Kosmos Energy (KOS) 10-K 26 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 16, 2018	Jun. 30, 2017
Document and Entity Information
Entity Registrant Name	Kosmos Energy Ltd.
Entity Central Index Key	1,509,991
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 1,462,148,287
Entity Common Stock, Shares Outstanding		395,706,528
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 233,412	$ 194,057
Restricted cash	56,380	24,506
Receivables:
Joint interest billings, net	134,565	63,249
Oil sales	0	54,195
Related party	780	0
Other	25,616	25,893
Inventories	71,861	74,380
Prepaid expenses and other	9,306	7,209
Derivatives	1,682	31,698
Total current assets	533,602	475,187
Property and equipment:
Oil and gas properties, net	2,310,973	2,700,889
Other property, net	6,855	8,003
Property and equipment, net	2,317,828	2,708,892
Other assets:
Equity method investment	236,514	0
Restricted cash	15,194	54,632
Long-term receivables - joint interest billings	34,941	45,663
Deferred financing costs, net of accumulated amortization of $13,951 and $11,213 at December 31, 2017 and December 31, 2016, respectively	2,510	5,248
Long-term deferred tax assets	22,517	37,827
Derivatives	39	3,808
Other	29,458	10,208
Total assets	3,192,603	3,341,465
Current liabilities:
Accounts payable	141,787	220,627
Accrued liabilities	219,412	129,706
Derivatives	67,531	19,692
Total current liabilities	428,730	370,025
Long-term liabilities:
Long-term debt, net	1,282,797	1,321,874
Derivatives	30,209	14,123
Asset retirement obligations	66,595	63,574
Deferred tax liabilities	476,548	482,221
Other long-term liabilities	10,612	8,449
Total long-term liabilities	1,866,761	1,890,241
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2017 and December 31, 2016	0	0
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 398,599,457 and 395,859,061 issued at December 31, 2017 and December 31, 2016, respectively	3,986	3,959
Additional paid-in capital	2,014,525	1,975,247
Accumulated deficit	(1,073,202)	(850,410)
Treasury stock, at cost, 9,188,819 and 9,101,395 shares at December 31, 2017 and December 31, 2016, respectively	(48,197)	(47,597)
Total shareholders’ equity	897,112	1,081,199
Total liabilities and shareholders’ equity	$ 3,192,603	$ 3,341,465

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Deferred financing costs, accumulated amortization (in dollars)	$ 13,951	$ 11,213
Preference shares, par value (in dollars per share)	$ 0.01	$ 0.01
Preference shares, authorized shares	200,000,000	200,000,000
Preference shares, issued shares	0	0
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, authorized shares	2,000,000,000	2,000,000,000
Common shares, issued shares	398,599,457	395,859,061
Treasury stock shares	9,188,819	9,101,395

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues and other income:
Oil and gas revenue	$ 578,139	$ 310,377	$ 446,696
Gain on sale of assets	0	0	24,651
Other income, net	58,697	74,978	209
Total revenues and other income	636,836	385,355	471,556
Costs and expenses:
Oil and gas production	126,850	119,367	105,336
Facilities insurance modifications, net	(820)	14,961	0
Exploration expenses	216,050	202,280	156,203
General and administrative	68,302	87,623	136,809
Depletion and depreciation	255,203	140,404	155,966
Interest and other financing costs, net	77,595	44,147	37,209
Derivatives, net	59,968	48,021	(210,649)
Loss on equity method investment, net	6,252	0	0
Other expenses, net	5,291	23,116	5,246
Total costs and expenses	814,691	679,919	386,120
Income (loss) before income taxes	(177,855)	(294,564)	85,436
Income tax expense (benefit)	44,937	(10,784)	155,272
Net loss	$ (222,792)	$ (283,780)	$ (69,836)
Net loss per share:
Basic (in dollars per share)	$ (0.57)	$ (0.74)	$ (0.18)
Diluted (in dollars per share)	$ (0.57)	$ (0.74)	$ (0.18)
Weighted average number of shares used to compute net loss per share:
Basic (in shares)	388,375	385,402	382,610
Diluted (in shares)	388,375	385,402	382,610

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net loss	$ (222,792)	$ (283,780)	$ (69,836)
Other comprehensive loss:
Reclassification adjustments for derivative gains included in net loss	0	0	(767)
Other comprehensive loss	0	0	(767)
Comprehensive loss	$ (222,792)	$ (283,780)	$ (70,603)

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common Shares	Additional Paid-in Capital	Accumulated Deficit	Accumulated Other Comprehensive Income	Treasury Stock
Balance (in shares) at Dec. 31, 2014		392,443
Balance at Dec. 31, 2014	$ 1,338,959	$ 3,924	$ 1,860,190	$ (494,850)	$ 767	$ (31,072)
Increase (Decrease) in Shareholders' Equity
Equity-based compensation	75,267		75,267
Derivatives, net	(767)				(767)
Restricted stock awards and units (in shares)		1,460
Restricted stock awards and units	0	$ 15	(15)
Restricted stock forfeitures	0		16			(16)
Purchase of treasury stock	(18,110)		(2,269)			(15,841)
Net loss	(69,836)			(69,836)
Balance (in shares) at Dec. 31, 2015		393,903
Balance at Dec. 31, 2015	1,325,513	$ 3,939	1,933,189	(564,686)	0	(46,929)
Increase (Decrease) in Shareholders' Equity
Equity-based compensation	41,447		43,391	(1,944)
Restricted stock awards and units (in shares)		1,956
Restricted stock awards and units	0	$ 20	(20)
Restricted stock forfeitures	0		2			(2)
Purchase of treasury stock	(1,981)		(1,315)			(666)
Net loss	(283,780)			(283,780)
Balance (in shares) at Dec. 31, 2016		395,859
Balance at Dec. 31, 2016	1,081,199	$ 3,959	1,975,247	(850,410)	0	(47,597)
Increase (Decrease) in Shareholders' Equity
Equity-based compensation	40,899		40,899
Restricted stock awards and units (in shares)		2,740
Restricted stock awards and units	0	$ 27	(27)
Purchase of treasury stock	(2,194)		(1,594)			(600)
Net loss	(222,792)			(222,792)
Balance (in shares) at Dec. 31, 2017		398,599
Balance at Dec. 31, 2017	$ 897,112	$ 3,986	$ 2,014,525	$ (1,073,202)	$ 0	$ (48,197)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities
Net loss	$ (222,792)	$ (283,780)	$ (69,836)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization	265,407	150,608	166,290
Deferred income taxes	9,505	(23,561)	110,786
Unsuccessful well costs	43,201	6,079	94,910
Change in fair value of derivatives	71,822	46,559	(210,957)
Cash settlements on derivatives, net (including $38.7 million, $188.0 million and $225.5 million on commodity hedges during 2017, 2016, and 2015)	25,888	188,895	224,741
Equity-based compensation	39,913	40,084	75,057
Gain on sale of assets	0	0	(24,651)
Loss on extinguishment of debt	0	0	165
Loss on equity method investment, net	6,252	0	0
Other	5,952	13,355	7,875
Changes in assets and liabilities:
(Increase) decrease in receivables	29,365	(20,558)	2,209
(Increase) decrease in inventories	1,653	(4,107)	(29,855)
(Increase) decrease in prepaid expenses and other	(31,710)	17,557	512
Increase (decrease) in accounts payable	(94,434)	(75,487)	111,289
Increase (decrease) in accrued liabilities	86,595	(3,567)	(17,756)
Net cash provided by operating activities	236,617	52,077	440,779
Investing activities
Oil and gas assets	(140,495)	(535,975)	(823,642)
Other property	(2,858)	(1,998)	(1,483)
Equity method investment	(231,280)	0	0
Proceeds on sale of assets	222,068	210	28,692
Net cash used in investing activities	(152,565)	(537,763)	(796,433)
Financing activities
Borrowings under long-term debt	200,000	450,000	100,000
Payments on long-term debt	(250,000)	0	(200,000)
Net proceeds from issuance of senior secured notes	0	0	206,774
Purchase of treasury stock	(2,194)	(1,981)	(18,110)
Deferred financing costs	(67)	0	(9,030)
Net cash provided by (used in) financing activities	(52,261)	448,019	79,634
Net increase (decrease) in cash, cash equivalents and restricted cash	31,791	(37,667)	(276,020)
Cash, cash equivalents and restricted cash at beginning of period	304,986	273,195	310,862
Cash, cash equivalents and restricted cash at end of period	273,195	310,862	586,882
Cash paid for:
Interest	55,381	27,860	33,315
Income taxes	48,815	13,997	35,857
Non-cash activity:
Conversion of joint interest billings receivable to long-term note receivable	0	9,814	0
Contribution to equity method investment	133,893	0	0
Dissolution of equity method investment	$ (122,407)	$ 0	$ 0

CONSOLIDATED STATEMENTS OF CAS8

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Cash Flows [Abstract]
Cash settlements on commodity hedges derivatives	$ 38.7	$ 188	$ 225.5

