Kosmos Energy (KOS) 10-Q 6 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Aug. 01, 2018
Document and Entity Information
Entity Registrant Name	Kosmos Energy Ltd.
Entity Central Index Key	1,509,991
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		398,403,309
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 116,941	$ 233,412
Restricted cash	20,377	56,380
Receivables:
Joint interest billings, net	68,006	134,565
Oil sales	73,700	0
Related party	2,610	780
Other	13,501	25,616
Inventories	71,085	71,861
Prepaid expenses and other	33,638	9,306
Derivatives	18,053	1,682
Total current assets	417,911	533,602
Property and equipment:
Oil and gas properties, net	2,253,815	2,310,973
Other property, net	9,249	6,855
Property and equipment, net	2,263,064	2,317,828
Other assets:
Equity method investment	151,310	236,514
Restricted cash	9,168	15,194
Long-term receivables - joint interest billings	28,981	34,941
Deferred financing costs, net of accumulated amortization of $15,320 and $13,951 at June 30, 2018 and December 31, 2017, respectively	1,141	2,510
Deferred tax assets	20,763	22,517
Derivatives	10,421	39
Other	684	29,458
Total assets	2,903,443	3,192,603
Current liabilities:
Accounts payable	128,471	141,787
Accrued liabilities	145,600	219,412
Derivatives	162,329	67,531
Total current liabilities	436,400	428,730
Long-term liabilities:
Long-term debt, net	1,167,775	1,282,797
Derivatives	83,733	30,209
Asset retirement obligations	70,122	66,595
Deferred tax liabilities	392,918	476,548
Other long-term liabilities	8,364	10,612
Total long-term liabilities	1,722,912	1,866,761
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at June 30, 2018 and December 31, 2017	0	0
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 407,557,090 and 398,599,457 issued at June 30, 2018 and December 31, 2017, respectively	4,076	3,986
Additional paid-in capital	2,015,463	2,014,525
Accumulated deficit	(1,226,701)	(1,073,202)
Treasury stock, at cost, 9,263,269 and 9,188,819 shares at June 30, 2018 and December 31, 2017, respectively	(48,707)	(48,197)
Total shareholders’ equity	744,131	897,112
Total liabilities and shareholders’ equity	$ 2,903,443	$ 3,192,603

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Deferred financing costs, accumulated amortization	$ 15,320	$ 13,951
Preference shares, par value (in dollars per share)	$ 0.01	$ 0.01
Preference shares, authorized shares (in shares)	200,000,000	200,000,000
Preference shares, issued shares (in shares)	0	0
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, authorized shares (in shares)	2,000,000,000	2,000,000,000
Common shares, issued shares (in shares)	407,557,090	398,599,457
Treasury stock shares (in shares)	9,263,269	9,188,819

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues and other income:
Oil and gas revenue	$ 215,191	$ 136,363	$ 342,387	$ 239,795
Other income, net	282	10,161	263	58,695
Total revenues and other income	215,473	146,524	342,650	298,490
Costs and expenses:
Oil and gas production	49,815	21,604	96,583	41,490
Facilities insurance modifications, net	1,029	(2)	9,478	2,572
Exploration expenses	77,481	19,982	98,674	125,696
General and administrative	17,497	14,739	39,380	30,526
Depletion and depreciation	74,289	72,441	128,566	107,419
Interest and other financing costs, net	18,870	19,465	44,564	36,251
Derivatives, net	140,272	(25,411)	178,750	(63,268)
(Gain) loss on equity method investments, net	(16,100)	6,426	(34,796)	6,426
Other expenses, net	938	2,008	4,643	2,770
Total costs and expenses	364,091	131,252	565,842	289,882
Income (loss) before income taxes	(148,618)	15,272	(223,192)	8,608
Income tax expense (benefit)	(45,345)	23,739	(69,693)	45,916
Net loss	$ (103,273)	$ (8,467)	$ (153,499)	$ (37,308)
Net loss per share:
Basic (in dollars per share)	$ (0.26)	$ (0.02)	$ (0.39)	$ (0.10)
Diluted (in dollars per share)	$ (0.26)	$ (0.02)	$ (0.39)	$ (0.10)
Weighted average number of shares used to compute net loss per share:
Basic (in shares)	396,826	387,952	396,218	387,634
Diluted (in shares)	396,826	387,952	396,218	387,634

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - 6 months ended Jun. 30, 2018 - USD ($) shares in Thousands, $ in Thousands	Total	Common Shares	Additional Paid-in Capital	Accumulated Deficit	Treasury Stock
Balance at the beginning (in shares) at Dec. 31, 2017		398,599
Balance at the beginning at Dec. 31, 2017	$ 897,112	$ 3,986	$ 2,014,525	$ (1,073,202)	$ (48,197)
Increase (Decrease) in Shareholders' Equity
Equity-based compensation	18,213		18,213
Restricted stock awards and units (in shares)		8,958
Restricted stock awards and units	0	$ 90	(90)
Purchase of treasury stock / tax withholdings	(17,695)		(17,185)		(510)
Net loss	(153,499)			(153,499)
Balance at the end (in shares) at Jun. 30, 2018		407,557
Balance at the end at Jun. 30, 2018	$ 744,131	$ 4,076	$ 2,015,463	$ (1,226,701)	$ (48,707)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Operating activities
Net loss	$ (153,499)	$ (37,308)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	133,289	112,521
Deferred income taxes	(81,876)	41,017
Unsuccessful well costs	44,654	3,605
Change in fair value of derivatives	177,790	(58,944)
Cash settlements on derivatives, net (including $(57.3) million and $24.3 million on commodity hedges during 2018 and 2017)	(56,221)	19,417
Equity-based compensation	17,085	20,329
Loss on extinguishment of debt	4,056	0
Distributions in excess of equity in earnings	5,234	6,426
Other	449	2,514
Changes in assets and liabilities:
(Increase) decrease in receivables	10,067	(28,251)
(Increase) decrease in inventories	800	(6,038)
(Increase) decrease in prepaid expenses and other	4,888	(17,459)
Decrease in accounts payable	(13,316)	(131,480)
Increase (decrease) in accrued liabilities	(92,967)	56,137
Net cash provided by (used in) operating activities	433	(17,514)
Investing activities
Oil and gas assets	(92,650)	(42,805)
Other property	(2,815)	(1,454)
Return of investment from KTIPI	79,970	0
Proceeds on sale of assets	0	222,068
Net cash provided by (used in) investing activities	(15,495)	177,809
Financing activities
Payments on long-term debt	(100,000)	(200,000)
Purchase of treasury stock / tax withholdings	(17,695)	(1,945)
Deferred financing costs	(25,743)	0
Net cash used in financing activities	(143,438)	(201,945)
Net decrease in cash, cash equivalents and restricted cash	(158,500)	(41,650)
Cash, cash equivalents and restricted cash at beginning of period	304,986	273,195
Cash, cash equivalents and restricted cash at end of period	146,486	231,545
Cash paid for:
Interest	47,845	24,944
Income taxes	22,596	27,199
Non-cash activity:
Contribution to equity method investment	$ 0	$ 133,893

CONSOLIDATED STATEMENTS OF CAS7

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Statement of Cash Flows [Abstract]
Cash settlements on derivatives, net (commodity hedges)	$ (57.3)	$ 24.3

Organization

Organization	6 Months Ended
	Jun. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise. Kosmos is a pure play deepwater oil and gas company with growing production, a pipeline of development opportunities and a balanced exploration portfolio along the Atlantic Margins. Our assets include growing production offshore Ghana and Equatorial Guinea, a competitively positioned Tortue gas project in Mauritania and Senegal and a sustainable exploration program balanced between proven basins (Equatorial Guinea), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Cote d'Ivoire and Sao Tome and Principe). Kosmos is listed on the New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS. We have one reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are related to production located offshore Ghana. We also have an equity method investment generating revenues with operations offshore Equatorial Guinea.

Accounting Policies

Accounting Policies	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Accounting Policies	Accounting Policies General The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of June 30, 2018 , the changes in the consolidated statements of shareholders’ equity for the six months ended June 30, 2018 , the consolidated results of operations for the three and six months ended June 30, 2018 and 2017 , and the consolidated cash flows for the six months ended June 30, 2018 and 2017 . The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2017 , included in our annual report on Form 10-K. Reclassifications Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net loss , current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows. Cash, Cash Equivalents and Restricted Cash June 30, December 31, (In thousands) Cash and cash equivalents $ 116,941 $ 233,412 Restricted cash - current 20,377 56,380 Restricted cash - long-term 9,168 15,194 Total cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows $ 146,486 $ 304,986 Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. In accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of June 30, 2018 and December 31, 2017 , we had $20.4 million and $31.6 million , respectively, of current restricted cash and $8.9 million and $15.2 million , respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts. As of June 30, 2018, we also had $0.3 million in other long-term restricted cash. In addition, prior to our reserves based debt facility (the "Facility") being amended and restated in February 2018, we were required to maintain a restricted cash balance that was sufficient to meet the payment of interest and fees for the next six -month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver, or the Facility, whichever was greater. As of December 31, 2017 , we had $24.8 million in current restricted cash to meet this requirement. Under the amended and restated Facility, we are no longer required to maintain a restricted cash balance provided we are compliant with certain financial covenant ratios. Inventories Inventories consisted of $65.1 million and $63.5 million of materials and supplies and $6.0 million and $8.4 million of hydrocarbons as of June 30, 2018 and December 31, 2017 , respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs. Revenue Recognition We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of June 30, 2018 and December 31, 2017 , we had no oil and gas imbalances recorded in our consolidated financial statements. Our oil and gas revenues are recognized based on the product that has transferred to the customer during the lifting process as of a point in time when control has transferred, usually over a 24 hour period, and generally based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale. Oil and gas revenue is composed of the following: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In thousands) Revenue from contracts with customers - Ghana $ 213,841 $ 140,915 $ 341,878 $ 244,355 Provisional oil sales contracts 1,350 (4,552 ) 509 (4,560 ) Oil and gas revenue $ 215,191 $ 136,363 342,387 239,795 Recent Accounting Standards Recently Adopted In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company adopted the new standard during the first quarter of 2018 using the modified retrospective approach and there is no impact to our previously recorded revenue under the new standard. In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740).” ASU 2018-05 was issued to include amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 ("SAB 118") and addresses certain circumstances that may arise for registrants in accounting for the income tax effects of the Tax Cut and Jobs Act (the "Tax Reform Act"), including when certain income tax effects of the Tax Reform Act are incomplete by the time the financial statements are issued. Not Yet Adopted In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The new leasing standard requires the modified retrospective adoption method. The Company is in the process of evaluating its contract population to determine the impact of this accounting standard on its consolidated financial statements.

