision in quantity estimates	(113,629)	(5,685)	(103,842)
Changes in production rates (timing) and other	(133,468)	(100,298)	(60,739)
Total	471,634	733,054	(1,285,977)
Standardized measure, end of year	$ 1,807,669	$ 1,336,035	$ 602,981