Organization

Organization	12 Months Ended
	Dec. 31, 2017
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 leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margins. Our assets include existing production and development projects offshore Ghana and Equatorial Guinea, large discoveries and significant further exploration potential offshore Mauritania and Senegal, as well as exploration licenses offshore Cote d'Ivoire, Equatorial Guinea, Morocco, Sao Tome and Principe, and Suriname. Kosmos is listed on the New York Stock Exchange (“NYSE”) and London Stock Exchange ("LSE") 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	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Accounting Policies	Accounting Policies Principles of Consolidation The accompanying consolidated financial statements include the accounts of Kosmos Energy Ltd. and its wholly owned subsidiaries. They also include the Corporation’s share of the undivided interest in certain assets, liabilities, revenues and expenses. Investments in corporate joint ventures, which we exercise significant influence over, are accounted for using the equity method of accounting. All intercompany transactions have been eliminated. Investments in companies that are partially owned by the Corporation are integral to the Corporation’s operations. The other parties, who also have an equity interest in these companies, are independent third parties that share in the business results according to their ownership. Kosmos does not invest in these companies in order to remove liabilities from its balance sheet. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates. Reclassifications Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no material impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows, except as disclosed related to the adoption of recent accounting pronouncements. Cash, Cash Equivalents and Restricted Cash December 31, 2017 2016 2015 (In thousands) Cash and cash equivalents $ 233,412 $ 194,057 $ 275,004 Restricted cash - current 56,380 24,506 28,533 Restricted cash - long-term 15,194 54,632 7,325 Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ 304,986 $ 273,195 $ 310,862 Cash and cash equivalents includes 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 our commercial debt facility (the “Facility”), we were required to maintain a restricted cash balance that is 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 is greater. As of December 31, 2017 and 2016 , we had $24.8 million and $24.5 million , respectively, in current restricted cash to meet this requirement. In addition, 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 December 31, 2017 and 2016 , we had $31.6 million and zero , respectively, of current restricted cash and $15.2 million and $54.6 million , respectively, of long‑term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts. Receivables Our receivables consist of joint interest billings, oil sales and other receivables. For our oil sales receivable, we require a letter of credit to be posted to secure the outstanding receivable. Receivables from joint interest owners are stated at amounts due, net of any allowances for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things. We had an allowance for doubtful accounts of zero and $0.6 million in current joint interest billings receivables as of December 31, 2017 and 2016 , respectively. Inventories Inventories consisted of $63.5 million and $68.1 million of materials and supplies and $8.4 million and $6.3 million of hydrocarbons as of December 31, 2017 and 2016 , 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. We recorded write downs of $0.9 million , $14.9 million and nil during the years ended December 31, 2017 , 2016 and 2015 for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows. 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. Exploration and Development Costs The Company follows the successful efforts method of accounting for its oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are expensed as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed and recorded in exploration expense on the consolidated statement of operations. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed as oil and gas production expense. The Company evaluates unproved property periodically for impairment. The impairment assessment considers results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential future reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time. Depletion, Depreciation and Amortization Proved properties and support equipment and facilities are depleted using the unit‑of‑production method based on estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in a discovery of proved reserves and development costs are amortized using the unit‑of‑production method based on estimated proved developed oil and natural gas reserves for the related field. Depreciation and amortization of other property is computed using the straight-line method over the assets’ estimated useful lives (not to exceed the lease term for leasehold improvements), ranging from one to eight years . Years Depreciated Leasehold improvements 1 to 8 Office furniture, fixtures and computer equipment 3 to 7 Vehicles 5 Amortization of deferred financing costs is computed using the straight‑line method over the life of the related debt. Capitalized Interest Interest costs from external borrowings are capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is depleted on the unit‑of‑production method in the same manner as the underlying assets. Asset Retirement Obligations The Company accounts for asset retirement obligations as required by ASC 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion and depreciation in the consolidated statement of operations. Impairment of Long‑lived Assets The Company reviews its long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable, or at least annually. ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value. The carrying amount of a long‑lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long‑lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell. We believe the assumptions used in our undiscounted cash flow analysis to test for impairment are appropriate and result in a reasonable estimate of future cash flows. The undiscounted cash flows from the analysis exceeded the carrying amount of our long-lived assets. The most significant assumptions are the pricing and production estimates used in undiscounted cash flow analysis. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation. In order to evaluate the sensitivity of the assumptions, we assumed a hypothetical reduction in our production profile which still showed no impairment. If we experience declines in oil pricing, increases in our estimated future expenditures or a decrease in our estimated production profile our long-lived assets could be at risk for impairment. Derivative Instruments and Hedging Activities We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of collars, put options, call options and swaps. We also use interest rate derivative contracts to mitigate our exposure to interest rate fluctuations related to our long‑term debt. Our derivative financial instruments are recorded on the balance sheet as either assets or liabilities and are measured at fair value. We do not apply hedge accounting to our derivative contracts. As of December 31, 2016 all instruments previously designated as hedges have settled and there is no balance remaining in AOCI. See Note 9—Derivative Financial Instruments. Estimates of Proved Oil and Natural Gas Reserves Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”). The accuracy of these reserve estimates is a function of: • the engineering and geological interpretation of available data; • estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost; • the accuracy of various mandated economic assumptions; and • the judgments of the persons preparing the estimates. Revenue Recognition We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold based on the provisional sales prices. 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 December 31, 2017 and 2016 , we had no oil and gas imbalances recorded in our consolidated financial statements. Our oil and gas revenues are 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. Equity‑based Compensation For equity‑based compensation awards, compensation expense is recognized in the Company’s financial statements over the awards’ vesting periods based on their grant date fair value. The Company utilizes (i) the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards and restricted stock units and (ii) a Monte Carlo simulation to determine the fair value of restricted stock awards and restricted stock units with a combination of market and service vesting criteria. Forfeitures are recognized in the period in which they occur. Treasury Stock We record treasury stock purchases at cost. Our treasury stock purchases are from our employees that surrendered shares to the Company to satisfy their statutory tax withholding requirements and are not part of a formal stock repurchase plan. The remainder of our treasury stock is forfeited restricted stock awards granted under our long‑term incentive plan. Income Taxes The Company accounts for income taxes as required by ASC 740—Income Taxes. Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be sustained upon examination by the tax authorities, based on the technical merits of the position. Accordingly, we measure tax benefits from such positions based on the most likely outcome to be realized. FASB Staff Accounting Bulletin 118 (SAB 118) was issued in January 2018 to address situations where certain aspects of the Tax Reform Act are unclear at issuance of a registrant’s financial statements for the reporting period in which the Tax Reform Act became law. SAB 118 allows us to record provisional amounts during a one year measurement period. We are analyzing certain aspects of the Tax Reform Act which could potentially affect the measurement of deferred tax balances or potentially give rise to new deferred tax amounts. Foreign Currency Translation The U.S. dollar is the functional currency for all of the Company’s material foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are not significant, and as such, the effect of exchange rate changes is not material to any reporting period. Concentration of Credit Risk Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are readily available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of operations. Recent Accounting Standards Recently Adopted In January 2017, the FASB issued ASU 2017-1, "Business Combinations (Topic 805): Clarifying the Definition of a Business." ASU 2017-1 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether those transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years with early adoption permitted. Effective October 1, 2017, we early adopted ASU 2017-1 in connection with our accounting treatment of the Equatorial Guinea acquisition during the fourth quarter of 2017. Not Yet Adopted In May 2014, the FASB issued ASU 2014-9, "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 2014-9 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 2014-9 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-9 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. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-9. The Company completed its assessment of the new accounting standard and does not expect the adoption of this standard to have a material impact to our revenue recognition based on our existing contracts with customers. We will adopt the new standard during the first quarter of 2018 using the modified retrospective approach and there will be no impact to our previously recorded revenue under the new standard. In February 2016, the FASB issued ASU 2016-2, “Leases (Topic 842).” ASU 2016-2 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 the impact of this accounting standard on its consolidated financial statements. In October 2016, the FASB issued ASU 2016-16, “Intra-Entity Transfers of Assets Other Than Inventory.” ASU 2016-16 requires the company to recognize income tax consequences, if any, on intercompany asset transfers, other than inventory, when the transfer occurs. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2017
Acquisitions and Divestitures
Acquisitions and Divestitures	Acquisitions and Divestitures 2017 Transactions In December 2016, we announced transactions with affiliates of BP p.l.c. (‘‘BP’’) in Mauritania and Senegal following a competitive farm-out process for our interests in our blocks offshore Mauritania and Senegal. The Mauritania and Senegal transactions closed in January 2017 and February 2017, respectively. In Mauritania, BP acquired a 62% participating interest in our four Mauritania licenses (C6, C8, C12 and C13). In Senegal, BP acquired a 49.99% interest in KBSL, our majority owned affiliate company which held a 60% participating interest in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") offshore Senegal. Previously we indicated that KBSL would hold a 65% participating interest upon the completion of our exercise in December 2016 of an option to increase our equity in each contract area by 5% in exchange for carrying Timis Corporation Limited’s (“Timis”) paying interest share of a third well in either contract area, subject to a maximum gross well cost of $120.0 million . However, we agreed to withdraw the exercise of this call option upon completion of an agreement between BP and Timis by which BP acquired Timis’ entire 30% participating interest in the Senegal Blocks. The transaction between BP and Timis was completed and KBSL’s participating interest in these blocks remained at 60% . In consideration for these transactions, Kosmos received $162 million in cash up front during the first quarter of 2017 and will receive $228 million exploration and appraisal carry (increased from $221 million upon completion of the transfer of a 30% working interest to BP Senegal Investments Limited), up to $533 million in a development carry and variable consideration up to $2 per barrel for up to 1 billion barrels of liquids, structured as a production royalty, subject to future liquids discovery and prevailing oil prices. The effective date of these transactions was July 1, 2016, with BP paying interim costs from the effective date to the closing dates. We reduced our unproved property balance by $221.9 million for the consideration received as a result of these transactions including the upfront cash and interim costs from the transaction date to the effective date. See Note 7—Equity Method Investments for further discussion of our investment in KBSL. In November 2015, we entered into a line of credit agreement with Timis, whereby Timis had the right to draw up to $30.0 million on the line of credit to offset its joint interest billings arising from costs under the Senegal Blocks petroleum agreements. The line of credit agreement was terminated in April 2017 when Timis entered into an agreement with BP to acquire Timis' 30% participating interest in the Senegal Blocks. As a result of the termination of this credit agreement, Kosmos received $16 million in August 2017 representing payment in full of outstanding amounts drawn on the line of credit. In September 2017, we closed a farm-in agreement with Tullow Mauritania Limited, a subsidiary of Tullow Oil plc (“Tullow”), to acquire a 15% non-operated participating interest in Block C18 offshore Mauritania. Based on the terms of the agreement, we will reimburse a portion of past and interim period costs and partially carry future costs. 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 holds an 85% paying interest ( 80.75% revenue interest) in the Ceiba Field and Okume Complex assets. Under the terms of the agreement, Kosmos and Trident each own 50% of Hess International Petroleum Inc. Hess International Petroleum Inc. 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 post closing entries Kosmos paid net cash of approximately $231 million , with a combination of cash on hand and availability 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, subject to ratification by the President of Equatorial Guinea. We presently have an 80% participating interest and are the operator in all three blocks, but pursuant to an agreement with Trident, we expect to assign a 40% participating interest in the blocks to an affiliate of Trident after ratification. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), currently 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 date of notification of ratification by the President of Equatorial Guinea. The first exploration period consists of two sub-periods of three and two years, respectively. The first exploration sub-period work program includes an approximately 6,000 square kilometer 3D seismic acquisition requirement across the three blocks. Upon ratification and the assignment of a 40% interest to the Trident affiliate noted above, interests in these three blocks will be 40% Kosmos, 40% Trident and 20% GEPetrol. 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. 2016 Transactions In January and February 2016, we closed farm-in agreements with Equator Exploration Limited (“Equator”), an affiliate of Oando Energy Resources, for Block 5 and Block 12 offshore Sao Tome and Principe. As a result of subsequent farm-outs we currently have a 45% participating interest and operatorship in each block. The national petroleum agency, ANP STP, has a 15% and 12.5% carried interest in Block 5 and Block 12, respectively. In April 2016, we closed a farm-out agreement with Hess Suriname Exploration Limited, a wholly-owned subsidiary of the Hess Corporation (“Hess”), covering the Block 42 contract area offshore Suriname. Under the terms of the agreement, Hess acquired a one-third non-operated interest in Block 42 from both Chevron and Kosmos. As part of the agreement, Hess is funding the cost of acquiring and processing a 6,500 square kilometer 3D seismic survey, subject to a maximum spend. Additionally, Hess will disproportionately fund a portion of the first exploration well in the Block 42 contract area, subject to a maximum spend, contingent upon the partnership entering the next phase of the exploration period. The new participating interests are one-third to each of Kosmos, Chevron and Hess, respectively. Kosmos remains the operator. Staatsolie Maatschappij Suriname N.V. (“Staatsolie”), Suriname’s national oil company, has the option to back into the contract with an interest of not more than 10% upon approval of a development plan. In May 2016, Kosmos and Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”) executed a petroleum agreement with the Office National des Hydrocarbures et des Mines ("ONHYM"), the national oil company of the Kingdom of Morocco, for the Boujdour Maritime block. The Boujdour Maritime petroleum agreement largely replaces the acreage covered by the Cap Boujdour petroleum agreement which expired in March 2016. Under the terms of the petroleum agreement, Kosmos is the operator of the Boujdour Maritime block and has a 55% participating interest, Cairn has a 20% participating interest, and ONHYM holds a 25% carried interest in the block through the exploration period. In November 2017, we provided to our co-venturers a notice of withdrawal from the the Boujdour Maritime block offshore Western Sahara and transferred its participating interest and operatorship to ONHYM. Certain transition services are being provided to ONHYM as part of the handover of operatorship. In order to complete our obligations under the petroleum contract, we will continue to fund the remainder of the seismic program. In September 2016, we entered into an agreement by which BP agreed to pay Kosmos $30 million in lieu of drilling an exploration well and assigned its 45% participating interest in the Essaouira Offshore Block back to us, and the Moroccan government issued joint ministerial orders approving the assignment in October 2016, making it effective. After giving effect to the assignment, our participating interest is 75% in the Essaouria Offshore block and we remain the operator. The $30 million payment was received from BP in January 2017. In October 2016, we entered into a petroleum contract covering Block C6 with the Islamic Republic of Mauritania. As a result of a subsequent farm-out we have a 28% participating interest and provide technical exploration services to BP, the operator. The Mauritanian national oil company, Societe Mauritanienne des Hydrocarbures et de Patrimoine Minier (“SMHPM”), currently has a 10% carried participating interest during the exploration period. Block C6 currently comprises approximately 1.1 million acres ( 4,300 square kilometers), with a first exploration period of four years from the effective date (October 28, 2016). The first exploration phase includes a 2,000 square kilometer 3D seismic requirement. In December 2016, Kosmos closed a farm-out agreement with a subsidiary of Galp Energia SGPS S.A. (“Galp”) to farm-out a 20% non-operated stake of the Company’s interest in Blocks 5, 11, and 12 offshore Sao Tome and Principe. Based on the terms of the agreement, Galp paid a proportionate share of Kosmos’ past costs in the form of a partial carry on the 3D seismic survey which was completed in August 2017. 2015 Transactions In March 2015, we closed a farm-in agreement with Repsol Exploracion, S.A. (“Repsol”), acquiring a non-operated interest in the Camarao, Ameijoa, Mexilhao and Ostra blocks in the Peniche Basin offshore Portugal. As part of the agreement, we reimbursed a portion of Repsol’s previously incurred exploration costs, as well as partially carried Repsol’s share of the costs of a planned 3D seismic program. After giving effect to the farm-in agreement, our participating interest was 31% in each of the blocks. In January 2017, we provided to our co-venturers a notice of withdrawal from the Ameijoa, Camarao, Mexilhao and Ostra Blocks offshore Portugal. In March 2015, we closed a farm‑out agreement with Chevron Corporation (“Chevron”) covering the C8, C12 and C13 petroleum contracts offshore Mauritania. As partial consideration for the farm-out, Chevron paid a disproportionate share of the costs of one exploration well, the Marsouin-1 exploration well, as well as its proportionate share of certain previously incurred exploration costs. The final allocation resulted in sales proceeds of $28.7 million , which exceeded our book basis in the assets, resulting in a $24.7 million gain on the transaction. As a further component of the consideration for the farm-out, Chevron was required to make an election by February 1, 2016, to either farm-in to the Tortue-1 exploration well by paying a disproportionate share of the costs incurred in drilling of the well or, alternatively elect to not farm-in to the Tortue-1 exploration well and pay a disproportionate share of the costs of a second contingent exploration or appraisal well in the contract areas, subject to maximum expenditure caps. Chevron failed to make this mandatory election by the required date. Consequently, pursuant to the terms of the farm-out agreement, Chevron has withdrawn from our Mauritania blocks. Chevron’s 30% non-operated participating interest was reassigned to us. In September 2015, we notified the government of Ireland and our partners that we are withdrawing from all of our blocks offshore Ireland. These blocks were acquired during 2013. In October 2015, we closed a sale and purchase agreement with ERHC Energy EEZ, LDA, whereby we acquired an 85% participating interest and operatorship in Block 11 offshore Sao Tome and Principe. The National Petroleum Agency, Agencia Nacional Do Petroleo De Sao Tome E Príncipe (“ANP STP”), has a 15% carried interest. In November 2015, we closed a farm-in agreement with Galp Energia Sao Tome E Principe, Unipessoal, LDA (“Galp”), a wholly owned subsidiary of Petrogal, S.A. to acquire a 45% non-operated participating interest in Block 6 offshore Sao Tome and Principe.

Joint Interest Billings

Joint Interest Billings	12 Months Ended
	Dec. 31, 2017
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 us. 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 December 31, 2017 and 2016 , the current portion of the joint interest billing receivables due from GNPC for the TEN fields development costs were $15.2 million and zero , respectively, and the long-term portion is $31.6 million and $44.0 million .

Property and Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property and Equipment	Property and Equipment Property and equipment is stated at cost and consisted of the following: December 31, 2017 2016 (In thousands) Oil and gas properties: Proved properties $ 1,653,616 $ 1,385,331 Unproved properties 465,109 919,056 Support equipment and facilities 1,427,054 1,386,448 Total oil and gas properties 3,545,779 3,690,835 Accumulated depletion (1,234,806 ) (989,946 ) Oil and gas properties, net 2,310,973 2,700,889 Other property 39,405 37,186 Accumulated depreciation (32,550 ) (29,183 ) Other property, net 6,855 8,003 Property and equipment, net $ 2,317,828 $ 2,708,892 We recorded depletion expense of $244.9 million , $131.5 million and $146.6 million for the years ended December 31, 2017 , 2016 and 2015 , respectively.

Suspended Well Costs

Suspended Well Costs	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Suspended Well Costs	Suspended Well Costs The Company capitalizes exploratory well costs as unproved properties within oil and gas properties until a determination is made that the well has either found proved reserves or is impaired. If proved reserves are found, the capitalized exploratory well costs are reclassified to proved properties. Well costs are charged to exploration expense if the exploratory well is determined to be impaired. The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the years ended December 31, 2017 , 2016 and 2015 . The table excludes $43.2 million , $2.4 million and $70.3 million in costs that were capitalized and subsequently expensed during the same year for the years ended December 31, 2017 , 2016 and 2015 , respectively. During 2017, the exploratory well costs associated with the Mahogany and Teak fields were reclassified to proved property as they were unitized into the Jubilee Unit as part of the Greater Jubilee Full Field Development Plan. Years Ended December 31, 2017 2016 2015 (In thousands) Beginning balance $ 734,463 $ 426,881 $ 226,714 Additions to capitalized exploratory well costs pending the determination of proved reserves 69,567 307,582 223,542 Reclassification due to unitization of Mahogany and Teak discoveries (176,881 ) — — Divestitures(1) (206,400 ) — — Contribution of oil and gas property to equity method investment (131,764 ) — — Dissolution of equity method investment 121,128 — — Capitalized exploratory well costs charged to expense — — (23,375 ) Ending balance $ 410,113 $ 734,463 $ 426,881 ______________________________________ (1) Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal transactions with BP. The following table provides 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: Years Ended December 31, 2017 2016 2015 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 67,159 $ 279,809 $ 199,486 Exploratory well costs capitalized for a period of one to two years 291,252 244,804 17,702 Exploratory well costs capitalized for a period of three to six years 51,702 209,850 209,693 Ending balance $ 410,113 $ 734,463 $ 426,881 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 5 5 3 As of December 31, 2017 , 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 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 Teranga discovery 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. Wawa Discovery — In February 2016, we requested the Ghana Ministry of Energy to approve the enlargement of the areal extent of the TEN fields and production area to capture the resource accumulation located in the Wawa Discovery Area for a potential future integrated development with the TEN fields. In April 2016, the Ghana Ministry of Energy approved our request to enlarge the TEN development and production area subject to continued subsurface and development concept evaluation, along with the requirement to integrate the Wawa Discovery into the TEN PoD. We are currently in discussions with the Ministry of Energy with respect to conducting further subsurface and development concept evaluation. 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 is being 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. Teranga Discovery — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality will be made.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Equity Method Investments Kosmos BP Senegal Limited As part of our transaction in Senegal with BP, our petroleum contracts in Senegal were contributed to KBSL, a corporate joint venture in which we owned a 50.01% interest. The objective of this transaction was to accelerate the development of discovered gas resources, ensure the execution of an appropriately sized exploration program and reduce the Company’s capital spending requirements for exploration and development over the near to medium term. In October 2017, upon approval, KBSL transferred a 30% working interest in the Senegal Blocks to BP Senegal Investments Limited in exchange for their outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and will no longer be accounted for under the equity method of accounting. After the transfer, KBSL has a 30% working interest in the Senegal Blocks. Prior to the acquisition of the remaining outstanding shares of KBSL in October 2017, our investment in KBSL qualified for the equity method of accounting. Our initial contribution to KBSL was $133.9 million , which was recorded at our carrying costs. Our share of the KBSL operations during the period it was accounted for as an equity method investment is reflected in our consolidated statements of operations as loss on equity method investments, net. During the twelve months ended December 31, 2017, we recorded an $11.5 million loss on equity method investment associated with KBSL. Equatorial Guinea As part of our acquisition of KTIPI, a corporate joint venture in which we own a 50% interest, we acquired the petroleum contract for 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. December 31, 2017 (In thousands) Assets Total current assets $ 179,070 Property and equipment, net 345,611 Other assets 567 Total assets $ 525,248 Liabilities and shareholders' equity Total current liabilities $ 106,769 Total long term liabilities 565,591 Shareholders' equity: Total shareholders' equity (147,112 ) Total liabilities and shareholders' equity $ 525,248 Period November 28, 2017 through December 31, 2017 Revenues and other income: Oil and gas revenue $ 54,615 Other income 294 Total revenues and other income 54,909 Costs and expenses: Oil and gas production 15,509 Depletion and depreciation 10,738 Other expenses, net (19 ) Total costs and expenses 26,228 Income before income taxes 28,681 Income tax expense 6,588 Net income $ 22,093 Kosmos' share of net income $ 11,046 Basis difference amortization(1) 5,812 Equity in earnings - KTIPI $ 5,234 ______________________________________ (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 December 31, 2017, 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.