Acquisitions and Divestitures

Acquisitions and Divestitures	6 Months Ended
	Jun. 30, 2018
Acquisitions and Divestitures
Acquisitions and Divestitures	Acquisitions and Divestitures 2018 Transactions In March 2018, as part of our alliance with BP, we entered into petroleum contracts covering Blocks 10 and 13 with the Democratic Republic of Sao Tome and Principe. We presently have a 35% participating interest in the blocks and the operator, BP, holds a 50% participating interest. The national petroleum agency, Agencia Nacional Do Petroleo De Sao Tome E Principe ("ANP STP") has a 15% carried interest in the blocks through exploration. The petroleum contracts cover approximately 13,600 square kilometers, with a first exploration period of four years from the effective date (March 2018). The exploration period can be extended an additional four years at our election subject to fulfilling specific work obligations. The first exploration period work program includes a 13,500 square kilometer 3D seismic acquisition requirement across the two blocks. In June 2018, we closed a farm-in agreement with a subsidiary of Ophir Energy plc ("Ophir") for Block EG-24, offshore Equatorial Guinea, whereby we acquired a 40% non-operated participating interest. As part of the agreement, we reimbursed a portion of Ophir's previously incurred exploration costs and will fully carry Ophir's share of the costs of a planned 3D seismic program as well as pay a disproportionate share of the well commitment should we enter the second exploration sub-period. The petroleum contracts cover approximately 3,500 square kilometers, with a first exploration period of three years from the effective date (March 2018) which can be extended up to four additional years at our election subject to fulfilling specific work obligations. The first exploration period work program includes a 3,000 square kilometer 3D seismic acquisition requirement. In August 2018, we entered into an agreement to acquire Deep Gulf Energy (together with its subsidiaries "DGE"), a deepwater company operating in the Gulf of Mexico, from First Reserve Corporation and other shareholders for a total consideration of $1.225 billion , comprised of $925 million in cash and $300 million in Kosmos common stock, subject to post-closing adjustments. We intend to fund the cash portion of the purchase price with borrowings under our existing credit facilities. We also received $200 million of additional firm commitments under the Facility, which provides further liquidity to the Company. The acquisition is expected to close around the end of the third quarter 2018, subject to receipt of regulatory approval and the satisfaction of customary closing conditions. 2017 Transactions In the fourth quarter of 2017, through a joint venture with an affiliate of Trident Energy ("Trident"), we acquired all of the equity interest of Hess International Petroleum Inc., a subsidiary of Hess Corporation ("Hess"), which held an 85% paying interest ( 80.75% revenue interest) in the Ceiba Field and Okume Complex assets located in Block G offshore Equatorial Guinea. Under the terms of the agreement, Kosmos and Trident each own 50% of Hess International Petroleum Inc, which was subsequently renamed Kosmos-Trident International Petroleum Inc. ("KTIPI"). Kosmos is primarily responsible for exploration and subsurface evaluation while Trident is primarily responsible for production operations and optimization. The gross acquisition price was $650 million effective as of January 1, 2017 . After purchase price adjustments, Kosmos paid net cash consideration of approximately $231 million at close with a combination of cash on hand and amounts borrowed under the Facility. The transaction is accounted for as an equity method investment. In October 2017, we entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. In May 2018, we signed a farm-out agreement with Trident, subject to final government approval, whereby they acquired a 40% participating interest. After giving effect to the farm-out agreement, we hold a 40% participating interest and are the operator in all three blocks. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration period of five years from the effective date (March 2018). The first exploration period consists of two sub-periods of three and two years, respectively. The first exploration sub-period work program includes a 6,000 square kilometer 3D seismic acquisition requirement across the three blocks. In December 2017 , as part of our alliance with BP, we entered into petroleum contracts covering Blocks CI-526, CI-602, CI-603, CI-707 and CI-708 with the Government of Cote d'Ivoire. We have a 45% participating interest and are the operator in all five blocks. BP has a 45% participating interest in the blocks and the Cote d'Ivoire national oil company, PETROCI Holding ("PETROCI"), currently has a 10% carried interest. The petroleum contracts cover approximately 17,000 square kilometers, with a first exploration period of three years. The first exploration period work program includes a 12,000 square kilometer 3D seismic acquisition across the five blocks.

Joint Interest Billings

Joint Interest Billings	6 Months Ended
	Jun. 30, 2018
Joint Interest Billings
Joint Interest Billings	Joint Interest Billings The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur. In 2014, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners of its request for the contractor group to pay GNPC’s 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners will be reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of June 30, 2018 and December 31, 2017 , the current portion of the joint interest billing receivables due from GNPC for the TEN fields development costs were $14.0 million and $15.2 million , respectively, and the long-term portion were $29.0 million and $31.6 million , respectively.

Property and Equipment

Property and Equipment	6 Months Ended
	Jun. 30, 2018
Property, Plant and Equipment [Abstract]
Property and Equipment	Property and Equipment Property and equipment is stated at cost and consisted of the following: June 30, December 31, (In thousands) Oil and gas properties: Proved properties $ 1,676,732 $ 1,653,616 Unproved properties 492,468 465,109 Support equipment and facilities 1,442,325 1,427,054 Total oil and gas properties 3,611,525 3,545,779 Accumulated depletion (1,357,710 ) (1,234,806 ) Oil and gas properties, net 2,253,815 2,310,973 Other property 43,906 39,405 Accumulated depreciation (34,657 ) (32,550 ) Other property, net 9,249 6,855 Property and equipment, net $ 2,263,064 $ 2,317,828 We recorded depletion expense of $71.3 million and $69.9 million for the three months ended June 30, 2018 and 2017 , respectively, and $122.9 million and $102.4 million for the six months ended June 30, 2018 and 2017 , respectively.

Suspended Well Costs

Suspended Well Costs	6 Months Ended
	Jun. 30, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Suspended Well Costs	Suspended Well Costs The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the six months ended June 30, 2018 . The table excludes $43.8 million in costs that were capitalized and subsequently expensed during the same period. June 30, (In thousands) Beginning balance $ 410,113 Additions to capitalized exploratory well costs pending the determination of proved reserves 6,619 Reclassification due to determination of proved reserves — Capitalized exploratory well costs charged to expense (796 ) Ending balance $ 415,936 The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: June 30, 2018 December 31, 2017 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 35,513 $ 67,159 Exploratory well costs capitalized for a period of one to two years 258,998 291,252 Exploratory well costs capitalized for a period of three to six years 121,425 51,702 Ending balance $ 415,936 $ 410,113 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 5 5 As of June 30, 2018 , the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Akasa discovery in the West Cape Three Points (“WCTP”) Block and the Wawa discovery in the DT Block, which are all located offshore Ghana, the Greater Tortue discovery which crosses the Mauritania and Senegal maritime border, the BirAllah discovery (formerly known as the Marsouin discovery) in Block C8 offshore Mauritania and the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal. Akasa Discovery — We are currently in discussions with the government of Ghana regarding additional technical studies and evaluation that we want to conduct before we are able to make a determination regarding commerciality of the discovery. If we determine the discovery to be commercial, a declaration of commerciality would be provided and a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP petroleum contract. We expect that the Akasa discovery will be discussed in detail with the partnership group during our third quarter partner meetings in October 2018. Wawa Discovery — We are currently in discussions with the Ministry of Energy with respect to conducting further subsurface and development concept evaluation in an effort to enlarge the TEN development and production area to capture the resource accumulation located in the Wawa Discovery Area for a potential future integrated development with the TEN fields. We expect that the Wawa discovery will be further discussed with the partnership group during our third quarter partner meetings in October 2018. Greater Tortue Discovery — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania, which encountered hydrocarbon pay. Two additional wells have been drilled in the Greater Tortue Discovery area, Ahmeyim-2 in Mauritania and Guembeul-1 in Senegal. We completed a drill stem test on the Tortue‑1 well in August 2017, which confirmed the production capabilities of the Greater Tortue Discovery. Data acquired from the drill stem test will be used to further optimize field development and to refine process design parameters critical to the Front End Engineering Design ("FEED") process. Following additional evaluation, a decision regarding commerciality will be made. BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well (renamed BirAllah) in the northern part of Block C8 offshore Mauritania which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality will be made. Yakaar and Teranga Discoveries — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. In June 2017, we completed the Yakaar-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. In November 2017, an integrated Yakaar-Teranga appraisal plan was submitted. Following additional evaluation, a decision regarding commerciality will be made.

Equity Method Investments

Equity Method Investments	6 Months Ended
	Jun. 30, 2018
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Equity Method Investments Kosmos BP Senegal Limited ("KBSL") As part of our transaction in Senegal with BP in February 2017, our participating interests in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") were contributed to KBSL, a corporate joint venture entity in which we owned a 50.01% interest which was accounted for under the equity method of accounting. In October 2017, KBSL transferred a 30% participating interest in the Senegal Blocks to BP Senegal Investments Limited in exchange for its outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and no longer is accounted for under the equity method of accounting. After the transfer, KBSL has a 30% participating interest in the Senegal Blocks. During the three and six month periods ended June 30, 2017 we recognized $6.4 million related to our share of losses in KBSL. Our initial contribution to KBSL was $133.9 million , which was recorded at our carrying costs. Equatorial Guinea As part of our acquisition of KTIPI, a corporate joint venture entity in which we own a 50% interest, we acquired an indirect participating interest in Block G offshore Equatorial Guinea. The objective of this transaction was to acquire the Ceiba Field and Okume Complex with the intent to optimize production and increase reserves. Below is a summary of financial information for KTIPI presented on a 100% basis. June 30, December 31, 2018 2017 (In thousands) Assets Total current assets $ 164,997 $ 179,070 Property and equipment, net 311,138 345,611 Other assets 544 567 Total assets $ 476,679 $ 525,248 Liabilities and shareholders' equity Total current liabilities $ 132,096 $ 106,769 Total long-term liabilities 548,434 565,591 Shareholders' equity: Total shareholders' equity (203,851 ) (147,112 ) Total liabilities and shareholders' equity $ 476,679 $ 525,248 Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 (In thousands) Revenues and other income: Oil and gas revenue $ 138,395 $ 384,749 Other income (170 ) 117 Total revenues and other income 138,225 384,866 Costs and expenses: Oil and gas production 23,332 75,033 Depletion and depreciation 21,881 75,951 Other expenses, net (73 ) (152 ) Total costs and expenses 45,140 150,832 Income before income taxes 93,085 234,034 Income tax expense 33,620 83,251 Net income $ 59,465 $ 150,783 Kosmos' share of net income $ 29,733 $ 75,392 Basis difference amortization(1) 13,633 40,596 Equity in earnings - KTIPI $ 16,100 $ 34,796 ______________________________________ (1) The basis difference, which is associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortize the basis difference using the unit-of-production method. When evaluating our equity method investments for impairment, we review our ability to recover the carrying amount of such investments or the entity’s ability to sustain earnings that justify its carrying amount. As of June 30, 2018 , we determined that we had the ability to recover the carrying amount of our equity method investment in KTIPI. As such, no impairment has been recorded. Our initial investment has been increased for our net share of equity in earnings as adjusted for our basis differential and reduced by cash dividends received. During the six months ended June 30, 2018 , we received $120.0 million of cash dividends from KTIPI, and we received an additional $27.5 million of cash dividends in July 2018.

Debt

Debt	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Debt	Debt June 30, December 31, (In thousands) Outstanding debt principal balances: Facility $ 700,000 $ 800,000 Senior Notes 525,000 525,000 Total 1,225,000 1,325,000 Unamortized deferred financing costs and discounts(1) (57,225 ) (42,203 ) Long-term debt, net $ 1,167,775 $ 1,282,797 __________________________________ (1) Includes $40.9 million and $23.6 million of unamortized deferred financing costs related to the Facility and $16.3 million and $18.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of June 30, 2018 and December 31, 2017 , respectively. Facility In February 2018, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions with additional commitments up to $0.5 billion being available if the existing financial institutions increase their commitments or if commitments from new financial institutions are added. In August 2018, the Company entered into letter agreements with two existing financial institutions, which obligate the two financial institutions to provide the Company, upon the Company's election, with an additional commitment of $200 million in the aggregate under the Facility. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of the debt refinancing in February 2018, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and $4.1 million of existing unamortized debt issuance costs and deferred interest attributable to those participants was expensed in interest and other financing costs, net in the first quarter of 2018. As of June 30, 2018 , we have $40.9 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility. As of June 30, 2018 , borrowings under the Facility totaled $700.0 million and the undrawn availability under the Facility was $800.0 million . During the second quarter of 2018, the Company voluntarily repaid $100.0 million of outstanding borrowings under the Facility, bringing the outstanding borrowings to $700.0 million . As of June 30, 2018, the borrowing availability was $1.5 billion . The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility, as amended in February 2018 expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2022, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2025. As of June 30, 2018 , we had no letters of credit issued under the Facility. We were in compliance with the financial covenants contained in the Facility as of March 31, 2018 (the most recent assessment date). The Facility contains customary cross default provisions. Corporate Revolver In August 2018, we amended and restated the Corporate Revolver from a number of financial institutions, maintaining the borrowing capacity at $400.0 million , extending the maturity date from November 2018 to May 2022 and lowering the margin 100 basis points to 5% . This results in lower commitment fees on the undrawn portion of the total commitments which is 30% per annum of the respective margin. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of June 30, 2018 , there were no outstanding borrowings under the Corporate Revolver. We were in compliance with the financial covenants contained in the Corporate Revolver as of March 31, 2018 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions. Revolving Letter of Credit Facility We have a revolving letter of credit facility agreement (“LC Facility”), which matures in July 2019 . In July 2018, the LC Facility size was voluntarily reduced to $40.0 million based on the maturation of several large outstanding letters of credit. As of June 30, 2018 , there were nine outstanding letters of credit totaling $36.9 million under the LC Facility. The LC Facility contains customary cross default provisions. 7.875% Senior Secured Notes due 2021 During August 2014, the Company issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. During April 2015, we issued an additional $225.0 million of Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million of Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued. The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries. At June 30, 2018 , the estimated repayments of debt during the five fiscal year periods and thereafter are as follows: Payments Due by Year Total 2018(2) 2019 2020 2021 2022 Thereafter (In thousands) Principal debt repayments(1) $ 1,225,000 $ — $ — $ — $ 525,000 $ — $ 700,000 __________________________________ (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on, as of June 30, 2018 , our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of June 30, 2018 , there were no borrowings under the Corporate Revolver. (2) Represents payments for the period July 1, 2018 through December 31, 2018 . Interest and other financing costs, net Interest and other financing costs, net incurred during the periods is comprised of the following: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In thousands) Interest expense $ 24,912 $ 22,792 $ 49,804 $ 45,973 Amortization—deferred financing costs 2,283 2,551 4,723 5,102 Loss on extinguishment of debt — — 4,056 — Capitalized interest (9,292 ) (7,376 ) (14,112 ) (16,935 ) Deferred interest 166 634 (1,090 ) 949 Interest income (843 ) (760 ) (1,791 ) (1,740 ) Other, net 1,644 1,624 2,974 2,902 Interest and other financing costs, net $ 18,870 $ 19,465 $ 44,564 $ 36,251

Derivative Financial Instrument

Derivative Financial Instruments	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Derivative Financial Instruments We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes. We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820 — Fair Value Measurements and Disclosures. Oil Derivative Contracts The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of June 30, 2018 . Volumes and weighted average prices are net of any offsetting derivative contracts entered into. Weighted Average Dated Brent Price per Bbl Net Deferred Premium Term Type of Contract MBbl Payable/(Receivable) Swap Sold Put Floor Ceiling Call 2018: July — December Swap with puts 3,000 $ — $ 56.75 $ 43.33 $ — $ — $ — July — December Three-way collars 1,466 0.74 — 41.57 56.57 65.91 — July — December Four-way collars 1,503 1.06 — 40.00 50.00 61.33 70.00 July — December Sold calls(1) 1,006 — — — — 65.00 — July — December Purchased Calls 1,000 1.88 — — — — 70.00 2019: January — December Three-way collars 10,500 $ 0.61 $ — $ 43.81 $ 53.33 $ 69.77 $ — January — December Sold calls(1) 913 — — — — 80.00 — 2020: January — December Sold calls(1) 4,000 $ — $ — $ — $ — $ 80.00 $ — __________________________________ (1) Represents call option contracts sold to counterparties to enhance other derivative positions. In July 2018, we entered into call option contracts for 3.5 MMBbl from January 2019 through December 2019 with a purchased call price of $65.00 per barrel and a sold call price of $75.00 per barrel with a deferred premium payable of $1.46 per barrel. In addition, we sold 3.5 MMBbl of calls from January 2020 through December 2020 with a strike price of $80.00 per barrel and used the proceeds to increase the upside exposure on the 2019 calls. The contracts are indexed to Dated Brent prices. Interest Rate Derivative Contracts The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of June 30, 2018 : Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) July 2018 — December 2018 Capped swap 1-month LIBOR $ 200,000 1.23 % 3.00 % The following tables disclose the Company’s derivative instruments as of June 30, 2018 and December 31, 2017 and gain/(loss) from derivatives during the three and six months ended June 30, 2018 and 2017 , respectively: Estimated Fair Value Asset (Liability) Type of Contract Balance Sheet Location June 30, December 31, (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ 17,119 $ 665 Interest rate Derivatives assets—current 934 1,017 Commodity(2) Derivatives assets—long-term 10,421 39 Derivative liabilities: Commodity(3) Derivatives liabilities—current (162,329 ) (67,531 ) Commodity(4) Derivatives liabilities—long-term (83,733 ) (30,209 ) Total derivatives not designated as hedging instruments $ (217,588 ) $ (96,019 ) __________________________________ (1) Includes net deferred premiums payable of $2.1 million and net deferred premiums receivable of $0.8 million related to commodity derivative contracts as of June 30, 2018 and December 31, 2017 , respectively. (2) Includes net deferred premiums payable of $0.9 million and net deferred premiums receivable of $0.1 million related to commodity derivative contracts as of June 30, 2018 and December 31, 2017 , respectively. (3) Includes net deferred premiums payable of $5.1 million and $5.6 million related to commodity derivative contracts as of June 30, 2018 and December 31, 2017 , respectively. (4) Includes net deferred premiums payable of $2.8 million and $4.8 million related to commodity derivative contracts as of June 30, 2018 and December 31, 2017 , respectively. Amount of Gain/(Loss) Amount of Gain/(Loss) Three Months Ended Six Months Ended June 30, June 30, Type of Contract Location of Gain/(Loss) 2018 2017 2018 2017 (In thousands) Derivatives not designated as hedging instruments: Commodity(1) Oil and gas revenue $ 1,350 $ (4,552 ) $ 509 $ (4,560 ) Commodity Derivatives, net (140,272 ) 25,411 (178,750 ) 63,268 Interest rate Interest expense 98 (92 ) 451 236 Total derivatives not designated as hedging instruments $ (138,824 ) $ 20,767 $ (177,790 ) $ 58,944 __________________________________ (1) Amounts represent the change in fair value of our provisional oil sales contracts. Offsetting of Derivative Assets and Derivative Liabilities Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of June 30, 2018 and December 31, 2017 , there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements In accordance with ASC Topic 820 — Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy: • Level 1 — quoted prices for identical assets or liabilities in active markets. • Level 2 — quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means. • Level 3 — unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 , for each fair value hierarchy level: Fair Value Measurements Using: Quoted Prices in Active Markets for Significant Other Significant Identical Assets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) June 30, 2018 Assets: Commodity derivatives $ — $ 27,540 $ — $ 27,540 Interest rate derivatives — 934 — 934 Liabilities: Commodity derivatives — (246,062 ) — (246,062 ) Total $ — $ (217,588 ) $ — $ (217,588 ) December 31, 2017 Assets: Commodity derivatives $ — $ 704 $ — $ 704 Interest rate derivatives — 1,017 — 1,017 Liabilities: Commodity derivatives — (97,740 ) — (97,740 ) Total $ — $ (96,019 ) $ — $ (96,019 ) The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs. Commodity Derivatives Our commodity derivatives represent crude oil collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for Dated Brent, (iii) a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for Dated Brent. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 9 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments. Provisional Oil Sales The value attributable to provisional oil sales derivatives is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for Dated Brent over the term of the pricing period designated in the sales contract and the spot price on the lifting date. Interest Rate Derivatives Our interest rate derivatives consist of interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate, and capped interest rate swaps, whereby the Company pays a fixed rate of interest if LIBOR is below the cap and pays the market rate less the spread between the cap and the fixed rate of interest if LIBOR is above the cap. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) LIBOR yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market. Debt The following table presents the carrying values and fair values at June 30, 2018 and December 31, 2017 : June 30, 2018 December 31, 2017 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 509,685 $ 535,264 $ 507,600 $ 542,472 Facility 700,000 700,000 800,000 800,000 Total $ 1,209,685 $ 1,235,264 $ 1,307,600 $ 1,342,472 The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.