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	Debt December 31, 2017 2016 (In thousands) Outstanding debt principal balances: Facility $ 800,000 $ 850,000 Senior Notes 525,000 525,000 Total 1,325,000 1,375,000 Unamortized deferred financing costs and discounts(1) (42,203 ) (53,126 ) Long-term debt, net $ 1,282,797 $ 1,321,874 ________________________________________ (1) Includes $23.6 million and $30.3 million of unamortized deferred financing costs related to the Facility and $18.6 million and $22.8 million of unamortized deferred financing costs and discounts related to the Senior Notes as of December 31, 2017 and December 31, 2016 , respectively. Facility In March 2017, following the lender’s semi-annual redetermination, the available borrowing base under our Facility was $1.3 billion (effective April 1, 2017). In August 2017, following the lender’s waiver of the September 30, 2017 semi-annual redetermination, the available borrowing base under our Facility remained at $1.3 billion . The borrowing base calculation included value related to the Jubilee and TEN fields. As of December 31, 2017 , borrowings under the Facility totaled $800.0 million including $200 million drawn for the KTIPI investment, and the undrawn availability under the Facility was $500.8 million . Interest is the aggregate of the applicable margin ( 3.25% to 4.50% , depending on the length of time that has passed from the date the Facility was entered into) and LIBOR . Interest is payable on the last day of each interest period (and, if the interest period is longer than six months , on the dates falling at six-month intervals after the first day of the interest period). We pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. Commitment fees were equal to 40% per annum of the then-applicable respective margin when a commitment is available for utilization and, equal to 20% per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835—Interest, which requires interest expense to be recognized using the effective interest method. We determined the effective interest rate based on the estimated level of borrowings under the 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. 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 $5.7 million of existing unamortized debt issuance costs attributable to those participants were expensed in the first quarter of 2018. As of December 31, 2017 , we have $23.6 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility, excluding the $5.7 million expensed in the first quarter of 2018. 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 December 31, 2017 , we had no letters of credit issued under the Facility. Kosmos has the right to cancel all the undrawn commitments under the amended and restated Facility. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined each year on March 31. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in Ghana and Equatorial Guinea. If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. The Facility contains customary cross default provisions. We were in compliance with the financial covenants contained in the Facility as of the September 30, 2017 (the most recent assessment date). Corporate Revolver In November 2012, we secured a Corporate Revolver from a number of financial institutions which, as amended in June 2015, has an availability of $400.0 million . The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration; appraisal and development programs. As of December 31, 2017 , we have $2.5 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term, which as amended expires in November 2018. These deferred financing costs are included in the Other assets section of the consolidated balance sheet. As of December 31, 2017 , there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400.0 million . Interest is the aggregate of the applicable margin ( 6.0% ); LIBOR ; and mandatory cost (if any, as defined in the Corporate Revolver). Interest is payable on the last day of each interest period (and, if the interest period is longer than six months , on the dates falling at six‑month intervals after the first day of the interest period). We pay commitment fees on the undrawn portion of the total commitments. Commitment fees, as amended in June 2015, for the lenders are equal to 30% per annum of the respective margin when a commitment is available for utilization. The Corporate Revolver, as amended in June 2015, expires on November 23, 2018. The available amount is not subject to borrowing base constraints. Kosmos has the right to cancel all the undrawn commitments under the Corporate Revolver. The Company is required to repay certain amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default exists under the Corporate Revolver, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us. We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2017 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions. Revolving Letter of Credit Facility In July 2013, we entered into a revolving letter of credit facility agreement (“LC Facility”). The size of the LC Facility is $75.0 million , as amended in July 2015, with additional commitments up to $50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. The LC Facility provides that we maintain cash collateral in an amount equal to at least 75% of all outstanding letters of credit under the LC Facility, provided that during the period of any breach of certain financial covenants, the required cash collateral amount shall increase to 100% . In July 2016, we amended and restated the LC Facility, extending the maturity date to July 2019. Other amendments included increasing the margin from 0.5% to 0.8% per annum on amounts outstanding, adding a commitment fee payable quarterly in arrears at an annual rate equal to 0.65% on the available commitment amount and providing for issuance fees to be payable to the lender per new issuance of a letter of credit. We may voluntarily cancel any commitments available under the LC Facility at any time. During the first quarter of 2017, the LC Facility size was increased to $115.0 million and in April 2017, we reduced the size of our LC Facility to $70 million . In February 2018, the LC Facility was increased to $73 million to facilitate the issuance of additional letters of credit . As of December 31, 2017 , there were eight outstanding letters of credit totaling $60.3 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 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 (the “Guarantees”). Redemption and Repurchase . On or after August 1, 2017, the Company may redeem all or a part of the Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest: Year Percentage On or after August 1, 2017, but before August 1, 2018 103.9 % On or after August 1, 2018, but before August 1, 2019 102.0 % On or after August 1, 2019 and thereafter 100.0 % We may also redeem the Senior Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the Senior Notes at a price equal to the principal amount of the Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted. Upon the occurrence of a change of control triggering event as defined under the Indenture, the Company will be required to make an offer to repurchase the Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase. If we sell assets, under certain circumstances outlined in the Indenture, we will be required to use the net proceeds to make an offer to purchase the Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date. Covenants. The Indenture restricts our ability and the ability of our restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of our subsidiaries to make dividends or other payments to us, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing. Collateral. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all currently outstanding shares, additional shares, dividends or other distributions paid in respect of such shares or any other property derived from such shares, in each case held by us in relation to the Company’s direct subsidiary, Kosmos Energy Holdings, pursuant to the terms of the Charge over Shares of Kosmos Energy Holdings dated November 23, 2012, as amended and restated on March 14, 2014, between the Company and BNP Paribas as Security and Intercreditor Agent. The Senior Notes share pari passu in the benefit of such equitable charge based on the respective amounts of the obligations under the Indenture and the amount of obligations under the Corporate Revolver. The Guarantees are not secured. At December 31, 2017 , the estimated repayments of debt during the five years and thereafter are as follows: Payments Due by Year Total 2018 2019 2020 2021 2022 Thereafter (In thousands) Principal debt repayments(1) $ 1,325,000 $ — $ 200,377 $ 404,971 $ 719,652 $ — $ — (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 the level of borrowings and the estimated future available borrowing base as of December 31, 2017 . 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 December 31, 2017 , there were no borrowings under the Corporate Revolver. Interest and other financing costs, net Interest and other financing costs, net incurred during the period comprised of the following: Years Ended December 31, 2017 2016 2015 (In thousands) Interest expense $ 92,687 $ 89,029 $ 74,897 Amortization—deferred financing costs 10,204 10,204 10,324 Loss on extinguishment of debt — — 165 Capitalized interest (30,282 ) (59,803 ) (52,392 ) Deferred interest 2,577 (581 ) 1,770 Interest income (3,422 ) (1,954 ) (844 ) Other, net 5,831 7,252 3,289 Interest and other financing costs, net $ 77,595 $ 44,147 $ 37,209

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2017
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 nonperformance 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 December 31, 2017 . Volumes are net of any offsetting derivative contracts entered into. Weighted Average Dated Brent Price per Bbl Term Type of Contract MBbl Net Deferred Premium Payable Swap Sold Put Floor Ceiling Call 2018: January — December Swap with puts 2,000 $ — $ 54.32 $ 40.00 $ — $ — $ — July — December Swap with puts 2,000 — 57.96 45.00 — — — January — June Swaps 1,000 — 57.25 — — — — January — December Three-way collars 2,913 0.74 — 41.57 56.57 65.90 — January — December Four-way collars 3,000 1.06 — 40.00 50.00 61.33 70.00 January — December Sold calls(1) 2,000 — — — — 65.00 — 2019: January — December Three-way collars 6,500 $ 0.18 $ — $ 41.54 $ 51.54 $ 63.80 $ — January — December Two-way collars 2,000 1.62 — — 55.00 65.00 — January — December Sold calls(1) 913 — — — — 80.00 — ______________________________________ (1) Represents call option contracts sold to counterparties to enhance other derivative positions. In January 2018, we entered into three-way costless collar contracts for 1.0 MMBbl from January 2019 through December 2019 with a sold put price of $45.00 , a floor price of $55.00 per barrel and a ceiling price of $72.90 per barrel. The contracts are indexed to Dated Brent prices. In February 2018, we sold 2.0 MMBbl of put contracts from January 2019 through December 2019 with a strike of $47.50 per barrel. We used part of the proceeds to increase our upside exposure by purchasing 1.0 MMBbl of calls in the second half of 2018 with a strike of $70.00 per barrel. These contracts are indexed to Dated Brent prices and have a net deferred premium receivable of $3.1 million . 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 December 31, 2017 : Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) January 2018 — December 2018 Capped swap 1-month LIBOR $ 200,000 1.23 % 3.00 % See Note 10—Fair Value Measurements for additional information regarding the Company’s derivative instruments. The following tables disclose the Company’s derivative instruments as of December 31, 2017 and 2016 and gain/(loss) from derivatives during the years ended December 31, 2017 , 2016 and 2015 . Estimated Fair Value Asset (Liability) December 31, Type of Contract Balance Sheet Location 2017 2016 (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ 665 $ 31,698 Interest rate Derivatives assets—current 1,017 — Commodity(2) Derivatives assets—long-term 39 3,226 Interest rate Derivatives assets—long-term — 582 Derivative liabilities: Commodity(3) Derivatives liabilities—current (67,531 ) (19,163 ) Interest rate Derivatives liabilities—current — (529 ) Commodity(4) Derivatives liabilities—long-term (30,209 ) (14,123 ) Total derivatives not designated as hedging instruments $ (96,019 ) $ 1,691 ______________________________________ (1) Includes net deferred premiums receivable of $0.8 million and net deferred premiums payable of $3.9 million related to commodity derivative contracts as of December 31, 2017 and 2016 , respectively. (2) Includes net deferred premiums receivable of $0.1 million and net deferred premiums payable of $2.5 million related to commodity derivative contracts as of December 31, 2017 and 2016 , respectively. (3) Includes zero and $30.9 thousand as of December 31, 2017 and December 31, 2016 , respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of $5.6 million and $6.2 million related to commodity derivative contracts as of December 31, 2017 and 2016 , respectively. (4) Includes net deferred premiums payable of $4.8 million and $0.6 million related to commodity derivative contracts as of December 31, 2017 and 2016 , respectively. Amount of Gain/(Loss) Years Ended December 31, Type of Contract Location of Gain/(Loss) 2017 2016 2015 (In thousands) Derivatives in cash flow hedging relationships: Interest rate(1) Interest expense $ — $ — $ 767 Total derivatives in cash flow hedging relationships $ — $ — $ 767 Derivatives not designated as hedging instruments: Commodity(2) Oil and gas revenue $ (12,502 ) $ 2,538 $ 3 Commodity Derivatives, net (59,968 ) (48,021 ) 210,649 Interest rate Interest expense 648 (1,076 ) (462 ) Total derivatives not designated as hedging instruments $ (71,822 ) $ (46,559 ) $ 210,190 ______________________________________ (1) Amounts were reclassified from AOCI into earnings upon settlement. (2) 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 December 31, 2017 and 2016 , 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	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements In accordance with ASC 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 December 31, 2017 and 2016 , for each fair value hierarchy level: Fair Value Measurements Using: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) December 31, 2017 Assets: Commodity derivatives $ — $ 704 $ — $ 704 Interest rate derivatives — 1,017 — 1,017 Liabilities: Commodity derivatives — (97,740 ) — (97,740 ) Interest rate derivatives — — — — Total $ — $ (96,019 ) $ — $ (96,019 ) December 31, 2016 Assets: Commodity derivatives $ — $ 34,924 $ — $ 34,924 Interest rate derivatives — 582 — 582 Liabilities: Commodity derivatives — (33,286 ) — (33,286 ) Interest rate derivatives — (529 ) — (529 ) Total $ — $ 1,691 $ — $ 1,691 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 the provisional oil sales derivative 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 We enter into interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR‑based rate. We also enter into 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 December 31, 2017 and 2016 : December 31, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 507,600 $ 542,472 $ 503,716 $ 528,938 Facility 800,000 800,000 850,000 850,000 Total $ 1,307,600 $ 1,342,472 $ 1,353,716 $ 1,378,938 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.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The following table summarizes the changes in the Company’s asset retirement obligations: December 31, 2017 2016 (In thousands) Asset retirement obligations: Beginning asset retirement obligations $ 63,574 $ 43,938 Liabilities incurred during period — 14,235 Revisions in estimated retirement obligations (3,945 ) — Accretion expense 6,966 5,401 Ending asset retirement obligations $ 66,595 $ 63,574 The Ghanaian legal and regulatory regime regarding oil field abandonment and other environmental matters is evolving. Currently, no Ghanaian environmental regulations expressly require that companies abandon or remove offshore assets. Under the Environmental Permit for the Jubilee Field, a decommissioning plan will be prepared and submitted to the Ghana Environmental Protection Agency. ASC 410—Asset Retirement and Environmental Obligations requires the Company to recognize this liability in the period in which the liability was incurred. The TEN fields commenced production during the third quarter of 2016 and an asset retirement obligation was recorded for the facilities and wells that came online during 2016. Additional asset retirement obligations will be recorded in the period in which additional wells within our producing fields are commissioned.