Equity-based Compensation

Equity-based Compensation	6 Months Ended
	Jun. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-based Compensation	Equity-based Compensation Restricted Stock Awards and Restricted Stock Units We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $9.1 million and $10.5 million during the three months ended June 30, 2018 and 2017 , respectively, and $17.1 million and $20.3 million during the six months ended June 30, 2018 and 2017 , respectively. The total tax benefit for the three months ended June 30, 2018 and 2017 was $1.8 million and $3.5 million , respectively, and $3.4 million and $6.8 million during the six months ended June 30, 2018 and 2017 , respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of $0.4 million and $3.0 million for the three months ended June 30, 2018 and 2017 , respectively, and $(0.3) million and $2.8 million during the six months ended June 30, 2018 and 2017 , respectively. The fair value of awards vested during the three months ended June 30, 2018 and 2017 was approximately $25.4 million and $10.5 million , respectively, and $82.0 million and $19.3 million during the six months ended June 30, 2018 and 2017 , respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service vesting criteria under the LTIP. Substantially all these awards vest over three or four year periods. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock. The following table reflects the outstanding restricted stock awards as of June 30, 2018 : Weighted- Service Vesting Average Restricted Stock Grant-Date Awards Fair Value (In thousands) Outstanding at December 31, 2017 220 $ 8.64 Granted — — Forfeited — — Vested (220 ) 8.64 Outstanding at June 30, 2018 — — The following table reflects the outstanding restricted stock units as of June 30, 2018 : Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Units Fair Value Units Fair Value (In thousands) (In thousands) Outstanding at December 31, 2017 4,183 $ 6.39 8,452 $ 11.26 Granted(1) 2,125 6.92 7,439 12.35 Forfeited (63 ) 6.73 (37 ) 10.04 Vested (2,062 ) 6.93 (9,350 ) 13.75 Outstanding at June 30, 2018 4,183 6.33 6,504 8.91 __________________________________ (1) The restricted stock units with a combination of market and service vesting criteria include 4.9 million shares granted as a result of the 2014 and 2015 awards achieving 200% of their respective market performance conditions. As of June 30, 2018 , total equity-based compensation to be recognized on unvested restricted stock units is $43.4 million over a weighted average period of 2.24 years . In January 2018, the board of directors approved an amendment to the plan to add 11.0 million shares to the plan which was approved at the Annual General Meeting in June 2018. The LTIP provides for the issuance of 50.5 million shares pursuant to awards under the plan. At June 30, 2018 , the Company had approximately 16.0 million shares that remain available for issuance under the LTIP. For restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 200% of the awards granted. The grant date fair value ranged from $4.83 to $15.71 per award. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 44.0% to 53.0% . The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.7% to 2.2% .

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero tax rate and tax-exempt jurisdictions from our evaluation of the estimated annual effective income tax rate. The tax effect of discrete items are recognized in the period in which they occur at the applicable statutory tax rate. On December 22, 2017, the President of the United States signed P.L. 115-97, the Tax Reform Act into law. SAB 118 was issued in January 2018 to address situations where certain aspects of the Jobs Act are unclear at issuance of a registrant’s financial statements for the reporting period in which the Jobs Act became law. SAB 118 allows us to record provisional amounts during a one-year measurement period. We are analyzing certain aspects of the Jobs Act which could affect the measurement of deferred tax balances or potentially give rise to new deferred tax amounts. The income tax provision consists of United States and Ghanaian income and Texas margin taxes. Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets. Income (loss) before income taxes is composed of the following: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In thousands) Bermuda $ (15,890 ) $ (16,759 ) $ (31,961 ) $ (32,940 ) United States 1,682 1,382 3,315 2,794 Foreign—other (134,410 ) 30,649 (194,546 ) 38,754 Income (loss) before income taxes $ (148,618 ) $ 15,272 $ (223,192 ) $ 8,608 Our effective tax rate for the three months ended June 30, 2018 and 2017 is 31% and 155% , respectively. For the six months ended , June 30, 2018 and 2017 , our effective tax rate was 31% and 533% , respectively. For the periods ended June 30, 2018 and 2017 our overall effective tax rates were impacted by non-deductible and non-taxable items associated with our U.S. and Ghanaian operations and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such expenses or losses. The Company files income tax returns in all jurisdictions where such requirements exist, however, our primary tax jurisdictions are Ghana and the United States. The Company is open to Ghanaian federal income tax examinations for tax years 2014 through 2017 and in the United States, to federal income tax examinations for tax years 2014 through 2017. As of June 30, 2018 , the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense.

Net Loss Per Share

Net Loss Per Share	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Net Loss Per Share	Net Loss Per Share The following table is a reconciliation between net loss and the amounts used to compute basic and diluted net loss per share and the weighted average shares outstanding used to compute basic and diluted net loss per share: Three Months Ended Six Months Ended June 30, June 30, 2018 2017 2018 2017 Numerator: Net loss $ (103,273 ) $ (8,467 ) $ (153,499 ) $ (37,308 ) Basic income allocable to participating securities(1) — — — — Basic net loss allocable to common shareholders (103,273 ) (8,467 ) (153,499 ) (37,308 ) Diluted adjustments to income allocable to participating securities(1) — — — — Diluted net loss allocable to common shareholders $ (103,273 ) $ (8,467 ) $ (153,499 ) $ (37,308 ) Denominator: Weighted average number of shares outstanding: Basic 396,826 387,952 396,218 387,634 Restricted stock awards and units(1)(2) — — — — Diluted 396,826 387,952 396,218 387,634 Net loss per share: Basic $ (0.26 ) $ (0.02 ) $ (0.39 ) $ (0.10 ) Diluted $ (0.26 ) $ (0.02 ) $ (0.39 ) $ (0.10 ) __________________________________ (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net loss per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net loss per common share calculation in periods we are in a net loss position. (2) We excluded outstanding restricted stock awards and units of 11.4 million and 13.0 million for the three months ended June 30, 2018 and 2017 , respectively, and 11.9 million and 13.0 million for the six months ended June 30, 2018 and 2017 , respectively, from the computations of diluted net loss per share because the effect would have been anti-dilutive .

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year. We currently have a commitment to drill one exploration well in both Mauritania and Suriname. In Mauritania, our partner is obligated to fund our share of the cost of the exploration wells, subject to the remaining exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Equatorial Guinea and Sao Tome and Principe, we have 3D seismic requirements of approximately 9,000 square kilometers and 13,500 square kilometers, respectively. Future minimum rental commitments under our leases at June 30, 2018 , are as follows: Payments Due By Year(1) Total 2018(2) 2019 2020 2021 2022 Thereafter (In thousands) Operating leases(3) $ 11,930 $ 2,521 $ 5,251 $ 1,366 $ 419 $ 419 $ 1,954 __________________________________ (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. (2) Represents payments for the period from July 1, 2018 through December 31, 2018 . (3) Primarily relates to corporate office and foreign office leases.

Additional Financial Informatio

Additional Financial Information	6 Months Ended
	Jun. 30, 2018
Additional Financial Information
Additional Financial Information	Additional Financial Information Accrued Liabilities Accrued liabilities consisted of the following: June 30, December 31, (In thousands) Accrued liabilities: Exploration, development and production $ 85,079 $ 144,717 General and administrative expenses 20,178 31,124 Interest 20,331 20,457 Income taxes 2,539 17,423 Taxes other than income 3,906 3,270 Derivatives 12,394 825 Other 1,173 1,596 $ 145,600 $ 219,412 Other Income, Net Other income, net consisted of zero and $10.2 million of Loss of Production Income (“LOPI”) proceeds, net related to the turret bearing issue on the Jubilee FPSO for the three months ended June 30, 2018 and 2017 , respectively and zero and $58.7 million for the six months ended June 30, 2018 and 2017 , respectively. Our LOPI coverage for this incident ended in May 2017. Oil and Gas Production Oil and gas production expense included insurance recoveries related to our increased cost of working covered by our LOPI policy of zero and $13.7 million for the three months ended June 30, 2018 and 2017 , respectively and zero and $17.1 million for the six months ended June 30, 2018 and 2017 , respectively. Facilities Insurance Modifications, Net Facilities insurance modifications, net consists of costs associated with the long-term solution to convert the Jubilee FPSO to a permanently spread moored facility which we expect to recover from our insurance policy net of any insurance reimbursements. Other Expenses, Net Other expenses, net incurred during the period is comprised of the following: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In thousands) (Gain) loss on disposal of inventory $ (24 ) $ 547 $ (24 ) $ 547 Gain on insurance settlements — — — (461 ) Disputed charges and related costs 626 1,209 2,961 2,439 Other, net 336 252 1,706 245 Other expenses, net $ 938 $ 2,008 $ 4,643 $ 2,770 The disputed charges and related costs are expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow has charged such expenditures to the Deepwater Tano (“DT”) joint account. Kosmos disputed through arbitration that these expenditures were chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement. In July 2018, the International Chamber of Commerce ("ICC") issued its Final Award in the arbitration in favor of Kosmos. As a result, we expect to recover from Tullow Ghana Limited the disputed charges, which include amounts previously paid under protest as well as certain costs and fees of pursuing the arbitration, estimated at approximately $14 million plus interest.

Accounting Policies (Policies)

Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
General	General The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of June 30, 2018 , the changes in the consolidated statements of shareholders’ equity for the six months ended June 30, 2018 , the consolidated results of operations for the three and six months ended June 30, 2018 and 2017 , and the consolidated cash flows for the six months ended June 30, 2018 and 2017 . The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2017 , included in our annual report on Form 10-K.
Reclassifications	Reclassifications Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net loss , current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows.
Cash, Cash Equivalents and Restricted Cash	Cash, Cash Equivalents and Restricted Cash Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. In accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts.
Inventories	Inventories The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.
Revenue Recognition	Revenue Recognition We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. Our oil and gas revenues are recognized based on the product that has transferred to the customer during the lifting process as of a point in time when control has transferred, usually over a 24 hour period, and generally based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale.
Recent Accounting Standards	Recent Accounting Standards Recently Adopted In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company adopted the new standard during the first quarter of 2018 using the modified retrospective approach and there is no impact to our previously recorded revenue under the new standard. In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740).” ASU 2018-05 was issued to include amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 ("SAB 118") and addresses certain circumstances that may arise for registrants in accounting for the income tax effects of the Tax Cut and Jobs Act (the "Tax Reform Act"), including when certain income tax effects of the Tax Reform Act are incomplete by the time the financial statements are issued. Not Yet Adopted In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The new leasing standard requires the modified retrospective adoption method. The Company is in the process of evaluating its contract population to determine the impact of this accounting standard on its consolidated financial statements.