Equity-based Compensation

Equity-based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-based Compensation	Equity‑based Compensation Restricted Stock Awards and Restricted Stock Units Prior to our corporate reorganization in May 2011, Kosmos Energy Holdings issued common units designated as profit units with a threshold value ranging from $0.85 to $90 to employees, management and directors. Profit units were equity awards that were measured on the grant date and expensed over a vesting period of four years . Founding management and directors vested 20% as of the date of issuance and an additional 20% on the anniversary date for each of the next four years. Profit units issued to employees vested 50% on the second and fourth anniversaries of the issuance date. As part of the corporate reorganization in May 2011, vested profit units were exchanged for 31.7 million common shares of Kosmos Energy Ltd., unvested profit units were exchanged for 10.0 million restricted stock awards and the $90 profit units were cancelled. These restricted stock awards ultimately vested during 2015. Based on the terms and conditions of the corporate reorganization, the exchange of profit units for common shares of Kosmos Energy Ltd. resulted in no incremental compensation costs. In April 2011, the Board of Directors approved the LTIP, which provides for the granting of incentive awards in the form of stock options, stock appreciation rights, restricted stock awards, restricted stock units, among other award types. In January 2015, the board of directors approved an amendment to the plan to add 15.0 million shares to the plan which was approved at the Annual General Meeting in June 2015. The LTIP provides for the issuance of 39.5 million shares pursuant to awards under the plan, in addition to the 10.0 million restricted stock awards exchanged for unvested profit units. As of December 31, 2017 , the Company had approximately 3.4 million shares that remain available for issuance under the LTIP. The Company adopted ASU 2016-9, “Improvements to Employee Share-based Payment Accounting” during the second quarter of 2016 using an effective date of January 1, 2016. Prior period compensation expense disclosed below includes estimated forfeitures and has not been adjusted. We record equity-based compensation expense equal to the fair value of share‑based payments over the vesting periods of the LTIP awards. We recorded compensation expense from awards granted under our LTIP of $40.0 million , $40.1 million and $75.1 million during the years ended December 31, 2017 , 2016 and 2015 , respectively. The total tax benefit for the years ended December 31, 2017 , 2016 and 2015 was $13.2 million , $13.0 million and $25.7 million , respectively. Additionally, we expensed a tax shortfall related to equity‑based compensation of $3.1 million , $5.5 million and $18.6 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The fair value of awards vested during 2017 , 2016 and 2015 was approximately $21.2 million , $14.4 million , and $52.2 million , 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 of 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 December 31, 2017 : Service Vesting Restricted Stock Awards Weighted- Average Grant-Date Fair Value Market / Service Vesting Restricted Stock Awards Weighted- Average Grant-Date Fair Value (In thousands) (In thousands) Outstanding at December 31, 2014: 3,240 $ 16.95 3,361 $ 13.00 Granted 660 8.64 — — Forfeited (2 ) 12.84 (1,554 ) 13.29 Vested (3,088 ) 17.21 (1,546 ) 13.30 Outstanding at December 31, 2015: 810 9.20 261 9.44 Granted — — — — Forfeited — — (162 ) 9.44 Vested (322 ) 9.77 (99 ) 9.44 Outstanding at December 31, 2016: 488 8.83 — — Granted — — — — Forfeited — — — — Vested (268 ) 8.97 — — Outstanding at December 31, 2017: 220 8.64 — — The following table reflects the outstanding restricted stock units as of December 31, 2017 : Service Vesting Restricted Stock Units Weighted- Average Grant-Date Fair Value Market / Service Vesting Restricted Stock Units Weighted-Average Grant-Date Fair Value (In thousands) (In thousands) Outstanding at December 31, 2014: 3,367 $ 10.76 3,246 $ 15.66 Granted 1,539 8.37 3,544 12.96 Forfeited (254 ) 10.14 (212 ) 14.48 Vested (1,060 ) 10.71 — — Outstanding at December 31, 2015: 3,592 9.79 6,578 14.24 Granted 2,158 4.05 1,379 4.88 Forfeited (134 ) 8.87 (70 ) 14.49 Vested (1,456 ) 9.61 (693 ) 15.81 Outstanding at December 31, 2016: 4,160 6.91 7,194 12.29 Granted 2,085 6.43 2,175 9.50 Forfeited (137 ) 6.91 (21 ) 6.21 Vested (1,925 ) 7.51 (896 ) 15.43 Outstanding at December 31, 2017: 4,183 6.39 8,452 11.26 As of December 31, 2017 , total equity‑based compensation to be recognized on unvested restricted stock awards and restricted stock units is $23.6 million over a weighted average period of 1.5 years . For restricted stock awards and 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 up to 100% of the awards granted for restricted stock awards and up to 200% of the awards granted for restricted stock units. The grant date fair value of these awards ranged from $6.70 to $13.57 per award for restricted stock awards and $4.83 to $15.81 per award for restricted stock units. 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 41.3% to 56.7% for restricted stock awards and 44.0% to 54.0% for restricted stock units. The risk‑free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant was 0.5% for restricted stock awards and and ranged from 0.5% to 1.4% for restricted stock units. For profit units that were exchanged for restricted stock awards, the significant assumptions used to calculate the fair values of the profit units granted as calculated using a binomial tree, were as follows: no dividend yield, expected volatility ranging from approximately 25% to 66% ; risk‑free interest rate ranging from 1.3% to 5.1% ; expected life ranging from 1.2 to 8.1 years ; and projected turnover rates ranging from 7.0% to 27.0% for employees and none for management. For profit units granted immediately prior to our initial public offering, we utilized the midpoint of the range of the estimated offering price, or $17.00 per share. In January 2018 , we granted 1.8 million service vesting restricted stock units and 2.3 million market and service vesting restricted stock units to our employees under our long-term incentive plan. We expect to recognize approximately $34.3 million of non-cash compensation expense related to these grants over the next three years .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Kosmos Energy Ltd. is a Bermuda company that is not subject to taxation at the corporate level. We provide for income taxes based on the laws and rates in effect in the countries in which our operations are conducted. The relationship between our pre‑tax income or loss from continuing operations and our income tax expense or benefit varies from period to period as a result of various factors which include changes in total pre‑tax income or loss, the jurisdictions in which our income (loss) is earned and the tax laws in those jurisdictions. On December 22, 2017, the President of the United States signed P.L. 115-97, the Tax Cut and Jobs Act (the Tax Reform Act), into law. Many of the provisions of the Tax Reform Act are effective beginning January 1, 2018, most notable of which is the reduction in the U.S. corporate income tax rate from 35% to 21%. Accounting Standards Codification Topic 740 requires deferred tax assets and liabilities be adjusted for the effect of changes in tax laws or tax rates during the period that includes the date of enactment. Accordingly, we have recorded a $16.7 million charge to deferred tax expense in December 2017 as a result of reducing our net deferred tax assets. The components of income (loss) before income taxes were as follows: Years Ended December 31, 2017 2016 2015 (In thousands) Bermuda $ (66,914 ) $ (63,749 ) $ (62,372 ) United States 6,068 5,083 10,652 Foreign—other (117,009 ) (235,898 ) 137,156 Income (loss) before income taxes $ (177,855 ) $ (294,564 ) $ 85,436 The components of the provision for income taxes attributable to our income (loss) before income taxes consist of the following: Years Ended December 31, 2017 2016 2015 (In thousands) Current: Bermuda $ — $ — $ — United States 10,976 12,675 15,199 Foreign—other 24,456 102 29,287 Total current 35,432 12,777 44,486 Deferred: Bermuda — — — United States 15,310 (3,594 ) 8,241 Foreign—other (5,805 ) (19,967 ) 102,545 Total deferred 9,505 (23,561 ) 110,786 Income tax expense (benefit) $ 44,937 $ (10,784 ) $ 155,272 Our reconciliation of income tax expense (benefit) computed by applying our Bermuda statutory rate and the reported effective tax rate on income (loss) from continuing operations is as follows: Years Ended December 31, 2017 2016 2015 (In thousands) Tax at Bermuda statutory rate $ — $ — $ — Foreign income (loss) taxed at different rates (1,978 ) (57,898 ) 94,184 Change in valuation allowance and the expiration of fully valued deferred tax assets 6,008 29,263 40,600 Non-deductible and other items(1) 21,100 12,347 1,885 Tax shortfall on equity-based compensation 3,086 5,504 18,603 Change in U.S. tax rate 16,721 — — Total tax expense (benefit) $ 44,937 $ (10,784 ) $ 155,272 Effective tax rate(2) 25 % 4 % 182 % ______________________________________ (1) Includes $5.0 million of tax expense related to the expiration of a Moroccan tax loss carryforward; $4.7 million of tax related interest expense incurred in 2017; and other various items. (2) The effective tax rate during the years ended December 31, 2017 , 2016 and 2015 were impacted by losses of $164.4 million , $121.4 million and $153.5 million , respectively, incurred in jurisdictions in which we are not subject to taxes and therefore do not generate any income tax benefits. The effective tax rate for the United States is approximately 433% , 179% and 220% for the years ended December 31, 2017 , 2016 and 2015 , respectively. The effective tax rate in the United States is impacted by the effect of writing-down our deferred tax assets as a result of the change in tax rate under the Act and the sum of equity-based compensation tax shortfalls and tax windfalls equal to the difference between the income tax benefit recognized for financial statement reporting purposes compared to the income tax benefit realized for tax return purposes. The effective tax rate for Ghana is approximately 49% , 23% and 35% for the years ended December 31, 2017 , 2016 and 2015 , respectively. The effective tax rate in Ghana is impacted by non-deductible expenditures, including amounts associated with the damage to the turret bearing, which we expect to recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax. 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. Deferred tax assets and liabilities, which are computed on the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities, are determined using the tax rates expected to be in effect when taxes are actually paid or recovered. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows: December 31, 2017 2016 (In thousands) Deferred tax assets: Foreign capitalized operating expenses $ 68,218 $ 69,804 Foreign net operating losses 25,307 36,352 Equity compensation 20,783 30,752 Unrealized derivative losses 33,963 — Asset retirement obligation and other 24,784 33,744 Total deferred tax assets 173,055 170,652 Valuation allowance (93,525 ) (87,517 ) Total deferred tax assets, net 79,530 83,135 Deferred tax liabilities: Depletion, depreciation and amortization related to property and equipment (533,561 ) (526,945 ) Unrealized derivative gains — (584 ) Total deferred tax liabilities (533,561 ) (527,529 ) Net deferred tax liability $ (454,031 ) $ (444,394 ) The Company has recorded a full valuation allowance against the net deferred tax assets in countries where we only have exploration operations. The Company has foreign net operating loss carryforwards of $94.1 million . Of these losses, we expect $0.9 million , $0.5 million , $0.5 million , $0.6 million , $0.7 million and $15.0 million to expire in 2019, 2020, 2021, 2022, 2023 and 2029, respectively, and $75.9 million do not expire. All of these losses currently have offsetting valuation allowances. A subsidiary of the Company files a U.S. federal income tax return and a Texas margin tax return. The Company is open to U.S. federal income tax examinations for tax years 2014 through 2017 and to Texas margin tax examinations for the tax years 2011 through 2017. In addition to the United States, the Company files income tax returns in the countries in which we operate. The Company is open to income tax examinations for years 2014 through 2017 in its significant other foreign jurisdictions, primarily Ghana. As of December 31, 2017 , 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 Income (Loss) Per Share

Net Income (Loss) Per Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Net Income (Loss) Per Share	Net Income (Loss) Per Share In the calculation of basic net income per share, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income, if any. We calculate basic net income per share under the two‑class method. Diluted net income (loss) per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. The computation of diluted net income (loss) per share reflects the potential dilution that could occur if all outstanding awards under our LTIP were converted into common shares or resulted in the issuance of common shares that would then share in the earnings of the Company. During periods in which the Company realizes a loss from continuing operations securities would not be dilutive to net loss per share and conversion into common shares is assumed not to occur. Basic net income (loss) per share is computed as (i) net income (loss), (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. The Company’s diluted net income (loss) per share is computed as (i) basic net income (loss), (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. Years Ended December 31, 2017 2016 2015 (In thousands, except per share data) Numerator: Net loss (222,792 ) (283,780 ) $ (69,836 ) Basic income allocable to participating securities(1) — — — Basic net loss allocable to common shareholders (222,792 ) (283,780 ) (69,836 ) Diluted adjustments to income allocable to participating securities(1) — — — Diluted net loss allocable to common shareholders (222,792 ) (283,780 ) $ (69,836 ) Denominator: Weighted average number of shares outstanding: Basic 388,375 385,402 382,610 Restricted stock awards and units(1)(2) — — — Diluted 388,375 385,402 382,610 Net loss per share: Basic $ (0.57 ) $ (0.74 ) $ (0.18 ) Diluted $ (0.57 ) $ (0.74 ) $ (0.18 ) ______________________________________ (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 income (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 income (loss) per common share calculation in periods we are in a net loss position. (2) For the years ended December 31, 2017 , 2016 and 2015 , we excluded 12.9 million , 11.8 million and 11.2 million outstanding restricted stock awards and restricted stock units, respectively, from the computations of diluted net income per share because the effect would have been anti‑dilutive.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
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. The Jubilee Field in Ghana covers an area within both the WCTP and DT petroleum contract areas. It was agreed the Jubilee Field would be unitized for optimal resource recovery. Kosmos and its partners executed a comprehensive unitization and unit operating agreement, the Jubilee UUOA, to unitize the Jubilee Field and govern each party’s respective rights and duties in the Jubilee Unit, which was effective July 16, 2009. Pursuant to the terms of the Jubilee UUOA, the tract participations are subject to a process of redetermination. The initial redetermination process was completed on October 14, 2011. As a result of the initial redetermination process, our Unit Interest is 24.1% . These consolidated financial statements are based on these re determined tract participations. Our unit interest may change in the future should another redetermination occur. The Company leases facilities under various operating leases that expire through 2027, including our office space. Rent expense under these agreements, was $3.3 million , $3.3 million and $4.7 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. We currently have a commitment to drill one exploration well in Mauritania. In Mauritania, our partner is obligated to fund our share of the cost of the exploration well, subject to their maximum $228 million cumulative exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Equatorial Guinea, Mauritania and Cote d'Ivoire, we have 3D seismic requirements of approximately 6,000 square kilometers, 7,600 square kilometers and 12,000 square kilometers, respectively. The Equatorial Guinea exploration block commitments are subject to ratification by the President of Equatorial Guinea. In November 2017, we entered into a one well drilling rig contract for the ENSCO DS-12 plus six well options. We have completed the initial well and have exercised one of the six option wells to be drilled in 2018. Future minimum rental commitments under our leases at December 31, 2017 , are as follows: Payments Due By Year(1) Total 2018 2019 2020 2021 2022 Thereafter (In thousands) Operating leases(2) $ 12,626 $ 4,981 $ 4,370 $ 484 $ 419 $ 418 $ 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) Primarily relates to corporate office and foreign office leases.

Additional Financial Informatio

Additional Financial Information	12 Months Ended
	Dec. 31, 2017
Additional Financial Information
Additional Financial Information	Additional Financial Information Accrued Liabilities Accrued liabilities consisted of the following: December 31, 2017 2016 (In thousands) Accrued liabilities: Exploration, development and production $ 144,717 $ 76,194 General and administrative expenses 31,124 31,243 Interest 20,457 17,247 Income taxes 17,423 2,579 Taxes other than income 3,270 1,914 Other 2,421 529 $ 219,412 $ 129,706 Other Income, net Other income, net consisted of $58.7 million , $74.8 million and zero of Loss of Production Income (“LOPI”) proceeds related to the turret bearing issue on the Jubilee FPSO for the years ended December 31, 2017 , 2016 and 2015 . 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 $17.1 million , $7.5 million , and zero for the years ended December 31, 2017 , 2016 and 2015 , respectively. Facilities Insurance Modifications, net Facilities insurance modifications consist of costs associated with the long-term solution to convert the FPSO to a permanently spread moored facility which we expect to recover from our insurance policy. Any insurance reimbursement of these costs is also be recorded to this line. Other Expenses, net Other expenses, net incurred during the period is comprised of the following: Years Ended December 31, 2017 2016 2015 (In thousands) Inventory write-off $ 866 $ 14,900 $ 36 (Gain) loss on insurance settlements (461 ) (4,003 ) 4,151 Disputed charges and related costs 4,962 11,299 — Other, net (76 ) 920 1,059 Other expenses, net $ 5,291 $ 23,116 $ 5,246 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 disputes that these expenditures are 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.

Supplemental Quarterly Financia

Supplemental Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Financial Information (Unaudited)	Supplemental Quarterly Financial Information (Unaudited) Quarter Ended March 31, June 30, September 30, December 31, (In thousands, except per share data) 2017 Revenues and other income $ 151,966 $ 146,524 $ 151,242 $ 187,104 Costs and expenses 158,630 131,252 216,162 308,647 Net loss (28,841 ) (8,467 ) (63,405 ) (122,079 ) Net loss per share: Basic(1) (0.07 ) (0.02 ) (0.16 ) (0.31 ) Diluted(1) (0.07 ) (0.02 ) (0.16 ) (0.31 ) 2016 Revenues and other income $ 62,133 $ 45,676 $ 66,629 $ 210,917 Costs and expenses 123,148 169,544 118,890 268,337 Net loss (58,993 ) (108,324 ) (59,763 ) (56,700 ) Net loss per share: Basic(1) (0.15 ) (0.28 ) (0.15 ) (0.15 ) Diluted(1) (0.15 ) (0.28 ) (0.15 ) (0.15 ) ______________________________________ (1) The sum of the quarterly earnings per share information may not add to the annual earnings per share information as a result of rounding.