Accounting Policies (Tables)

Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Schedule of cash and cash equivalents	June 30, December 31, (In thousands) Cash and cash equivalents $ 116,941 $ 233,412 Restricted cash - current 20,377 56,380 Restricted cash - long-term 9,168 15,194 Total cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows $ 146,486 $ 304,986
Schedule of oil and gas revenue	Oil and gas revenue is composed of the following: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In thousands) Revenue from contracts with customers - Ghana $ 213,841 $ 140,915 $ 341,878 $ 244,355 Provisional oil sales contracts 1,350 (4,552 ) 509 (4,560 ) Oil and gas revenue $ 215,191 $ 136,363 342,387 239,795

Property and Equipment (Tables)

Property and Equipment (Tables)	6 Months Ended
	Jun. 30, 2018
Property, Plant and Equipment [Abstract]
Schedule of property and equipment	Property and equipment is stated at cost and consisted of the following: June 30, December 31, (In thousands) Oil and gas properties: Proved properties $ 1,676,732 $ 1,653,616 Unproved properties 492,468 465,109 Support equipment and facilities 1,442,325 1,427,054 Total oil and gas properties 3,611,525 3,545,779 Accumulated depletion (1,357,710 ) (1,234,806 ) Oil and gas properties, net 2,253,815 2,310,973 Other property 43,906 39,405 Accumulated depreciation (34,657 ) (32,550 ) Other property, net 9,249 6,855 Property and equipment, net $ 2,263,064 $ 2,317,828

Suspended Well Costs (Tables)

Suspended Well Costs (Tables)	6 Months Ended
	Jun. 30, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of capitalized exploratory well costs	The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the six months ended June 30, 2018 . The table excludes $43.8 million in costs that were capitalized and subsequently expensed during the same period. June 30, (In thousands) Beginning balance $ 410,113 Additions to capitalized exploratory well costs pending the determination of proved reserves 6,619 Reclassification due to determination of proved reserves — Capitalized exploratory well costs charged to expense (796 ) Ending balance $ 415,936
Schedule of aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year	The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: June 30, 2018 December 31, 2017 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 35,513 $ 67,159 Exploratory well costs capitalized for a period of one to two years 258,998 291,252 Exploratory well costs capitalized for a period of three to six years 121,425 51,702 Ending balance $ 415,936 $ 410,113 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 5 5

Equity Method Investments (Tabl

Equity Method Investments (Tables)	6 Months Ended
	Jun. 30, 2018
Equity Method Investments and Joint Ventures [Abstract]
Summary of financial information of KTIPI	Below is a summary of financial information for KTIPI presented on a 100% basis. June 30, December 31, 2018 2017 (In thousands) Assets Total current assets $ 164,997 $ 179,070 Property and equipment, net 311,138 345,611 Other assets 544 567 Total assets $ 476,679 $ 525,248 Liabilities and shareholders' equity Total current liabilities $ 132,096 $ 106,769 Total long-term liabilities 548,434 565,591 Shareholders' equity: Total shareholders' equity (203,851 ) (147,112 ) Total liabilities and shareholders' equity $ 476,679 $ 525,248 Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 (In thousands) Revenues and other income: Oil and gas revenue $ 138,395 $ 384,749 Other income (170 ) 117 Total revenues and other income 138,225 384,866 Costs and expenses: Oil and gas production 23,332 75,033 Depletion and depreciation 21,881 75,951 Other expenses, net (73 ) (152 ) Total costs and expenses 45,140 150,832 Income before income taxes 93,085 234,034 Income tax expense 33,620 83,251 Net income $ 59,465 $ 150,783 Kosmos' share of net income $ 29,733 $ 75,392 Basis difference amortization(1) 13,633 40,596 Equity in earnings - KTIPI $ 16,100 $ 34,796 ______________________________________ (1) The basis difference, which is associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortize the basis difference using the unit-of-production method.

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Schedule of debt	June 30, December 31, (In thousands) Outstanding debt principal balances: Facility $ 700,000 $ 800,000 Senior Notes 525,000 525,000 Total 1,225,000 1,325,000 Unamortized deferred financing costs and discounts(1) (57,225 ) (42,203 ) Long-term debt, net $ 1,167,775 $ 1,282,797 __________________________________ (1) Includes $40.9 million and $23.6 million of unamortized deferred financing costs related to the Facility and $16.3 million and $18.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of June 30, 2018 and December 31, 2017 , respectively.
Schedule of estimated repayments of debt	At June 30, 2018 , the estimated repayments of debt during the five fiscal year periods and thereafter are as follows: Payments Due by Year Total 2018(2) 2019 2020 2021 2022 Thereafter (In thousands) Principal debt repayments(1) $ 1,225,000 $ — $ — $ — $ 525,000 $ — $ 700,000 __________________________________ (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on, as of June 30, 2018 , our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of June 30, 2018 , there were no borrowings under the Corporate Revolver. (2) Represents payments for the period July 1, 2018 through December 31, 2018 .
Schedule of interest and other financing costs, net	Interest and other financing costs, net incurred during the periods is comprised of the following: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In thousands) Interest expense $ 24,912 $ 22,792 $ 49,804 $ 45,973 Amortization—deferred financing costs 2,283 2,551 4,723 5,102 Loss on extinguishment of debt — — 4,056 — Capitalized interest (9,292 ) (7,376 ) (14,112 ) (16,935 ) Deferred interest 166 634 (1,090 ) 949 Interest income (843 ) (760 ) (1,791 ) (1,740 ) Other, net 1,644 1,624 2,974 2,902 Interest and other financing costs, net $ 18,870 $ 19,465 $ 44,564 $ 36,251

Derivative Financial Instrume29

Derivative Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of oil derivative contracts	The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of June 30, 2018 . Volumes and weighted average prices are net of any offsetting derivative contracts entered into. Weighted Average Dated Brent Price per Bbl Net Deferred Premium Term Type of Contract MBbl Payable/(Receivable) Swap Sold Put Floor Ceiling Call 2018: July — December Swap with puts 3,000 $ — $ 56.75 $ 43.33 $ — $ — $ — July — December Three-way collars 1,466 0.74 — 41.57 56.57 65.91 — July — December Four-way collars 1,503 1.06 — 40.00 50.00 61.33 70.00 July — December Sold calls(1) 1,006 — — — — 65.00 — July — December Purchased Calls 1,000 1.88 — — — — 70.00 2019: January — December Three-way collars 10,500 $ 0.61 $ — $ 43.81 $ 53.33 $ 69.77 $ — January — December Sold calls(1) 913 — — — — 80.00 — 2020: January — December Sold calls(1) 4,000 $ — $ — $ — $ — $ 80.00 $ — __________________________________ (1) Represents call option contracts sold to counterparties to enhance other derivative positions.
Schedule of interest rate derivative contracts	The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of June 30, 2018 : Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) July 2018 — December 2018 Capped swap 1-month LIBOR $ 200,000 1.23 % 3.00 %
Schedule of derivative instruments by balance sheet location	The following tables disclose the Company’s derivative instruments as of June 30, 2018 and December 31, 2017 and gain/(loss) from derivatives during the three and six months ended June 30, 2018 and 2017 , respectively: Estimated Fair Value Asset (Liability) Type of Contract Balance Sheet Location June 30, December 31, (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ 17,119 $ 665 Interest rate Derivatives assets—current 934 1,017 Commodity(2) Derivatives assets—long-term 10,421 39 Derivative liabilities: Commodity(3) Derivatives liabilities—current (162,329 ) (67,531 ) Commodity(4) Derivatives liabilities—long-term (83,733 ) (30,209 ) Total derivatives not designated as hedging instruments $ (217,588 ) $ (96,019 ) __________________________________ (1) Includes net deferred premiums payable of $2.1 million and net deferred premiums receivable of $0.8 million related to commodity derivative contracts as of June 30, 2018 and December 31, 2017 , respectively. (2) Includes net deferred premiums payable of $0.9 million and net deferred premiums receivable of $0.1 million related to commodity derivative contracts as of June 30, 2018 and December 31, 2017 , respectively. (3) Includes net deferred premiums payable of $5.1 million and $5.6 million related to commodity derivative contracts as of June 30, 2018 and December 31, 2017 , respectively. (4) Includes net deferred premiums payable of $2.8 million and $4.8 million related to commodity derivative contracts as of June 30, 2018 and December 31, 2017 , respectively.
Schedule of derivative instruments by location of gain/(loss)	Amount of Gain/(Loss) Amount of Gain/(Loss) Three Months Ended Six Months Ended June 30, June 30, Type of Contract Location of Gain/(Loss) 2018 2017 2018 2017 (In thousands) Derivatives not designated as hedging instruments: Commodity(1) Oil and gas revenue $ 1,350 $ (4,552 ) $ 509 $ (4,560 ) Commodity Derivatives, net (140,272 ) 25,411 (178,750 ) 63,268 Interest rate Interest expense 98 (92 ) 451 236 Total derivatives not designated as hedging instruments $ (138,824 ) $ 20,767 $ (177,790 ) $ 58,944 __________________________________ (1) Amounts represent the change in fair value of our provisional oil sales contracts.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Schedule of Company's assets and liabilities that are measured at fair value on a recurring basis	The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 , for each fair value hierarchy level: Fair Value Measurements Using: Quoted Prices in Active Markets for Significant Other Significant Identical Assets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) June 30, 2018 Assets: Commodity derivatives $ — $ 27,540 $ — $ 27,540 Interest rate derivatives — 934 — 934 Liabilities: Commodity derivatives — (246,062 ) — (246,062 ) Total $ — $ (217,588 ) $ — $ (217,588 ) December 31, 2017 Assets: Commodity derivatives $ — $ 704 $ — $ 704 Interest rate derivatives — 1,017 — 1,017 Liabilities: Commodity derivatives — (97,740 ) — (97,740 ) Total $ — $ (96,019 ) $ — $ (96,019 )
Schedule of carrying values and fair values of financial instruments that are not carried at fair value	The following table presents the carrying values and fair values at June 30, 2018 and December 31, 2017 : June 30, 2018 December 31, 2017 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 509,685 $ 535,264 $ 507,600 $ 542,472 Facility 700,000 700,000 800,000 800,000 Total $ 1,209,685 $ 1,235,264 $ 1,307,600 $ 1,342,472

Equity-based Compensation (Tabl

Equity-based Compensation (Tables)	6 Months Ended
	Jun. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of plan activity	The following table reflects the outstanding restricted stock awards as of June 30, 2018 : Weighted- Service Vesting Average Restricted Stock Grant-Date Awards Fair Value (In thousands) Outstanding at December 31, 2017 220 $ 8.64 Granted — — Forfeited — — Vested (220 ) 8.64 Outstanding at June 30, 2018 — — The following table reflects the outstanding restricted stock units as of June 30, 2018 : Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Units Fair Value Units Fair Value (In thousands) (In thousands) Outstanding at December 31, 2017 4,183 $ 6.39 8,452 $ 11.26 Granted(1) 2,125 6.92 7,439 12.35 Forfeited (63 ) 6.73 (37 ) 10.04 Vested (2,062 ) 6.93 (9,350 ) 13.75 Outstanding at June 30, 2018 4,183 6.33 6,504 8.91 __________________________________ (1) The restricted stock units with a combination of market and service vesting criteria include 4.9 million shares granted as a result of the 2014 and 2015 awards achieving 200% of their respective market performance conditions.

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Schedule of components of income (loss) before income taxes	Income (loss) before income taxes is composed of the following: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In thousands) Bermuda $ (15,890 ) $ (16,759 ) $ (31,961 ) $ (32,940 ) United States 1,682 1,382 3,315 2,794 Foreign—other (134,410 ) 30,649 (194,546 ) 38,754 Income (loss) before income taxes $ (148,618 ) $ 15,272 $ (223,192 ) $ 8,608

Net Loss Per Share (Tables)

Net Loss Per Share (Tables)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Schedule of reconciliation between net income and amounts used to compute basic and diluted EPS	The following table is a reconciliation between net loss and the amounts used to compute basic and diluted net loss per share and the weighted average shares outstanding used to compute basic and diluted net loss per share: Three Months Ended Six Months Ended June 30, June 30, 2018 2017 2018 2017 Numerator: Net loss $ (103,273 ) $ (8,467 ) $ (153,499 ) $ (37,308 ) Basic income allocable to participating securities(1) — — — — Basic net loss allocable to common shareholders (103,273 ) (8,467 ) (153,499 ) (37,308 ) Diluted adjustments to income allocable to participating securities(1) — — — — Diluted net loss allocable to common shareholders $ (103,273 ) $ (8,467 ) $ (153,499 ) $ (37,308 ) Denominator: Weighted average number of shares outstanding: Basic 396,826 387,952 396,218 387,634 Restricted stock awards and units(1)(2) — — — — Diluted 396,826 387,952 396,218 387,634 Net loss per share: Basic $ (0.26 ) $ (0.02 ) $ (0.39 ) $ (0.10 ) Diluted $ (0.26 ) $ (0.02 ) $ (0.39 ) $ (0.10 ) __________________________________ (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net loss per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net loss per common share calculation in periods we are in a net loss position. (2) We excluded outstanding restricted stock awards and units of 11.4 million and 13.0 million for the three months ended June 30, 2018 and 2017 , respectively, and 11.9 million and 13.0 million for the six months ended June 30, 2018 and 2017 , respectively, from the computations of diluted net loss per share because the effect would have been anti-dilutive .

Commitments and Contingencies (

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of estimated future minimum commitments	Future minimum rental commitments under our leases at June 30, 2018 , are as follows: Payments Due By Year(1) Total 2018(2) 2019 2020 2021 2022 Thereafter (In thousands) Operating leases(3) $ 11,930 $ 2,521 $ 5,251 $ 1,366 $ 419 $ 419 $ 1,954 __________________________________ (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. (2) Represents payments for the period from July 1, 2018 through December 31, 2018 . (3) Primarily relates to corporate office and foreign office leases.

Additional Financial Informat35

Additional Financial Information (Tables)	6 Months Ended
	Jun. 30, 2018
Additional Financial Information
Schedule of accrued liabilities	Accrued liabilities consisted of the following: June 30, December 31, (In thousands) Accrued liabilities: Exploration, development and production $ 85,079 $ 144,717 General and administrative expenses 20,178 31,124 Interest 20,331 20,457 Income taxes 2,539 17,423 Taxes other than income 3,906 3,270 Derivatives 12,394 825 Other 1,173 1,596 $ 145,600 $ 219,412
Schedule of other expenses, net incurred	Other expenses, net incurred during the period is comprised of the following: Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 (In thousands) (Gain) loss on disposal of inventory $ (24 ) $ 547 $ (24 ) $ 547 Gain on insurance settlements — — — (461 ) Disputed charges and related costs 626 1,209 2,961 2,439 Other, net 336 252 1,706 245 Other expenses, net $ 938 $ 2,008 $ 4,643 $ 2,770

Organization (Details)

Organization (Details)	6 Months Ended
	Jun. 30, 2018segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of reportable segments	1

Accounting Policies (Details)

Accounting Policies (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016	Aug. 31, 2014
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents	$ 116,941	$ 233,412
Restricted cash - current	20,377	56,380
Restricted cash - long-term	9,168	15,194
Total cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows	146,486	304,986	$ 231,545	$ 273,195
Inventories
Materials and supplies inventory	65,100	63,500
Hydrocarbons inventory	$ 6,000	8,400
Senior Notes | 7.875% senior notes due 2021
Cash, Cash Equivalents and Restricted Cash
Interest rate	7.875%				7.875%
Restricted Cash | Petroleum agreements - performance guarantees
Cash, Cash Equivalents and Restricted Cash
Restricted cash - current	$ 20,400	31,600
Restricted cash - long-term	8,900	15,200
Restricted Cash | Non-petroleum agreements
Cash, Cash Equivalents and Restricted Cash
Restricted cash - long-term	$ 300
Restricted Cash | Facility interest or the Senior Notes plus the Corporate Revolver interest
Cash, Cash Equivalents and Restricted Cash
Restricted cash - current		$ 24,800
Restricted cash period required as per commercial debt facility to meet interest and commitment fee payments	6 months

Accounting Policies Summary of

Accounting Policies Summary of Oil and Gas Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers - Ghana	$ 213,841	$ 140,915	$ 341,878	$ 244,355
Provisional oil sales contracts	(138,824)	20,767	(177,790)	58,944
Oil and gas revenue	215,191	136,363	342,387	239,795
Oil and Gas
Disaggregation of Revenue [Line Items]
Provisional oil sales contracts	$ 1,350	$ (4,552)	$ 509	$ (4,560)

Acquisitions and Divestitures (

Acquisitions and Divestitures (Details)	1 Months Ended				2 Months Ended	3 Months Ended
	Jun. 30, 2018km²	May 31, 2018km²sub_periodblock	Mar. 31, 2018km²block	Dec. 31, 2017km²block	Sep. 30, 2018USD ($)	Dec. 31, 2017USD ($)km²	Feb. 28, 2018USD ($)
Petroleum Agreement | Blocks 10 and 13
Acquisitions and Divestitures
Participating interests			35.00%
Area of petroleum exploration			13,600
Exploration period			4 years
First sub exploration period			4 years
3D seismic requirements			13,500
Number of blocks | block			2
Petroleum Agreement | Blocks EG-21, S and W
Acquisitions and Divestitures
Participating interests		40.00%
Area of petroleum exploration		6,000
Exploration period		5 years
First sub exploration period		3 years
3D seismic requirements		6,000
Number of blocks | block		3
Number of sub-periods | sub_period		2
Second sub exploration period		2 years
Petroleum Agreement | Blocks CI-526, CI-602, CI-603, CI-707 and CI-708
Acquisitions and Divestitures
Participating interests				45.00%
Area of petroleum exploration				17,000		17,000
Exploration period				3 years
3D seismic requirements				12,000
Number of blocks | block				5
Farm-in agreement | Block EG-24
Acquisitions and Divestitures
Area of petroleum exploration	3,500
Exploration period	3 years
First sub exploration period	4 years
3D seismic requirements	3,000
Participation interest acquired	40.00%
Sales and purchase agreement | Ceiba Field and Okume Complex Assets | Hess
Acquisitions and Divestitures
Total consideration | $						$ 650,000,000
Cash consideration | $						$ 231,000,000
BP | Petroleum Agreement | Blocks 10 and 13
Acquisitions and Divestitures
Participating interests			50.00%
BP | Petroleum Agreement | Blocks CI-526, CI-602, CI-603, CI-707 and CI-708
Acquisitions and Divestitures
Participating interests				45.00%
ANP STP | Petroleum Agreement | Blocks 10 and 13
Acquisitions and Divestitures
Carried participating interest percentage	15.00%
Hess | Ceiba Field and Okume Complex Assets
Acquisitions and Divestitures
Paying interest, percentage						85.00%
Revenue interest, percentage						80.75%
Trident | Farm out agreement | Blocks EG-21, S and W
Acquisitions and Divestitures
Participation interest acquired		40.00%
GEPetrol | Petroleum Agreement | Blocks EG-21, S and W
Acquisitions and Divestitures
Carried participating interest percentage		20.00%
Percentage converted from carried to participating		20.00%
PETROCI Holding | Petroleum Agreement | Blocks CI-526, CI-602, CI-603, CI-707 and CI-708
Acquisitions and Divestitures
Carried participating interest percentage				10.00%		10.00%
Hess | Sales and purchase agreement | Ceiba Field and Okume Complex Assets
Acquisitions and Divestitures
Ownership percentage	50.00%
Hess | Trident | Sales and purchase agreement | Ceiba Field and Okume Complex Assets
Acquisitions and Divestitures
Ownership percentage	50.00%
The Facility | Revolving Credit Facility
Acquisitions and Divestitures
Additional commitments | $							$ 500,000,000
Forecast | Deep Gulf Energy, LP
Acquisitions and Divestitures
Total consideration | $					$ 1,225,000,000
Cash consideration | $					925,000,000
Equity consideration | $					300,000,000
Forecast | The Facility | Revolving Credit Facility
Acquisitions and Divestitures
Additional commitments | $					$ 200,000,000

Joint Interest Billings (Detail

Joint Interest Billings (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Jun. 30, 2018	Dec. 31, 2017
Joint interest billings
Joint interest billings, net		$ 68,006	$ 134,565
Long-term receivables - joint interest billings		28,981	34,941
TEN Discoveries | GNPC
Joint interest billings
Joint interest billings, net		14,000	15,200
Long-term receivables - joint interest billings		$ 29,000	$ 31,600
TEN Discoveries | GNPC
Joint interest billings
GNPC's paying interest	5.00%

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Oil and gas properties:
Proved properties	$ 1,676,732		$ 1,676,732		$ 1,653,616
Unproved properties	492,468		492,468		465,109
Support equipment and facilities	1,442,325		1,442,325		1,427,054
Total oil and gas properties	3,611,525		3,611,525		3,545,779
Accumulated depletion	(1,357,710)		(1,357,710)		(1,234,806)
Oil and gas properties, net	2,253,815		2,253,815		2,310,973
Other property	43,906		43,906		39,405
Accumulated depreciation	(34,657)		(34,657)		(32,550)
Other property, net	9,249		9,249		6,855
Property and equipment, net	2,263,064		2,263,064		$ 2,317,828
Depletion expense	$ 71,300	$ 69,900	$ 122,900	$ 102,400

Suspended Well Costs (Details)

Suspended Well Costs (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2018USD ($)	Jun. 30, 2018USD ($)project	Dec. 31, 2017USD ($)project	May 31, 2015project
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized exploratory well costs subsequently expensed in the same period	$ 43,800
Reconciliation of capitalized exploratory well costs on completed wells
Beginning balance	410,113
Additions to capitalized exploratory well costs pending the determination of proved reserves	6,619
Reclassification due to determination of proved reserves	0
Capitalized exploratory well costs charged to expense	(796)
Ending balance	415,936
Aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year
Exploratory well costs capitalized for a period of one year or less		$ 35,513	$ 67,159
Exploratory well costs capitalized for a period of one to two years		258,998	291,252
Exploratory well costs capitalized for a period of three to six years		121,425	51,702
Ending balance	$ 410,113	$ 415,936	$ 410,113
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | project		5	5
Greater Tortue Discovery
Projects with exploratory well costs capitalized for more than one year
Number of additional appraisal wells drilled | project				2