Schedule I - Condensed Parent C

Schedule I - Condensed Parent Company Financial Statements	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule I - Condensed Parent Company Financial Statements	Schedule I—Condensed Parent Company Financial Statements Under the terms of agreements governing the indebtedness of subsidiaries of Kosmos Energy Ltd. for 2017 , 2016 and 2015 (collectively “KEL,” the “Parent Company”), such subsidiaries are restricted from making dividend payments, loans or advances to KEL. Schedule I of Article 5‑04 of Regulation S‑X requires the condensed financial information of the Parent Company to be filed when the restricted net assets of consolidated subsidiaries exceed 25 percent of consolidated net assets as of the end of the most recently completed fiscal year. The following condensed parent‑only financial statements of KEL have been prepared in accordance with Rule 12‑04, Schedule I of Regulation S‑X and included herein. The Parent Company’s 100% investment in its subsidiaries has been recorded using the equity basis of accounting in the accompanying condensed parent‑only financial statements. The condensed financial statements should be read in conjunction with the consolidated financial statements of Kosmos Energy Ltd. and subsidiaries and notes thereto. The terms “Kosmos,” the “Company,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise. Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or shareholders equity. KOSMOS ENERGY LTD. CONDENSED PARENT COMPANY BALANCE SHEETS (In thousands, except share data) December 31, 2017 2016 Assets Current assets: Cash and cash equivalents $ 297 $ 1,092 Receivables from subsidiaries — 14,131 Prepaid expenses and other 290 417 Total current assets 587 15,640 Investment in subsidiaries at equity 1,419,890 1,580,459 Deferred financing costs, net of accumulated amortization of $13,951 and $11,213 at December 31, 2017 and December 31, 2016, respectively 2,510 5,248 Total assets $ 1,422,987 $ 1,601,347 Liabilities and shareholders’ equity Current liabilities: Accounts payable $ 4 $ 13 Accounts payable to subsidiaries 332 — Accrued liabilities 19,128 17,939 Total current liabilities 19,464 17,952 Long-term debt 506,411 502,196 Shareholders’ equity: Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2017 and December 31, 2016 — — Common shares, $0.01 par value; 2,000,000,000 authorized shares; 398,599,457 and 395,859,061 issued at December 31, 2017 and December 31, 2016, respectively 3,986 3,959 Additional paid-in capital 2,014,525 1,975,247 Accumulated deficit (1,073,202 ) (850,410 ) Treasury stock, at cost, 9,188,819 and 9,101,395 shares at December 31, 2017 and December 31, 2016, respectively (48,197 ) (47,597 ) Total shareholders’ equity 897,112 1,081,199 Total liabilities and shareholders’ equity $ 1,422,987 $ 1,601,347 CONDENSED PARENT COMPANY STATEMENTS OF OPERATIONS (In thousands) Years Ended December 31, 2017 2016 2015 Revenues and other income: Oil and gas revenue $ — $ — $ — Total revenues and other income — — — Costs and expenses: General and administrative 51,544 48,542 85,103 General and administrative recoveries—related party (40,266 ) (40,047 ) (72,543 ) Interest and other financing costs, net 55,596 55,253 49,572 Other expenses, net 40 1 240 Equity in losses of subsidiaries 155,878 220,031 7,464 Total costs and expenses 222,792 283,780 69,836 Loss before income taxes (222,792 ) (283,780 ) (69,836 ) Income tax expense — — — Net loss $ (222,792 ) $ (283,780 ) $ (69,836 ) CONDENSED PARENT COMPANY STATEMENTS OF CASH FLOWS (In thousands) Years Ended December 31, 2017 2016 2015 Operating activities Net loss $ (222,792 ) $ (283,780 ) $ (69,836 ) Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Equity in losses of subsidiaries 155,878 220,031 7,464 Equity-based compensation 39,913 40,423 75,267 Amortization 3,070 3,070 3,190 Other 3,884 3,530 2,704 Changes in assets and liabilities: Decrease in receivables 986 — — (Increase) decrease in prepaid expenses and other 127 52 (34 ) (Increase) decrease due to/from related party 14,463 (15,201 ) 1,224 Increase in accounts payable and accrued liabilities 1,179 312 2,721 Net cash provided by (used in) operating activities (3,292 ) (31,563 ) 22,700 Investing activities Investment in subsidiaries 4,691 (40,047 ) (293,545 ) Net cash provided by (used in) investing activities 4,691 (40,047 ) (293,545 ) Financing activities Net proceeds from issuance of senior secured notes — — 206,774 Purchase of treasury stock (2,194 ) (1,981 ) (18,110 ) Deferred financing costs — — (9,030 ) Net cash provided by (used in) financing activities (2,194 ) (1,981 ) 179,634 Net decrease in cash and cash equivalents (795 ) (73,591 ) (91,211 ) Cash and cash equivalents at beginning of period 1,092 74,683 165,894 Cash and cash equivalents at end of period $ 297 $ 1,092 $ 74,683

Valuation and Qualifying Accoun

Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2017
Valuation and Qualifying Accounts [Abstract]
Valuation and Qualifying Accounts	Valuation and Qualifying Accounts For the Years Ended December 31, 2017 , 2016 and 2015 Additions Description Balance January 1, Charged to Costs and Expenses Charged To Other Accounts Deductions From Reserves Balance December 31, 2017 Allowance for doubtful receivables $ 574 $ 77 $ — $ (651 ) $ — Allowance for deferred tax assets $ 87,517 $ 6,008 $ — $ — $ 93,525 2016 Allowance for doubtful receivables $ — $ 574 $ — $ — $ 574 Allowance for deferred tax assets $ 116,541 $ (29,024 ) $ — $ — $ 87,517 2015 Allowance for doubtful receivables $ — $ — $ — $ — $ — Allowance for deferred tax assets $ 75,941 $ 40,600 $ — $ — $ 116,541 Schedules other than Schedule I and Schedule II have been omitted because they are not applicable or the required information is presented in the consolidated financial statements or the notes to consolidated financial statements.

Accounting Policies (Policies)

Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The accompanying consolidated financial statements include the accounts of Kosmos Energy Ltd. and its wholly owned subsidiaries. They also include the Corporation’s share of the undivided interest in certain assets, liabilities, revenues and expenses. Investments in corporate joint ventures, which we exercise significant influence over, are accounted for using the equity method of accounting. All intercompany transactions have been eliminated. Investments in companies that are partially owned by the Corporation are integral to the Corporation’s operations. The other parties, who also have an equity interest in these companies, are independent third parties that share in the business results according to their ownership. Kosmos does not invest in these companies in order to remove liabilities from its balance sheet.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.
Reclassifications	Reclassifications Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no material impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows, except as disclosed related to the adoption of recent accounting pronouncements.
Cash, Cash Equivalents and Restricted Cash	Cash, Cash Equivalents and Restricted Cash December 31, 2017 2016 2015 (In thousands) Cash and cash equivalents $ 233,412 $ 194,057 $ 275,004 Restricted cash - current 56,380 24,506 28,533 Restricted cash - long-term 15,194 54,632 7,325 Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ 304,986 $ 273,195 $ 310,862 Cash and cash equivalents includes 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 our commercial debt facility (the “Facility”), we were required to maintain a restricted cash balance that is 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 is greater. As of December 31, 2017 and 2016 , we had $24.8 million and $24.5 million , respectively, in current restricted cash to meet this requirement. In addition, 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 December 31, 2017 and 2016 , we had $31.6 million and zero , respectively, of current restricted cash and $15.2 million and $54.6 million , respectively, of long‑term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts.
Receivables	Receivables Our receivables consist of joint interest billings, oil sales and other receivables. For our oil sales receivable, we require a letter of credit to be posted to secure the outstanding receivable. Receivables from joint interest owners are stated at amounts due, net of any allowances for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things.
Inventories	Inventories Inventories consisted of $63.5 million and $68.1 million of materials and supplies and $8.4 million and $6.3 million of hydrocarbons as of December 31, 2017 and 2016 , 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. We recorded write downs of $0.9 million , $14.9 million and nil during the years ended December 31, 2017 , 2016 and 2015 for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows. 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.
Exploration and Development Costs	Exploration and Development Costs The Company follows the successful efforts method of accounting for its oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are expensed as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed and recorded in exploration expense on the consolidated statement of operations. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed as oil and gas production expense. The Company evaluates unproved property periodically for impairment. The impairment assessment considers results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential future reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time.
Depletion, Depreciation and Amortization	Depletion, Depreciation and Amortization Proved properties and support equipment and facilities are depleted using the unit‑of‑production method based on estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in a discovery of proved reserves and development costs are amortized using the unit‑of‑production method based on estimated proved developed oil and natural gas reserves for the related field. Depreciation and amortization of other property is computed using the straight-line method over the assets’ estimated useful lives (not to exceed the lease term for leasehold improvements), ranging from one to eight years . Years Depreciated Leasehold improvements 1 to 8 Office furniture, fixtures and computer equipment 3 to 7 Vehicles 5 Amortization of deferred financing costs is computed using the straight‑line method over the life of the related debt.
Capitalized Interest	Capitalized Interest Interest costs from external borrowings are capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is depleted on the unit‑of‑production method in the same manner as the underlying assets.
Asset Retirement Obligations	Asset Retirement Obligations The Company accounts for asset retirement obligations as required by ASC 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion and depreciation in the consolidated statement of operations.
Impairment of Long-lived Assets	Impairment of Long‑lived Assets The Company reviews its long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable, or at least annually. ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value. The carrying amount of a long‑lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long‑lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell. We believe the assumptions used in our undiscounted cash flow analysis to test for impairment are appropriate and result in a reasonable estimate of future cash flows. The undiscounted cash flows from the analysis exceeded the carrying amount of our long-lived assets. The most significant assumptions are the pricing and production estimates used in undiscounted cash flow analysis. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation. In order to evaluate the sensitivity of the assumptions, we assumed a hypothetical reduction in our production profile which still showed no impairment. If we experience declines in oil pricing, increases in our estimated future expenditures or a decrease in our estimated production profile our long-lived assets could be at risk for impairment.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of collars, put options, call options and swaps. We also use interest rate derivative contracts to mitigate our exposure to interest rate fluctuations related to our long‑term debt. Our derivative financial instruments are recorded on the balance sheet as either assets or liabilities and are measured at fair value. We do not apply hedge accounting to our derivative contracts.
Estimates of Proved Oil and Natural Gas Reserves	Estimates of Proved Oil and Natural Gas Reserves Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”). The accuracy of these reserve estimates is a function of: • the engineering and geological interpretation of available data; • estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost; • the accuracy of various mandated economic assumptions; and • the judgments of the persons preparing the estimates.
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 based on the provisional sales prices. 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 December 31, 2017 and 2016 , we had no oil and gas imbalances recorded in our consolidated financial statements. Our oil and gas revenues are 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.
Equity-based Compensation	Equity‑based Compensation For equity‑based compensation awards, compensation expense is recognized in the Company’s financial statements over the awards’ vesting periods based on their grant date fair value. The Company utilizes (i) the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards and restricted stock units and (ii) a Monte Carlo simulation to determine the fair value of restricted stock awards and restricted stock units with a combination of market and service vesting criteria. Forfeitures are recognized in the period in which they occur.
Treasury Stock	Treasury Stock We record treasury stock purchases at cost. Our treasury stock purchases are from our employees that surrendered shares to the Company to satisfy their statutory tax withholding requirements and are not part of a formal stock repurchase plan. The remainder of our treasury stock is forfeited restricted stock awards granted under our long‑term incentive plan.
Income Taxes	Income Taxes The Company accounts for income taxes as required by ASC 740—Income Taxes. Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be sustained upon examination by the tax authorities, based on the technical merits of the position. Accordingly, we measure tax benefits from such positions based on the most likely outcome to be realized.
Foreign Currency Translation	Foreign Currency Translation The U.S. dollar is the functional currency for all of the Company’s material foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are not significant, and as such, the effect of exchange rate changes is not material to any reporting period.
Concentration of Credit Risk	Concentration of Credit Risk Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are readily available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of operations.
Recent Accounting Standards	Recent Accounting Standards Recently Adopted In January 2017, the FASB issued ASU 2017-1, "Business Combinations (Topic 805): Clarifying the Definition of a Business." ASU 2017-1 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether those transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years with early adoption permitted. Effective October 1, 2017, we early adopted ASU 2017-1 in connection with our accounting treatment of the Equatorial Guinea acquisition during the fourth quarter of 2017. Not Yet Adopted In May 2014, the FASB issued ASU 2014-9, "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 2014-9 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 2014-9 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-9 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. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-9. The Company completed its assessment of the new accounting standard and does not expect the adoption of this standard to have a material impact to our revenue recognition based on our existing contracts with customers. We will adopt the new standard during the first quarter of 2018 using the modified retrospective approach and there will be no impact to our previously recorded revenue under the new standard. In February 2016, the FASB issued ASU 2016-2, “Leases (Topic 842).” ASU 2016-2 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 the impact of this accounting standard on its consolidated financial statements. In October 2016, the FASB issued ASU 2016-16, “Intra-Entity Transfers of Assets Other Than Inventory.” ASU 2016-16 requires the company to recognize income tax consequences, if any, on intercompany asset transfers, other than inventory, when the transfer occurs. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements.

Accounting Policies (Tables)

Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Schedule of cash and cash equivalents	December 31, 2017 2016 2015 (In thousands) Cash and cash equivalents $ 233,412 $ 194,057 $ 275,004 Restricted cash - current 56,380 24,506 28,533 Restricted cash - long-term 15,194 54,632 7,325 Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ 304,986 $ 273,195 $ 310,862
Schedule of estimated useful lives of other property	Depreciation and amortization of other property is computed using the straight-line method over the assets’ estimated useful lives (not to exceed the lease term for leasehold improvements), ranging from one to eight years . Years Depreciated Leasehold improvements 1 to 8 Office furniture, fixtures and computer equipment 3 to 7 Vehicles 5

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Schedule of property and equipment	Property and equipment is stated at cost and consisted of the following: December 31, 2017 2016 (In thousands) Oil and gas properties: Proved properties $ 1,653,616 $ 1,385,331 Unproved properties 465,109 919,056 Support equipment and facilities 1,427,054 1,386,448 Total oil and gas properties 3,545,779 3,690,835 Accumulated depletion (1,234,806 ) (989,946 ) Oil and gas properties, net 2,310,973 2,700,889 Other property 39,405 37,186 Accumulated depreciation (32,550 ) (29,183 ) Other property, net 6,855 8,003 Property and equipment, net $ 2,317,828 $ 2,708,892

Suspended Well Costs (Tables)

Suspended Well Costs (Tables)	12 Months Ended
	Dec. 31, 2017
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 years ended December 31, 2017 , 2016 and 2015 . The table excludes $43.2 million , $2.4 million and $70.3 million in costs that were capitalized and subsequently expensed during the same year for the years ended December 31, 2017 , 2016 and 2015 , respectively. During 2017, the exploratory well costs associated with the Mahogany and Teak fields were reclassified to proved property as they were unitized into the Jubilee Unit as part of the Greater Jubilee Full Field Development Plan. Years Ended December 31, 2017 2016 2015 (In thousands) Beginning balance $ 734,463 $ 426,881 $ 226,714 Additions to capitalized exploratory well costs pending the determination of proved reserves 69,567 307,582 223,542 Reclassification due to unitization of Mahogany and Teak discoveries (176,881 ) — — Divestitures(1) (206,400 ) — — Contribution of oil and gas property to equity method investment (131,764 ) — — Dissolution of equity method investment 121,128 — — Capitalized exploratory well costs charged to expense — — (23,375 ) Ending balance $ 410,113 $ 734,463 $ 426,881 ______________________________________ (1) Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal transactions with BP.
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 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: Years Ended December 31, 2017 2016 2015 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 67,159 $ 279,809 $ 199,486 Exploratory well costs capitalized for a period of one to two years 291,252 244,804 17,702 Exploratory well costs capitalized for a period of three to six years 51,702 209,850 209,693 Ending balance $ 410,113 $ 734,463 $ 426,881 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 5 5 3

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Summary of Financial Information of KTIPI	Below is a summary of financial information for KTIPI. December 31, 2017 (In thousands) Assets Total current assets $ 179,070 Property and equipment, net 345,611 Other assets 567 Total assets $ 525,248 Liabilities and shareholders' equity Total current liabilities $ 106,769 Total long term liabilities 565,591 Shareholders' equity: Total shareholders' equity (147,112 ) Total liabilities and shareholders' equity $ 525,248 Period November 28, 2017 through December 31, 2017 Revenues and other income: Oil and gas revenue $ 54,615 Other income 294 Total revenues and other income 54,909 Costs and expenses: Oil and gas production 15,509 Depletion and depreciation 10,738 Other expenses, net (19 ) Total costs and expenses 26,228 Income before income taxes 28,681 Income tax expense 6,588 Net income $ 22,093 Kosmos' share of net income $ 11,046 Basis difference amortization(1) 5,812 Equity in earnings - KTIPI $ 5,234 ______________________________________ (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)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of debt	December 31, 2017 2016 (In thousands) Outstanding debt principal balances: Facility $ 800,000 $ 850,000 Senior Notes 525,000 525,000 Total 1,325,000 1,375,000 Unamortized deferred financing costs and discounts(1) (42,203 ) (53,126 ) Long-term debt, net $ 1,282,797 $ 1,321,874 ________________________________________ (1) Includes $23.6 million and $30.3 million of unamortized deferred financing costs related to the Facility and $18.6 million and $22.8 million of unamortized deferred financing costs and discounts related to the Senior Notes as of December 31, 2017 and December 31, 2016 , respectively.
Schedule of redemption prices (expressed as percentages of principal amount) of all or a part of the Senior Notes	On or after August 1, 2017, the Company may redeem all or a part of the Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest: Year Percentage On or after August 1, 2017, but before August 1, 2018 103.9 % On or after August 1, 2018, but before August 1, 2019 102.0 % On or after August 1, 2019 and thereafter 100.0 %
Schedule of estimated repayments of debt	At December 31, 2017 , the estimated repayments of debt during the five years and thereafter are as follows: Payments Due by Year Total 2018 2019 2020 2021 2022 Thereafter (In thousands) Principal debt repayments(1) $ 1,325,000 $ — $ 200,377 $ 404,971 $ 719,652 $ — $ — (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 the level of borrowings and the estimated future available borrowing base as of December 31, 2017 . 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 December 31, 2017 , there were no borrowings under the Corporate Revolver.
Schedule of interest and other financing costs, net	Interest and other financing costs, net incurred during the period comprised of the following: Years Ended December 31, 2017 2016 2015 (In thousands) Interest expense $ 92,687 $ 89,029 $ 74,897 Amortization—deferred financing costs 10,204 10,204 10,324 Loss on extinguishment of debt — — 165 Capitalized interest (30,282 ) (59,803 ) (52,392 ) Deferred interest 2,577 (581 ) 1,770 Interest income (3,422 ) (1,954 ) (844 ) Other, net 5,831 7,252 3,289 Interest and other financing costs, net $ 77,595 $ 44,147 $ 37,209

Derivative Financial Instrume34

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
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 December 31, 2017 . Volumes are net of any offsetting derivative contracts entered into. Weighted Average Dated Brent Price per Bbl Term Type of Contract MBbl Net Deferred Premium Payable Swap Sold Put Floor Ceiling Call 2018: January — December Swap with puts 2,000 $ — $ 54.32 $ 40.00 $ — $ — $ — July — December Swap with puts 2,000 — 57.96 45.00 — — — January — June Swaps 1,000 — 57.25 — — — — January — December Three-way collars 2,913 0.74 — 41.57 56.57 65.90 — January — December Four-way collars 3,000 1.06 — 40.00 50.00 61.33 70.00 January — December Sold calls(1) 2,000 — — — — 65.00 — 2019: January — December Three-way collars 6,500 $ 0.18 $ — $ 41.54 $ 51.54 $ 63.80 $ — January — December Two-way collars 2,000 1.62 — — 55.00 65.00 — January — December Sold calls(1) 913 — — — — 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 December 31, 2017 : Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) January 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 December 31, 2017 and 2016 and gain/(loss) from derivatives during the years ended December 31, 2017 , 2016 and 2015 . Estimated Fair Value Asset (Liability) December 31, Type of Contract Balance Sheet Location 2017 2016 (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ 665 $ 31,698 Interest rate Derivatives assets—current 1,017 — Commodity(2) Derivatives assets—long-term 39 3,226 Interest rate Derivatives assets—long-term — 582 Derivative liabilities: Commodity(3) Derivatives liabilities—current (67,531 ) (19,163 ) Interest rate Derivatives liabilities—current — (529 ) Commodity(4) Derivatives liabilities—long-term (30,209 ) (14,123 ) Total derivatives not designated as hedging instruments $ (96,019 ) $ 1,691 ______________________________________ (1) Includes net deferred premiums receivable of $0.8 million and net deferred premiums payable of $3.9 million related to commodity derivative contracts as of December 31, 2017 and 2016 , respectively. (2) Includes net deferred premiums receivable of $0.1 million and net deferred premiums payable of $2.5 million related to commodity derivative contracts as of December 31, 2017 and 2016 , respectively. (3) Includes zero and $30.9 thousand as of December 31, 2017 and December 31, 2016 , respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of $5.6 million and $6.2 million related to commodity derivative contracts as of December 31, 2017 and 2016 , respectively. (4) Includes net deferred premiums payable of $4.8 million and $0.6 million related to commodity derivative contracts as of December 31, 2017 and 2016 , respectively.
Schedule of derivative instruments by location of gain/(loss)	Amount of Gain/(Loss) Years Ended December 31, Type of Contract Location of Gain/(Loss) 2017 2016 2015 (In thousands) Derivatives in cash flow hedging relationships: Interest rate(1) Interest expense $ — $ — $ 767 Total derivatives in cash flow hedging relationships $ — $ — $ 767 Derivatives not designated as hedging instruments: Commodity(2) Oil and gas revenue $ (12,502 ) $ 2,538 $ 3 Commodity Derivatives, net (59,968 ) (48,021 ) 210,649 Interest rate Interest expense 648 (1,076 ) (462 ) Total derivatives not designated as hedging instruments $ (71,822 ) $ (46,559 ) $ 210,190 ______________________________________ (1) Amounts were reclassified from AOCI into earnings upon settlement. (2) Amounts represent the change in fair value of our provisional oil sales contracts.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
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 December 31, 2017 and 2016 , for each fair value hierarchy level: Fair Value Measurements Using: Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) December 31, 2017 Assets: Commodity derivatives $ — $ 704 $ — $ 704 Interest rate derivatives — 1,017 — 1,017 Liabilities: Commodity derivatives — (97,740 ) — (97,740 ) Interest rate derivatives — — — — Total $ — $ (96,019 ) $ — $ (96,019 ) December 31, 2016 Assets: Commodity derivatives $ — $ 34,924 $ — $ 34,924 Interest rate derivatives — 582 — 582 Liabilities: Commodity derivatives — (33,286 ) — (33,286 ) Interest rate derivatives — (529 ) — (529 ) Total $ — $ 1,691 $ — $ 1,691
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 December 31, 2017 and 2016 : December 31, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 507,600 $ 542,472 $ 503,716 $ 528,938 Facility 800,000 800,000 850,000 850,000 Total $ 1,307,600 $ 1,342,472 $ 1,353,716 $ 1,378,938

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of changes in asset retirement obligations	The following table summarizes the changes in the Company’s asset retirement obligations: December 31, 2017 2016 (In thousands) Asset retirement obligations: Beginning asset retirement obligations $ 63,574 $ 43,938 Liabilities incurred during period — 14,235 Revisions in estimated retirement obligations (3,945 ) — Accretion expense 6,966 5,401 Ending asset retirement obligations $ 66,595 $ 63,574

Equity-based Compensation (Tabl

Equity-based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of plan activity	The following table reflects the outstanding restricted stock awards as of December 31, 2017 : Service Vesting Restricted Stock Awards Weighted- Average Grant-Date Fair Value Market / Service Vesting Restricted Stock Awards Weighted- Average Grant-Date Fair Value (In thousands) (In thousands) Outstanding at December 31, 2014: 3,240 $ 16.95 3,361 $ 13.00 Granted 660 8.64 — — Forfeited (2 ) 12.84 (1,554 ) 13.29 Vested (3,088 ) 17.21 (1,546 ) 13.30 Outstanding at December 31, 2015: 810 9.20 261 9.44 Granted — — — — Forfeited — — (162 ) 9.44 Vested (322 ) 9.77 (99 ) 9.44 Outstanding at December 31, 2016: 488 8.83 — — Granted — — — — Forfeited — — — — Vested (268 ) 8.97 — — Outstanding at December 31, 2017: 220 8.64 — — The following table reflects the outstanding restricted stock units as of December 31, 2017 : Service Vesting Restricted Stock Units Weighted- Average Grant-Date Fair Value Market / Service Vesting Restricted Stock Units Weighted-Average Grant-Date Fair Value (In thousands) (In thousands) Outstanding at December 31, 2014: 3,367 $ 10.76 3,246 $ 15.66 Granted 1,539 8.37 3,544 12.96 Forfeited (254 ) 10.14 (212 ) 14.48 Vested (1,060 ) 10.71 — — Outstanding at December 31, 2015: 3,592 9.79 6,578 14.24 Granted 2,158 4.05 1,379 4.88 Forfeited (134 ) 8.87 (70 ) 14.49 Vested (1,456 ) 9.61 (693 ) 15.81 Outstanding at December 31, 2016: 4,160 6.91 7,194 12.29 Granted 2,085 6.43 2,175 9.50 Forfeited (137 ) 6.91 (21 ) 6.21 Vested (1,925 ) 7.51 (896 ) 15.43 Outstanding at December 31, 2017: 4,183 6.39 8,452 11.26

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of components of income (loss) before income taxes	The components of income (loss) before income taxes were as follows: Years Ended December 31, 2017 2016 2015 (In thousands) Bermuda $ (66,914 ) $ (63,749 ) $ (62,372 ) United States 6,068 5,083 10,652 Foreign—other (117,009 ) (235,898 ) 137,156 Income (loss) before income taxes $ (177,855 ) $ (294,564 ) $ 85,436
Schedule of components of the provision for income taxes attributable to the entity's income (loss) before income taxes	The components of the provision for income taxes attributable to our income (loss) before income taxes consist of the following: Years Ended December 31, 2017 2016 2015 (In thousands) Current: Bermuda $ — $ — $ — United States 10,976 12,675 15,199 Foreign—other 24,456 102 29,287 Total current 35,432 12,777 44,486 Deferred: Bermuda — — — United States 15,310 (3,594 ) 8,241 Foreign—other (5,805 ) (19,967 ) 102,545 Total deferred 9,505 (23,561 ) 110,786 Income tax expense (benefit) $ 44,937 $ (10,784 ) $ 155,272
Schedule of reconciliation of income tax expense and the reported effective tax rate	Our reconciliation of income tax expense (benefit) computed by applying our Bermuda statutory rate and the reported effective tax rate on income (loss) from continuing operations is as follows: Years Ended December 31, 2017 2016 2015 (In thousands) Tax at Bermuda statutory rate $ — $ — $ — Foreign income (loss) taxed at different rates (1,978 ) (57,898 ) 94,184 Change in valuation allowance and the expiration of fully valued deferred tax assets 6,008 29,263 40,600 Non-deductible and other items(1) 21,100 12,347 1,885 Tax shortfall on equity-based compensation 3,086 5,504 18,603 Change in U.S. tax rate 16,721 — — Total tax expense (benefit) $ 44,937 $ (10,784 ) $ 155,272 Effective tax rate(2) 25 % 4 % 182 % ______________________________________ (1) Includes $5.0 million of tax expense related to the expiration of a Moroccan tax loss carryforward; $4.7 million of tax related interest expense incurred in 2017; and other various items. (2) The effective tax rate during the years ended December 31, 2017 , 2016 and 2015 were impacted by losses of $164.4 million , $121.4 million and $153.5 million , respectively, incurred in jurisdictions in which we are not subject to taxes and therefore do not generate any income tax benefits.
Schedule of tax effects of significant temporary differences to deferred tax assets and liabilities	The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows: December 31, 2017 2016 (In thousands) Deferred tax assets: Foreign capitalized operating expenses $ 68,218 $ 69,804 Foreign net operating losses 25,307 36,352 Equity compensation 20,783 30,752 Unrealized derivative losses 33,963 — Asset retirement obligation and other 24,784 33,744 Total deferred tax assets 173,055 170,652 Valuation allowance (93,525 ) (87,517 ) Total deferred tax assets, net 79,530 83,135 Deferred tax liabilities: Depletion, depreciation and amortization related to property and equipment (533,561 ) (526,945 ) Unrealized derivative gains — (584 ) Total deferred tax liabilities (533,561 ) (527,529 ) Net deferred tax liability $ (454,031 ) $ (444,394 )

Net Income (Loss) Per Share (Ta

Net Income (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of reconciliation between net income and the amounts used to compute basic and diluted net income per share and the weighted average shares outstanding used to compute basic and diluted net income per share	Years Ended December 31, 2017 2016 2015 (In thousands, except per share data) Numerator: Net loss (222,792 ) (283,780 ) $ (69,836 ) Basic income allocable to participating securities(1) — — — Basic net loss allocable to common shareholders (222,792 ) (283,780 ) (69,836 ) Diluted adjustments to income allocable to participating securities(1) — — — Diluted net loss allocable to common shareholders (222,792 ) (283,780 ) $ (69,836 ) Denominator: Weighted average number of shares outstanding: Basic 388,375 385,402 382,610 Restricted stock awards and units(1)(2) — — — Diluted 388,375 385,402 382,610 Net loss per share: Basic $ (0.57 ) $ (0.74 ) $ (0.18 ) Diluted $ (0.57 ) $ (0.74 ) $ (0.18 ) ______________________________________ (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 income (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 income (loss) per common share calculation in periods we are in a net loss position. (2) For the years ended December 31, 2017 , 2016 and 2015 , we excluded 12.9 million , 11.8 million and 11.2 million outstanding restricted stock awards and restricted stock units, respectively, from the computations of diluted net income per share because the effect would have been anti‑dilutive.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of estimated future minimum commitments	Future minimum rental commitments under our leases at December 31, 2017 , are as follows: Payments Due By Year(1) Total 2018 2019 2020 2021 2022 Thereafter (In thousands) Operating leases(2) $ 12,626 $ 4,981 $ 4,370 $ 484 $ 419 $ 418 $ 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) Primarily relates to corporate office and foreign office leases.

Additional Financial Informat41

Additional Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Additional Financial Information
Schedule of accrued liabilities	Accrued liabilities consisted of the following: December 31, 2017 2016 (In thousands) Accrued liabilities: Exploration, development and production $ 144,717 $ 76,194 General and administrative expenses 31,124 31,243 Interest 20,457 17,247 Income taxes 17,423 2,579 Taxes other than income 3,270 1,914 Other 2,421 529 $ 219,412 $ 129,706
Schedule of Other expenses, net incurred	Other expenses, net incurred during the period is comprised of the following: Years Ended December 31, 2017 2016 2015 (In thousands) Inventory write-off $ 866 $ 14,900 $ 36 (Gain) loss on insurance settlements (461 ) (4,003 ) 4,151 Disputed charges and related costs 4,962 11,299 — Other, net (76 ) 920 1,059 Other expenses, net $ 5,291 $ 23,116 $ 5,246

Supplemental Quarterly Financ42

Supplemental Quarterly Financial Information (Unaudited) (Table)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule of Supplemental Quarterly Financial Information (Unaudited)	Quarter Ended March 31, June 30, September 30, December 31, (In thousands, except per share data) 2017 Revenues and other income $ 151,966 $ 146,524 $ 151,242 $ 187,104 Costs and expenses 158,630 131,252 216,162 308,647 Net loss (28,841 ) (8,467 ) (63,405 ) (122,079 ) Net loss per share: Basic(1) (0.07 ) (0.02 ) (0.16 ) (0.31 ) Diluted(1) (0.07 ) (0.02 ) (0.16 ) (0.31 ) 2016 Revenues and other income $ 62,133 $ 45,676 $ 66,629 $ 210,917 Costs and expenses 123,148 169,544 118,890 268,337 Net loss (58,993 ) (108,324 ) (59,763 ) (56,700 ) Net loss per share: Basic(1) (0.15 ) (0.28 ) (0.15 ) (0.15 ) Diluted(1) (0.15 ) (0.28 ) (0.15 ) (0.15 ) ______________________________________ (1) The sum of the quarterly earnings per share information may not add to the annual earnings per share information as a result of rounding.