Equity Method Investments - Nar

Equity Method Investments - Narrative (Details) - USD ($)	1 Months Ended			3 Months Ended		6 Months Ended
	Jul. 31, 2018	Oct. 31, 2017	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Schedule of Equity Method Investments [Line Items]
Gain (loss) on equity method investments, net				$ 16,100,000	$ (6,426,000)	$ 34,796,000	$ (6,426,000)
Contribution to equity method investment						$ 0	133,893,000
Kosmos BP Senegal Limited
Schedule of Equity Method Investments [Line Items]
Ownership percentage			50.01%
Gain (loss) on equity method investments, net					$ (6,400,000)		$ (6,400,000)
Contribution to equity method investment			$ 133,900,000
Kosmos-Trident International Petroleum Inc.
Schedule of Equity Method Investments [Line Items]
Ownership percentage				50.00%		50.00%
Gain (loss) on equity method investments, net				$ 16,100,000		$ 34,796,000
Impairment of equity method investment						0
Cash dividends from KTIPI						$ 120,000,000
Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Schedule of Equity Method Investments [Line Items]
Participating interests						30.00%
BP Senegal Investments Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | Kosmos BP Senegal Limited
Schedule of Equity Method Investments [Line Items]
Participating interest transferred		30.00%
Subsequent Event | Kosmos-Trident International Petroleum Inc.
Schedule of Equity Method Investments [Line Items]
Cash dividends from KTIPI	$ 27,500,000

Equity Method Investments - Sum

Equity Method Investments - Summary of Financial Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Costs and expenses:
Equity in earnings - KTIPI	$ 16,100	$ (6,426)	$ 34,796	$ (6,426)
Kosmos-Trident International Petroleum Inc.
Schedule of Equity Method Investments [Line Items]
Basis presented	100.00%		100.00%
Assets
Total current assets	$ 164,997		$ 164,997		$ 179,070
Property and equipment, net	311,138		311,138		345,611
Other assets	544		544		567
Total assets	476,679		476,679		525,248
Liabilities and shareholders' equity
Total current liabilities	132,096		132,096		106,769
Total long-term liabilities	548,434		548,434		565,591
Shareholders' equity:
Total shareholders' equity	(203,851)		(203,851)		(147,112)
Total liabilities and shareholders' equity	476,679		476,679		$ 525,248
Revenues and other income:
Oil and gas revenue	138,395		384,749
Other income	(170)		117
Total revenues and other income	138,225		384,866
Costs and expenses:
Oil and gas production	23,332		75,033
Depletion and depreciation	21,881		75,951
Other expenses, net	(73)		(152)
Total costs and expenses	45,140		150,832
Income before income taxes	93,085		234,034
Income tax expense	33,620		83,251
Net income	59,465		150,783
Kosmos' share of net income	29,733		75,392
Basis difference amortization	13,633		40,596
Equity in earnings - KTIPI	$ 16,100		$ 34,796

Debt - Schedule of Instruments

Debt - Schedule of Instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Debt
Outstanding debt principal	$ 1,225,000	$ 1,325,000
Unamortized issuance costs and discount	(57,225)	(42,203)
Long-term debt, net	1,167,775	1,282,797
Revolving Credit Facility
Debt
Outstanding debt principal	700,000	800,000
Senior Notes
Debt
Outstanding debt principal	525,000	525,000
Unamortized issuance costs and discount	(16,300)	(18,600)
The Facility | Revolving Credit Facility
Debt
Unamortized issuance costs and discount	$ (40,900)	$ (23,600)

Debt - Facility (Details)

Debt - Facility (Details)	1 Months Ended	3 Months Ended		6 Months Ended
	Feb. 28, 2018USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Aug. 07, 2018USD ($)financial_institution	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
Loss on extinguishment of debt		$ 0	$ 0	$ 4,056,000	$ 0
Net deferred financing costs		1,141,000		1,141,000			$ 2,510,000
The Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Total commitment	$ 1,500,000,000
Additional commitments	500,000,000
Loss on extinguishment of debt	$ 4,100,000
Net deferred financing costs		40,900,000		40,900,000
Amount outstanding		700,000,000		700,000,000
Undrawn availability		800,000,000		800,000,000
Repayment of Facility		100,000,000
Current borrowing capacity		1,500,000,000		1,500,000,000
Availability period of revolving-credit	1 month
Amount outstanding under letters of credit		$ 0		$ 0
Subsequent Event | The Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Additional commitments						$ 200,000,000
Number of financial institutions | financial_institution						2

Debt - Corporate Revolver (Deta

Debt - Corporate Revolver (Details) - USD ($)	Aug. 06, 2018	Jun. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Net deferred financing costs		$ 1,141,000	$ 2,510,000
Corporate Revolver | Revolving Credit Facility
Debt Instrument [Line Items]
Amount outstanding		$ 0
Subsequent Event | Corporate Revolver | Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 400,000,000
Change in basis points	(1.00%)
Applicable margin	5.00%
Commitment fee percentage	30.00%

Debt - Revolving Letter of Cred

Debt - Revolving Letter of Credit Facility (Details) - Revolving Letter of Credit Facility	Jul. 31, 2018USD ($)	Jun. 30, 2018USD ($)letter_of_credit
Debt Instrument [Line Items]
Number of letters of credit | letter_of_credit		9
Amount outstanding		$ 36,900,000
Subsequent Event
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 40,000,000

Debt - 7.875% Senior Secured No

Debt - 7.875% Senior Secured Notes due 2021 (Details) - Senior Notes - 7.875% senior notes due 2021 - USD ($)	1 Months Ended
	Apr. 30, 2015	Aug. 31, 2014	Jun. 30, 2018
Debt Instrument [Line Items]
Interest rate		7.875%	7.875%
Senior notes offering face amount	$ 225,000,000	$ 300,000,000
Proceeds, net of offering discounts and deferred financing costs	$ 206,800,000	$ 292,500,000

Debt - Maturities (Details)

Debt - Maturities (Details) - USD ($)	Jun. 30, 2018	Dec. 31, 2017
Scheduled maturities of debt during the five year period and thereafter
Total	$ 1,225,000,000	$ 1,325,000,000
2,018	0
2,019	0
2,020	0
2,021	525,000,000
2,022	0
Thereafter	700,000,000
Senior Notes
Scheduled maturities of debt during the five year period and thereafter
Total	525,000,000	525,000,000
Revolving Credit Facility
Scheduled maturities of debt during the five year period and thereafter
Total	700,000,000	$ 800,000,000
7.875% senior notes due 2021 | Senior Notes
Scheduled maturities of debt during the five year period and thereafter
Total	525,000,000
Corporate Revolver | Revolving Credit Facility
Scheduled maturities of debt during the five year period and thereafter
Amount outstanding	$ 0

Debt - Interest and other finan

Debt - Interest and other financing costs, net (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Debt Disclosure [Abstract]
Interest expense	$ 24,912	$ 22,792	$ 49,804	$ 45,973
Amortization—deferred financing costs	2,283	2,551	4,723	5,102
Loss on extinguishment of debt	0	0	4,056	0
Capitalized interest	(9,292)	(7,376)	(14,112)	(16,935)
Deferred interest	166	634	(1,090)	949
Interest income	(843)	(760)	(1,791)	(1,740)
Other, net	1,644	1,624	2,974	2,902
Interest and other financing costs, net	$ 18,870	$ 19,465	$ 44,564	$ 36,251

Derivative Financial Instrume52

Derivative Financial Instruments - Schedule of oil derivative contracts (Details)	1 Months Ended	6 Months Ended
	Jul. 31, 2018$ / bblMBbls	Jun. 30, 2018$ / bblMBbls
Term July 2018 to December 2018 | Swap with puts
Derivative Financial Instruments
Volume (mbbls) | MBbls		3,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0
Swap (usd per bbl)		56.75
Sold Put (usd per bbl)		43.33
Floor (usd per bbl)		0
Ceiling (usd per bbl)		0
Call (usd per bbl)		0
Term July 2018 to December 2018 | Three-way collars
Derivative Financial Instruments
Volume (mbbls) | MBbls		1,466
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0.74
Swap (usd per bbl)		0
Sold Put (usd per bbl)		41.57
Floor (usd per bbl)		56.57
Ceiling (usd per bbl)		65.91
Call (usd per bbl)		0
Term July 2018 to December 2018 | Four-way collars
Derivative Financial Instruments
Volume (mbbls) | MBbls		1,503
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		1.06
Swap (usd per bbl)		0
Sold Put (usd per bbl)		40
Floor (usd per bbl)		50
Ceiling (usd per bbl)		61.33
Call (usd per bbl)		70
Term July 2018 to December 2018 | Sold calls
Derivative Financial Instruments
Volume (mbbls) | MBbls		1,006
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0
Swap (usd per bbl)		0
Sold Put (usd per bbl)		0
Floor (usd per bbl)		0
Ceiling (usd per bbl)		65
Call (usd per bbl)		0
Term July 2018 to December 2018 | Purchased Calls
Derivative Financial Instruments
Volume (mbbls) | MBbls		1,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		1.88
Swap (usd per bbl)		0
Sold Put (usd per bbl)		0
Floor (usd per bbl)		0
Ceiling (usd per bbl)		0
Call (usd per bbl)		70
Term January 2019 to December 2019 | Three-way collars
Derivative Financial Instruments
Volume (mbbls) | MBbls		10,500
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0.61
Swap (usd per bbl)		0
Sold Put (usd per bbl)		43.81
Floor (usd per bbl)		53.33
Ceiling (usd per bbl)		69.77
Call (usd per bbl)		0
Term January 2019 to December 2019 | Sold calls
Derivative Financial Instruments
Volume (mbbls) | MBbls		913
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0
Swap (usd per bbl)		0
Sold Put (usd per bbl)		0
Floor (usd per bbl)		0
Ceiling (usd per bbl)		80
Call (usd per bbl)		0
Term January 2020 To December 2020 | Sold calls
Derivative Financial Instruments
Volume (mbbls) | MBbls		4,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0
Swap (usd per bbl)		0
Sold Put (usd per bbl)		0
Floor (usd per bbl)		0
Ceiling (usd per bbl)		80
Call (usd per bbl)		0
Subsequent Event | Term January 2019 to December 2019 | Purchased/Sold Calls
Derivative Financial Instruments
Volume (mbbls) | MBbls	3,500
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)	1.46
Ceiling (usd per bbl)	75
Call (usd per bbl)	65
Subsequent Event | Term January 2020 To December 2020 | Sold calls
Derivative Financial Instruments
Volume (mbbls) | MBbls	3,500
Weighted Average Dated Brent Price Per Bbl [Abstract]
Ceiling (usd per bbl)	80