Organization (Details)

Organization (Details)	12 Months Ended
	Dec. 31, 2017segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of reportable segments	1

Accounting Policies - Cash, Cas

Accounting Policies - Cash, Cash Equivalents, and Restricted Stock (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Cash and cash equivalents	$ 233,412	$ 194,057	$ 275,004
Restricted cash - current	56,380	24,506	28,533
Restricted cash - long-term	15,194	54,632	7,325
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$ 304,986	$ 273,195	$ 310,862	$ 586,882

Accounting Policies - Useful Li

Accounting Policies - Useful Lives (Details)	12 Months Ended
	Dec. 31, 2017
Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	1 year
Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	8 years
Leasehold improvements | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	1 year
Leasehold improvements | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	8 years
Office furniture, fixtures and computer equipment | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	3 years
Office furniture, fixtures and computer equipment | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	7 years
Vehicles
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	5 years

Accounting Policies - Narrative

Accounting Policies - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Aug. 31, 2014
Restricted Cash
Restricted cash - current	$ 56,380,000	$ 24,506,000	$ 28,533,000
Restricted cash - long-term	15,194,000	54,632,000	7,325,000
Receivables
Allowance for doubtful accounts	0	600,000
Inventories
Materials and supplies inventory	63,500,000	68,100,000
Hydrocarbons inventory	8,400,000	6,300,000
Write down of materials and supplies	866,000	14,900,000	$ 36,000
Impairment of Long-lived Assets
Impairment of oil and gas	0
Derivative Instruments and Hedging Activities
Accumulated other comprehensive income		0
Revenue Recognition
Oil and gas imbalances	$ 0	0
Restricted Cash | Facility interest or the Senior Notes plus the Corporate Revolver interest
Restricted Cash
Restricted cash period required as per commercial debt facility to meet interest and commitment fee payments	6 months
Restricted cash - current	$ 24,800,000	24,500,000
Restricted Cash | Petroleum agreements - performance guarantees
Restricted Cash
Restricted cash - current	31,600,000	0
Restricted cash - long-term	$ 15,200,000	$ 54,600,000
Senior Notes | 7.875% senior notes due 2021
Restricted Cash
Interest rate	7.875%			7.875%
Minimum
Depletion, Depreciation and Amortization
Estimated useful lives (in years)	1 year
Maximum
Depletion, Depreciation and Amortization
Estimated useful lives (in years)	8 years
Capitalized interest | Minimum
Capitalized Interest
Expected construction period for capitalization of interest costs on major projects	1 year

Acquisitions and Divestitures (

Acquisitions and Divestitures (Details) a in Millions

Feb. 01, 2016

Dec. 31, 2017USD ($)km²block$ / bblMBbls

Oct. 31, 2017km²sub_periodblock

Sep. 30, 2017

Aug. 31, 2017USD ($)

Apr. 30, 2017

Jan. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Oct. 31, 2016akm²

Sep. 30, 2016USD ($)

May 31, 2016

Apr. 30, 2016km²

Nov. 30, 2015USD ($)

Oct. 31, 2015

Mar. 31, 2015USD ($)exploration_well

Feb. 28, 2017instrument

Oct. 31, 2016a

Dec. 31, 2017USD ($)km²$ / bblMBbls

Mar. 31, 2017USD ($)

Dec. 31, 2017USD ($)km²$ / bblMBbls

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Oct. 31, 2016

Oct. 31, 2016km²

Acquisitions and Divestitures

Proceeds on sale of assets

$ 222,068,000

$ 210,000

$ 28,692,000

Gain on sale of assets

$ 0

$ 0

$ 24,651,000

Block 5

Acquisitions and Divestitures

Participating interest percentage

45.00%

Block 12

Acquisitions and Divestitures

Participating interest percentage

45.00%

Essaouira Offshore Block

Acquisitions and Divestitures

Participating interest percentage

75.00%

Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks

Acquisitions and Divestitures

Participating interest percentage

60.00%

Farm-in agreement | Block 11

Acquisitions and Divestitures

Participation interest acquired

85.00%

Farm-in agreement | Camarao, Ameijoa, Mexilhao and Ostra blocks

Acquisitions and Divestitures

Participating interest percentage

31.00%

Farm-in agreement | Block 6

Acquisitions and Divestitures

Participation interest acquired

45.00%

Farm-out agreements | Block 42

Acquisitions and Divestitures

Participating interest percentage

33.33%

Petroleum agreement | Boujdour Maritime block

Acquisitions and Divestitures

Participating interest percentage

55.00%

Petroleum agreement | Block C6 Related To Mauritania

Acquisitions and Divestitures

Participating interest percentage

28.00%

Area of petroleum exploration

1.1

1.1

4,300

Initial exploration period

4 years

3D seismic requirements (in square kilometers) | km²

2,000

Petroleum agreement | Block EG-21 and Block S and Block W

Acquisitions and Divestitures

Participating interest percentage

80.00%

Number of blocks | block

3

Area of petroleum exploration | km²

6,000

Initial exploration period

5 years

Number of sub-periods | sub_period

2

First sub exploration period

3 years

Second sub exploration period

2 years

3D seismic requirements (in square kilometers) | km²

6,000

Petroleum agreement | Block CI-526, Block CI-602, Block CI-603, Block CI-707, and Block CI-708

Acquisitions and Divestitures

Participating interest percentage

45.00%

Number of blocks | block

5

Area of petroleum exploration | km²

17,000

17,000

17,000

Initial exploration period

3 years

3D seismic requirements (in square kilometers) | km²

12,000

Assignment Agreement | Block EG-21 and Block S and Block W

Acquisitions and Divestitures

Participating interest percentage

40.00%

Sales and purchase agreement | Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks

Acquisitions and Divestitures

Participating interest percentage

65.00%

60.00%

Equity increase in each contract area

5.00%

Sales and purchase agreement and farm-out agreements | Mauritania And Senegal Offshore Block

Acquisitions and Divestitures

Reduction of oil and gas properties with unproved reserves

$ 221,900,000

$ 221,900,000

$ 221,900,000

Timis Corporation Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks

Acquisitions and Divestitures

Participating interest percentage

30.00%

Trident Energy | Assignment Agreement | Block EG-21 and Block S and Block W

Acquisitions and Divestitures

Participating interest percentage

40.00%

Participating interest to be assigned

40.00%

Guinea Equatorial De Petroleos | Petroleum agreement | Block EG-21 and Block S and Block W

Acquisitions and Divestitures

Carried participating interest

20.00%

Percentage converted from carried to participating

20.00%

Tullow | Farm-in agreement | Block C18 Offshore Mauritania

Acquisitions and Divestitures

Participating interest percentage

15.00%

ANP STP | Block 5

Acquisitions and Divestitures

Carried participating interest

15.00%

15.00%

15.00%

ANP STP | Block 12

Acquisitions and Divestitures

Carried participating interest

12.50%

12.50%

12.50%

ANP STP | Farm-in agreement | Block 11

Acquisitions and Divestitures

Carried participating interest

15.00%

Hess Corporation | Farm-out agreements | Block 42

Acquisitions and Divestitures

Participating interest percentage

33.33%

3D seismic requirements (in square kilometers) | km²

6,500

Staatsolie | Farm-out agreements | Block 42

Acquisitions and Divestitures

Maximum percentage interest available upon approval

10.00%

Cairn | Petroleum agreement | Boujdour Maritime block

Acquisitions and Divestitures

Participating interest percentage

20.00%

ONHYM | Petroleum agreement | Boujdour Maritime block

Acquisitions and Divestitures

Carried participating interest

25.00%

BP | Essaouira Offshore Block

Acquisitions and Divestitures

Amount due in lieu of drilling exploration well

$ 30,000,000

Participating interest reassigned

45.00%

Amount received in lieu of drilling exploration well

$ 30,000,000

BP | Farm-out agreements | Block C6 Block C8 Block C12 and Block C13 Mauritania

Acquisitions and Divestitures

Participation interest acquired

62.00%

Number of blocks covered by farm-out agreements | instrument

4

BP | Petroleum agreement | Block CI-526, Block CI-602, Block CI-603, Block CI-707, and Block CI-708

Acquisitions and Divestitures

Participating interest percentage

45.00%

BP | Sales and purchase agreement | Kosmos BP Senegal Limited

Acquisitions and Divestitures

Participation interest acquired

49.99%

BP | Sales and purchase agreement and farm-out agreements | Mauritania And Senegal Offshore Block

Acquisitions and Divestitures

Upfront amount of cash received

$ 162,000,000

Spending by third party for exploration and appraisal costs

$ 228,000,000

Spending by third party for exploration and appraisal costs, initial estimate

221,000,000

Spending by third party for Kosmos' development costs

$ 533,000,000

SMHPM | Petroleum agreement | Block C6 Related To Mauritania

Acquisitions and Divestitures

Carried participating interest

10.00%

GALP | Farm-out agreements | Block 5, Block 11, and Block 12

Acquisitions and Divestitures

Non operated interest

20.00%

Timis Corporation Limited

Acquisitions and Divestitures

Line of credit agreement maximum

$ 30,000,000

Amount received, result of agreement termination

$ 16,000,000

Timis Corporation Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks

Acquisitions and Divestitures

Participating interest percentage

30.00%

Timis Corporation Limited | Farm-in agreement | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks

Acquisitions and Divestitures

Maximum cost per contingent exploration well

$ 120,000,000

Chevron | Farm-out agreements | Block 42

Acquisitions and Divestitures

Participating interest percentage

33.33%

Chevron | Farm-out agreements | Block C8 Block C12 And Block C13

Acquisitions and Divestitures

Participating interest reassigned

30.00%

Number of exploration wells for which a third party will pay a disproportionate amount | exploration_well

1

Proceeds on sale of assets

$ 28,700,000

Gain on sale of assets

$ 24,700,000

Hess | Ceiba Field and Okume Complex Assets

Acquisitions and Divestitures

Revenue interests

80.75%

Paying interest

85.00%

PETROCI | Petroleum agreement | Block CI-526, Block CI-602, Block CI-603, Block CI-707, and Block CI-708

Acquisitions and Divestitures

Carried participating interest

10.00%

10.00%

10.00%

Hess | Sales and purchase agreement | Ceiba Field and Okume Complex Assets

Acquisitions and Divestitures

Payments to acquire business

$ 650,000,000

Net cash consideration paid

$ 231,000,000

$ 231,000,000

$ 231,000,000

Maximum | BP | Farm-out agreements | Mauritania And Senegal Offshore Block

Acquisitions and Divestitures

Number of barrels | MBbls

1,000,000

1,000,000

1,000,000

Amount of potential and variable consideration per barrel | $ / bbl

2

2

2

Kosmos BP Senegal Ltd | BP Senegal Investments Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks

Acquisitions and Divestitures

Working interest transferred

30.00%

Hess | Trident Energy | Sales and purchase agreement | Ceiba Field and Okume Complex Assets

Acquisitions and Divestitures

Ownership percentage

50.00%

50.00%

50.00%

Joint Interest Billings (Detail

Joint Interest Billings (Details) - USD ($)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2017	Dec. 31, 2016
Joint interest billings
Joint interest billings, net		$ 134,565,000	$ 63,249,000
Long-term receivables - joint interest billings		34,941,000	45,663,000
TEN Discoveries | GNPC
Joint interest billings
Joint interest billings, net		15,200,000	0
Long-term receivables - joint interest billings		$ 31,600,000	$ 44,000,000
TEN Discoveries | GNPC
Joint interest billings
GNPC's paying interest (as a percent)	5.00%

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and gas properties:
Proved properties	$ 1,653,616	$ 1,385,331
Unproved properties	465,109	919,056
Support equipment and facilities	1,427,054	1,386,448
Total oil and gas properties	3,545,779	3,690,835
Accumulated depletion	(1,234,806)	(989,946)
Oil and gas properties, net	2,310,973	2,700,889
Other property	39,405	37,186
Accumulated depreciation	(32,550)	(29,183)
Other property, net	6,855	8,003
Property and equipment, net	2,317,828	2,708,892
Depletion expense	$ 244,900	$ 131,500	$ 146,600

Suspended Well Costs (Details)

Suspended Well Costs (Details) $ in Thousands	1 Months Ended	12 Months Ended
	May 31, 2015exploration_well	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2017USD ($)project	Dec. 31, 2016USD ($)project	Dec. 31, 2015USD ($)project
Reconciliation of capitalized exploratory well costs on completed wells
Beginning balance		$ 734,463	$ 426,881	$ 226,714
Additions to capitalized exploratory well costs pending the determination of proved reserves		69,567	307,582	223,542
Reclassification due to unitization of Mahogany and Teak discoveries		(176,881)	0	0
Divestitures		(206,400)	0	0
Contribution of oil and gas property to equity method investment		(131,764)	0	0
Dissolution of equity method investment		121,128	0	0
Capitalized exploratory well costs charged to expense		0	0	(23,375)
Ending balance		410,113	734,463	426,881
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					$ 67,159	$ 279,809	$ 199,486
Exploratory well costs capitalized for a period of one to two years					291,252	244,804	17,702
Exploratory well costs capitalized for a period of three to six years					51,702	209,850	209,693
Ending balance		734,463	426,881	226,714	$ 410,113	$ 734,463	$ 426,881
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | project					5	5	3
Capitalized exploratory well costs subsequently expensed in the same period		$ 43,200	$ 2,400	$ 70,300
Greater Tortue Discovery
Aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year
Number of additional wells drilled | exploration_well	2

Equity Method Investments - Sum

Equity Method Investments - Summary of Financial Information (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs and expenses:
Equity in earnings - KTIPI		$ (6,252)	$ 0	$ 0
Kosmos-Trident International Petroleum Inc.
Assets
Total current assets	$ 179,070	179,070
Property and equipment, net	345,611	345,611
Other assets	567	567
Total assets	525,248	525,248
Liabilities and shareholders' equity
Total current liabilities	106,769	106,769
Total long term liabilities	565,591	565,591
Shareholders' equity:
Total shareholders' equity	(147,112)	(147,112)
Total liabilities and shareholders' equity	525,248	$ 525,248
Revenues and other income:
Oil and gas revenue	54,615
Other income	294
Total revenues and other income	54,909
Costs and expenses:
Oil and gas production	15,509
Depletion and depreciation	10,738
Other expenses, net	(19)
Total costs and expenses	26,228
Income before income taxes	28,681
Income tax expense	6,588
Net income	22,093
Kosmos' share of net income	11,046
Basis difference amortization	5,812
Equity in earnings - KTIPI	$ 5,234

Equity Method Investments - Nar

Equity Method Investments - Narrative (Details) - USD ($)	1 Months Ended		12 Months Ended
	Dec. 31, 2017	Oct. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Contribution to equity method investment			$ 133,893,000	$ 0	$ 0
Initial contribution			231,280,000	0	0
Loss on equity method investment, net			$ 6,252,000	$ 0	$ 0
Kosmos BP Senegal Limited
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.01%		50.01%
Contribution to equity method investment			$ 133,900,000
Loss on equity method investment, net			$ 11,500,000
Kosmos-Trident International Petroleum Inc.
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%		50.00%
Loss on equity method investment, net	$ (5,234,000)
Impairment of equity method investment			$ 0
Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | BP Senegal Investments Limited | Kosmos BP Senegal Limited
Schedule of Equity Method Investments [Line Items]
Working interest transferred		30.00%
Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | Kosmos BP Senegal Limited
Schedule of Equity Method Investments [Line Items]
Working interest			30.00%