Derivative Financial Instrume53

Derivative Financial Instruments - Schedule of interest rate derivative contracts (Details) - 1-month LIBOR - Interest Rate Cap Swap - Term July 2018 to December 2018 $ in Thousands	Jun. 30, 2018USD ($)
Derivative Financial Instruments
Weighted average notional amount	$ 200,000
Weighted average swap	1.23%
Weighted average sold call	3.00%

Derivative Financial Instrume54

Derivative Financial Instruments - Derivatives instrument and gain/loss from derivatives (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Derivative instruments, Balance Sheet Location
Derivatives assets—current	$ 18,053	$ 1,682
Derivatives assets—long-term	10,421	39
Derivatives liabilities—current	(162,329)	(67,531)
Derivatives liabilities—long-term	(83,733)	(30,209)
Derivatives not designated as hedging instruments:
Derivative instruments, Balance Sheet Location
Total derivatives not designated as hedging instruments	(217,588)	(96,019)
Derivatives not designated as hedging instruments: | Commodity
Derivative instruments, Balance Sheet Location
Derivatives assets—current	17,119	665
Derivatives assets—long-term	10,421	39
Derivatives liabilities—current	(162,329)	(67,531)
Derivatives liabilities—long-term	(83,733)	(30,209)
Net deferred premiums payable related to commodity derivative contracts - current assets	2,100
Net deferred premiums receivable related to commodity derivative contracts - current assets		800
Net deferred premiums payable related to commodity derivative contracts - non-current assets	900
Net deferred premiums receivable related to commodity derivative contracts - non-current assets		100
Net deferred premiums payable related to commodity derivative contracts - current liabilities	5,100	5,600
Net deferred premiums payable related to commodity derivative contracts - non-current liabilities	2,800	4,800
Derivatives not designated as hedging instruments: | Interest rate
Derivative instruments, Balance Sheet Location
Derivatives assets—current	$ 934	$ 1,017

Derivative Financial Instrume55

Derivative Financial Instruments - Schedule of derivative instruments by location of gain/(loss) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	$ (138,824)	$ 20,767	$ (177,790)	$ 58,944
Commodity | Oil and gas revenue
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	1,350	(4,552)	509	(4,560)
Commodity | Derivatives, net
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	(140,272)	25,411	(178,750)	63,268
Interest rate | Interest expense
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	$ 98	$ (92)	$ 451	$ 236

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Carrying Value
Liabilities:
Long-term debt	$ 1,209,685	$ 1,307,600
Fair Value
Liabilities:
Long-term debt	1,235,264	1,342,472
Senior Notes | Carrying Value
Liabilities:
Long-term debt	509,685	507,600
Senior Notes | Fair Value
Liabilities:
Long-term debt	535,264	542,472
Facility | Carrying Value
Liabilities:
Long-term debt	700,000	800,000
Facility | Fair Value
Liabilities:
Long-term debt	700,000	800,000
Recurring basis
Liabilities:
Total fair value, net	(217,588)	(96,019)
Recurring basis | Commodity
Assets:
Derivative asset, fair value	27,540	704
Liabilities:
Derivative liability, fair value	(246,062)	(97,740)
Recurring basis | Interest rate
Assets:
Derivative asset, fair value	934	1,017
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Total fair value, net	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate
Assets:
Derivative asset, fair value	0	0
Recurring basis | Significant Other Observable Inputs (Level 2)
Liabilities:
Total fair value, net	(217,588)	(96,019)
Recurring basis | Significant Other Observable Inputs (Level 2) | Commodity
Assets:
Derivative asset, fair value	27,540	704
Liabilities:
Derivative liability, fair value	(246,062)	(97,740)
Recurring basis | Significant Other Observable Inputs (Level 2) | Interest rate
Assets:
Derivative asset, fair value	934	1,017
Recurring basis | Significant Unobservable Inputs (Level 3)
Liabilities:
Total fair value, net	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Commodity
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Interest rate
Assets:
Derivative asset, fair value	$ 0	$ 0

Equity-based Compensation - Add

Equity-based Compensation - Additional Information (Details) - LTIP - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2018	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recognized		$ 9.1	$ 10.5	$ 17.1	$ 20.3
Tax benefit		1.8	3.5	3.4	6.8
Net tax shortfall (windfall) related to equity-based compensation		0.4	3	(0.3)	2.8
Fair value of awards vested		$ 25.4	$ 10.5	$ 82	$ 19.3
Number of additional shares authorized (in shares)	11,000,000
Number of shares authorized (in shares)		50,500,000		50,500,000
Number of shares remaining available for grant (in shares)		16,000,000		16,000,000
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				3 years
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				4 years
Market/Service Vesting Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant date fair value of awards granted (in dollars per share)				$ 12.35
Market/Service Vesting Restricted Stock Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant date fair value of awards granted (in dollars per share)				$ 4.83
Expected volatility				44.00%
Risk-free interest rate				0.70%
Market/Service Vesting Restricted Stock Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the awards granted (up to)				200.00%
Grant date fair value of awards granted (in dollars per share)				$ 15.71
Expected volatility				53.00%
Risk-free interest rate				2.20%
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense not yet recognized		$ 43.4		$ 43.4
Weighted average period over which compensation expense is to be recognized				2 years 2 months 27 days

Equity-based Compensation - Sch

Equity-based Compensation - Schedule of awards (Details) - LTIP shares in Thousands	6 Months Ended
	Jun. 30, 2018$ / sharesshares
Service Vesting Restricted Stock Awards
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	220
Granted (in shares)	0
Forfeited (in shares)	0
Vested (in shares)	(220)
Outstanding at the end of the period (in shares)	0
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share) | $ / shares	$ 8.64
Granted (in dollars per share) | $ / shares	0
Forfeited (in dollars per share) | $ / shares	0
Vested (in dollars per share) | $ / shares	8.64
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 0
Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	4,183
Granted (in shares)	2,125
Forfeited (in shares)	(63)
Vested (in shares)	(2,062)
Outstanding at the end of the period (in shares)	4,183
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share) | $ / shares	$ 6.39
Granted (in dollars per share) | $ / shares	6.92
Forfeited (in dollars per share) | $ / shares	6.73
Vested (in dollars per share) | $ / shares	6.93
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 6.33
Market/Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	8,452
Granted (in shares)	7,439
Forfeited (in shares)	(37)
Vested (in shares)	(9,350)
Outstanding at the end of the period (in shares)	6,504
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share) | $ / shares	$ 11.26
Granted (in dollars per share) | $ / shares	12.35
Forfeited (in dollars per share) | $ / shares	10.04
Vested (in dollars per share) | $ / shares	13.75
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 8.91
2014 and 2015 | Market/Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Granted (in shares)	4,900
Weighted-Average Grant-Date Fair Value
Vesting percentage of the awards granted	200.00%

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Taxes
Effective tax rate (as a percent)	31.00%	155.00%	31.00%	533.00%
Income (loss) before income taxes	$ (148,618)	$ 15,272	$ (223,192)	$ 8,608
Uncertain tax positions	0		0
Bermuda
Income Taxes
Income (loss) before income taxes	(15,890)	(16,759)	(31,961)	(32,940)
United States
Income Taxes
Income (loss) before income taxes	1,682	1,382	$ 3,315	2,794
Foreign—other
Income Taxes
Effective tax rate (as a percent)			0.00%
Statutory tax rate (as a percent)			0.00%
Income (loss) before income taxes	$ (134,410)	$ 30,649	$ (194,546)	$ 38,754

Net Loss Per Share (Details)

Net Loss Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Numerator:
Net loss	$ (103,273)	$ (8,467)	$ (153,499)	$ (37,308)
Basic income allocable to participating securities	0	0	0	0
Basic net loss allocable to common shareholders	(103,273)	(8,467)	(153,499)	(37,308)
Diluted adjustments to income allocable to participating securities	0	0	0	0
Diluted net loss allocable to common shareholders	$ (103,273)	$ (8,467)	$ (153,499)	$ (37,308)
Weighted average number of shares outstanding:
Basic (in shares)	396,826	387,952	396,218	387,634
Restricted stock awards and units (in shares)	0	0	0	0
Diluted (in shares)	396,826	387,952	396,218	387,634
Net loss per share:
Basic (in dollars per share)	$ (0.26)	$ (0.02)	$ (0.39)	$ (0.10)
Diluted (in dollars per share)	$ (0.26)	$ (0.02)	$ (0.39)	$ (0.10)
Outstanding restricted stock awards and units excluded from the computations of diluted net income per share (in shares)	11,400	13,000	11,900	13,000

Commitments and Contingencies61

Commitments and Contingencies (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2018USD ($)km²exploration_well
Future minimum rental commitments
Total	$ 11,930
2,018	2,521
2,019	5,251
2,020	1,366
2,021	419
2,022	419
Thereafter	$ 1,954
Suriname
Commitments and contingencies
Number of exploration wells | exploration_well	1
Mauritania
Commitments and contingencies
Number of exploration wells | exploration_well	1
Equatorial Guinea
Commitments and contingencies
3D seismic requirements | km²	9,000
Sao Tome and Principe
Commitments and contingencies
3D seismic requirements | km²	13,500

Additional Financial Informat62

Additional Financial Information (Details) - USD ($)	3 Months Ended			6 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Accrued liabilities:
Exploration, development and production		$ 85,079,000		$ 85,079,000		$ 144,717,000
General and administrative expenses		20,178,000		20,178,000		31,124,000
Interest		20,331,000		20,331,000		20,457,000
Income taxes		2,539,000		2,539,000		17,423,000
Taxes other than income		3,906,000		3,906,000		3,270,000
Derivatives		12,394,000		12,394,000		825,000
Other		1,173,000		1,173,000		1,596,000
Accrued liabilities		145,600,000		145,600,000		$ 219,412,000
Other income, net		0	$ 10,200,000	0	$ 58,700,000
Other Expenses, Net
(Gain) loss on disposal of inventory		(24,000)	547,000	(24,000)	547,000
Gain on insurance settlements		0	0	0	(461,000)
Disputed charges and related costs		626,000	1,209,000	2,961,000	2,439,000
Other, net		336,000	252,000	1,706,000	245,000
Other expenses, net		938,000	2,008,000	4,643,000	2,770,000
Oil and gas production expense
Accrued liabilities:
Insurance recoveries		$ 0	$ 13,700,000	$ 0	$ 17,100,000
Forecast
Other Expenses, Net
Estimated recoveries	$ 14,000,000