Debt - Schedule of Debt (Detail

Debt - Schedule of Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Outstanding debt principal	$ 1,325,000	$ 1,375,000
Unamortized issuance costs and discount	(42,203)	(53,126)
Long-term debt	1,282,797	1,321,874
Revolving Credit Facility
Debt Instrument [Line Items]
Outstanding debt principal	800,000	850,000
Senior Notes
Debt Instrument [Line Items]
Outstanding debt principal	525,000	525,000
Unamortized issuance costs and discount	(18,600)	(22,800)
The Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Unamortized issuance costs and discount	$ (23,600)	$ (30,300)

Debt - Narrative (Details)

Debt - Narrative (Details)

1 Months Ended

12 Months Ended

Feb. 26, 2018USD ($)

Jul. 31, 2016

Jun. 30, 2016

Jul. 31, 2015USD ($)

Apr. 30, 2015USD ($)

Aug. 31, 2014USD ($)

Dec. 31, 2017USD ($)letter_of_credit

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Sep. 30, 2017USD ($)

Apr. 30, 2017USD ($)

Mar. 31, 2017USD ($)

Aug. 01, 2015USD ($)

Jun. 30, 2015USD ($)

Feb. 01, 2015USD ($)

Debt

Loss on extinguishment of debt

$ 0

$ 0

$ 165,000

Net deferred financing costs

2,510,000

$ 5,248,000

Revolving Credit Facility | The Facility

Debt

Current borrowing capacity

$ 1,300,000,000

$ 1,300,000,000

Amount outstanding

800,000,000

Proceeds from lines of credit

200,000,000

Undrawn availability

$ 500,800,000

Interval period for payment of interest

6 months

Commitment fee percentage of the then-applicable margin when commitment is available for utilization

40.00%

Commitment fee percentage of the then-applicable margin when commitment is not available for utilization

20.00%

Net deferred financing costs

$ 23,600,000

Availability period of revolving-credit

1 month

Amount outstanding under letters of credit

$ 0

Revolving Credit Facility | Corporate Revolver

Debt

Amount outstanding

0

Undrawn availability

400,000,000

Total commitment

$ 400,000,000

Net deferred financing costs

$ 2,500,000

Interval period for payment of interest

6 months

Percentage used to calculate commitment fees when commitment is available for utilization

30.00%

Revolving Credit Facility | Corporate Revolver | LIBOR

Debt

Applicable margin (as a percent)

6.00%

Revolving Credit Facility | Minimum | The Facility | LIBOR

Debt

Applicable margin (as a percent)

3.25%

Revolving Credit Facility | Maximum | The Facility | LIBOR

Debt

Applicable margin (as a percent)

4.50%

Senior Notes | 7.875% senior notes due 2021

Other disclosures

Interest rate

7.875%

7.875%

Senior notes offering face amount

$ 225,000,000

$ 300,000,000

$ 225,000,000

$ 300,000,000

Proceeds, net of offering discounts and deferred financing costs

$ 206,800,000

$ 292,500,000

Redemption price percentage following change of control

101.00%

Redemption price percentage following sell of certain assets

100.00%

Revolving Letter of Credit Facility

Debt

Amount outstanding

$ 60,300,000

Applicable margin (as a percent)

0.80%

0.50%

Total commitment

$ 75,000,000

$ 70,000,000

$ 115,000,000

Additional commitments

$ 50,000,000

Percentage used to calculate commitment fees when commitment is available for utilization

0.65%

Other disclosures

Cash collateral maintained as a percentage of outstanding letters of credit

75.00%

Cash collateral required as a percentage of outstanding letters of credit under breach of certain financial covenants

100.00%

Number of letters of credit | letter_of_credit

8

Subsequent Event | Revolving Credit Facility | The Facility

Debt

Total commitment

$ 1,500,000,000

Additional commitments

500,000,000

Loss on extinguishment of debt

5,700,000

Subsequent Event | Revolving Letter of Credit Facility

Debt

Total commitment

$ 73,000,000

Debt - Redemption Prices (Detai

Debt - Redemption Prices (Details) - Senior Notes - 7.875% senior notes due 2021	12 Months Ended
	Dec. 31, 2017
On or after August 1, 2017, but before August 1, 2018
Debt Instrument [Line Items]
Redemption price, as a percent of the of principal amount	103.90%
On or after August 1, 2018, but before August 1, 2019
Debt Instrument [Line Items]
Redemption price, as a percent of the of principal amount	102.00%
On or after August 1, 2019 and thereafter
Debt Instrument [Line Items]
Redemption price, as a percent of the of principal amount	100.00%

Debt - Maturities (Details)

Debt - Maturities (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Scheduled maturities of debt during the five year period and thereafter
Total	$ 1,325,000,000	$ 1,375,000,000
2,018	0
2,019	200,377,000
2,020	404,971,000
2,021	719,652,000
2,022	0
Thereafter	0
Debt Instrument [Line Items]
Outstanding debt principal	1,325,000,000	1,375,000,000
Senior Notes
Scheduled maturities of debt during the five year period and thereafter
Total	525,000,000	525,000,000
Debt Instrument [Line Items]
Outstanding debt principal	525,000,000	525,000,000
Senior Notes | 7.875% senior notes due 2021
Scheduled maturities of debt during the five year period and thereafter
Total	525,000,000
Debt Instrument [Line Items]
Outstanding debt principal	525,000,000
Corporate Revolver
Scheduled maturities of debt during the five year period and thereafter
Total	800,000,000	850,000,000
Debt Instrument [Line Items]
Outstanding debt principal	800,000,000	$ 850,000,000
Corporate Revolver | Corporate Revolver
Debt Instrument [Line Items]
Amount outstanding	$ 0

Debt - Debt Interest (Details)

Debt - Debt Interest (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Interest expense	$ 92,687	$ 89,029	$ 74,897
Amortization—deferred financing costs	10,204	10,204	10,324
Loss on extinguishment of debt	0	0	165
Capitalized interest	(30,282)	(59,803)	(52,392)
Deferred interest	2,577	(581)	1,770
Interest income	(3,422)	(1,954)	(844)
Other, net	5,831	7,252	3,289
Interest and other financing costs, net	$ 77,595	$ 44,147	$ 37,209

Derivative Financial Instrume58

Derivative Financial Instruments - Oil Derivative Contracts (Details) $ in Millions	1 Months Ended		12 Months Ended
	Feb. 26, 2018USD ($)$ / bblMBbls	Jan. 31, 2018$ / bblMBbls	Dec. 31, 2017$ / bblMBbls
January 2018 — December 2018 | Swap with puts
Derivative Financial Instruments
Volumes (in MBbl) | MBbls			2,000
Weighted Average Dated Brent Price per Bbl [Abstract]
Deferred premium payable (USD per Bbl)			0
Swap (USD per Bbl)			54.32
Put (USD per Bbl)			40
Floor (USD per Bbl)			0
Ceiling (USD per Bbl)			0
Call (USD per Bbl)			0
January 2018 — December 2018 | Three-way collars
Derivative Financial Instruments
Volumes (in MBbl) | MBbls			2,913
Weighted Average Dated Brent Price per Bbl [Abstract]
Deferred premium payable (USD per Bbl)			0.74
Swap (USD per Bbl)			0
Put (USD per Bbl)			41.57
Floor (USD per Bbl)			56.57
Ceiling (USD per Bbl)			65.90
Call (USD per Bbl)			0
January 2018 — December 2018 | Four-way collars
Derivative Financial Instruments
Volumes (in MBbl) | MBbls			3,000
Weighted Average Dated Brent Price per Bbl [Abstract]
Deferred premium payable (USD per Bbl)			1.06
Swap (USD per Bbl)			0
Put (USD per Bbl)			40
Floor (USD per Bbl)			50
Ceiling (USD per Bbl)			61.33
Call (USD per Bbl)			70
January 2018 — December 2018 | Sold calls
Derivative Financial Instruments
Volumes (in MBbl) | MBbls			2,000
Weighted Average Dated Brent Price per Bbl [Abstract]
Deferred premium payable (USD per Bbl)			0
Swap (USD per Bbl)			0
Put (USD per Bbl)			0
Floor (USD per Bbl)			0
Ceiling (USD per Bbl)			65
Call (USD per Bbl)			0
July 2018 - December 2018 | Swap with puts
Derivative Financial Instruments
Volumes (in MBbl) | MBbls			2,000
Weighted Average Dated Brent Price per Bbl [Abstract]
Deferred premium payable (USD per Bbl)			0
Swap (USD per Bbl)			57.96
Put (USD per Bbl)			45
Floor (USD per Bbl)			0
Ceiling (USD per Bbl)			0
Call (USD per Bbl)			0
January 2018 - June 2018 | Swap
Derivative Financial Instruments
Volumes (in MBbl) | MBbls			1,000
Weighted Average Dated Brent Price per Bbl [Abstract]
Deferred premium payable (USD per Bbl)			0
Swap (USD per Bbl)			57.25
Put (USD per Bbl)			0
Floor (USD per Bbl)			0
Ceiling (USD per Bbl)			0
Call (USD per Bbl)			0
January 2019 - December 2019 | Three-way collars
Derivative Financial Instruments
Volumes (in MBbl) | MBbls			6,500
Weighted Average Dated Brent Price per Bbl [Abstract]
Deferred premium payable (USD per Bbl)			0.18
Swap (USD per Bbl)			0
Put (USD per Bbl)			41.54
Floor (USD per Bbl)			51.54
Ceiling (USD per Bbl)			63.80
Call (USD per Bbl)			0
January 2019 - December 2019 | Sold calls
Derivative Financial Instruments
Volumes (in MBbl) | MBbls			913
Weighted Average Dated Brent Price per Bbl [Abstract]
Deferred premium payable (USD per Bbl)			0
Swap (USD per Bbl)			0
Put (USD per Bbl)			0
Floor (USD per Bbl)			0
Ceiling (USD per Bbl)			80
Call (USD per Bbl)			0
January 2019 - December 2019 | Two-way Collars
Derivative Financial Instruments
Volumes (in MBbl) | MBbls			2,000
Weighted Average Dated Brent Price per Bbl [Abstract]
Deferred premium payable (USD per Bbl)			1.62
Swap (USD per Bbl)			0
Put (USD per Bbl)			0
Floor (USD per Bbl)			55
Ceiling (USD per Bbl)			65
Call (USD per Bbl)			0
Subsequent Event | Three-way collars
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		1,000
Subsequent Event | Commodity option
Weighted Average Dated Brent Price per Bbl [Abstract]
Deferred premium receivable | $	$ 3.1
Subsequent Event | January 2019 - December 2019 | Three-way collars
Weighted Average Dated Brent Price per Bbl [Abstract]
Put (USD per Bbl)		45
Floor (USD per Bbl)		55
Ceiling (USD per Bbl)		72.90
Short | Subsequent Event | Commodity option
Derivative Financial Instruments
Volumes (in MBbl) | MBbls	2,000
Weighted Average Dated Brent Price per Bbl [Abstract]
Derivative strike price	47.50
Long | Subsequent Event | Commodity option
Derivative Financial Instruments
Volumes (in MBbl) | MBbls	1,000
Weighted Average Dated Brent Price per Bbl [Abstract]
Derivative strike price	70

Derivative Financial Instrume59

Derivative Financial Instruments - Interest Rate Derivative Contracts (Details) - 1-month LIBOR - Capped swap - January 2018 — December 2018	Dec. 31, 2017USD ($)
Derivative Financial Instruments
Weighted average notional Amount	$ 200,000,000
Weighted average swap	1.23%
Weighted average sold call	3.00%

Derivative Financial Instrume60

Derivative Financial Instruments - Derivative Instruments and Gain/(Loss) from Derivatives (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Derivative instruments, Balance Sheet Location
Derivatives assets—current	$ 1,682,000	$ 31,698,000
Derivatives assets—long-term	39,000	3,808,000
Derivatives liabilities—current	(67,531,000)	(19,692,000)
Derivatives liabilities—long-term	(30,209,000)	(14,123,000)
Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Total derivatives not designated as hedging instruments	(96,019,000)	1,691,000
Commodity derivatives | Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Derivatives assets—current	665,000	31,698,000
Derivatives assets—long-term	39,000	3,226,000
Derivatives liabilities—current	(67,531,000)	(19,163,000)
Derivatives liabilities—long-term	(30,209,000)	(14,123,000)
Deferred premium receivable, current	800,000
Deferred premium payable, current		3,900,000
Deferred premium receivable, noncurrent	100,000
Deferred premium payable, noncurrent		2,500,000
Net deferred premiums payable related to commodity derivative contracts - current liabilities	5,600,000	6,200,000
Net deferred premiums payable related to commodity derivative contracts - non current liabilities	4,800,000	600,000
Commodity derivatives | Not designated as hedging instruments | Oil and gas revenue
Derivative instruments, Balance Sheet Location
Derivatives liabilities—current	0	(30,900)
Interest rate contracts | Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Derivatives assets—current	1,017,000	0
Derivatives assets—long-term	0	582,000
Derivatives liabilities—current	$ 0	$ (529,000)

Derivative Financial Instrume61

Derivative Financial Instruments - Location of Gain (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives not designated as hedging instruments	$ (71,822)	$ (46,559)	$ 210,190
Interest rate contracts | Interest expense
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives not designated as hedging instruments	648	(1,076)	(462)
Commodity derivatives | Oil and gas revenue
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives not designated as hedging instruments	(12,502)	2,538	3
Commodity derivatives | Derivatives, net
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives not designated as hedging instruments	(59,968)	(48,021)	210,649
Derivatives in cash flow hedging relationships
Derivative instruments, Location of Gain/(Loss)
Total derivatives in cash flow hedging relationships	0	0	767
Derivatives in cash flow hedging relationships | Interest rate contracts | Interest expense
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives designated as hedging instrument	$ 0	$ 0	$ 767

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Carrying Value
Liabilities:
Long-term debt	$ 1,307,600	$ 1,353,716
Fair Value
Liabilities:
Long-term debt	1,342,472	1,378,938
Senior Notes | Carrying Value
Liabilities:
Long-term debt	507,600	503,716
Senior Notes | Fair Value
Liabilities:
Long-term debt	542,472	528,938
Facility | Carrying Value
Liabilities:
Long-term debt	800,000	850,000
Facility | Fair Value
Liabilities:
Long-term debt	800,000	850,000
Recurring basis
Liabilities:
Total fair value, net	(96,019)	1,691
Recurring basis | Commodity derivatives
Assets:
Derivative asset, fair value	704	34,924
Liabilities:
Derivative liability, fair value	(97,740)	(33,286)
Recurring basis | Interest rate derivatives
Assets:
Derivative asset, fair value	1,017	582
Liabilities:
Derivative liability, fair value	0	(529)
Recurring basis | Level 1
Liabilities:
Total fair value, net	0	0
Recurring basis | Level 1 | Commodity derivatives
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis | Level 1 | Interest rate derivatives
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis | Level 2
Liabilities:
Total fair value, net	(96,019)	1,691
Recurring basis | Level 2 | Commodity derivatives
Assets:
Derivative asset, fair value	704	34,924
Liabilities:
Derivative liability, fair value	(97,740)	(33,286)
Recurring basis | Level 2 | Interest rate derivatives
Assets:
Derivative asset, fair value	1,017	582
Liabilities:
Derivative liability, fair value	0	(529)
Recurring basis | Level 3
Liabilities:
Total fair value, net	0	0
Recurring basis | Level 3 | Commodity derivatives
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis | Level 3 | Interest rate derivatives
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	$ 0	$ 0

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset retirement obligations:
Beginning asset retirement obligations	$ 63,574	$ 43,938
Liabilities incurred during period	0	14,235
Revisions in estimated retirement obligations	(3,945)	0
Accretion expense	6,966	5,401
Ending asset retirement obligations	$ 66,595	$ 63,574

Equity-based Compensation - Nar

Equity-based Compensation - Narrative (Details) - USD ($)	Apr. 30, 2011	Jan. 31, 2018	Jun. 30, 2015	May 31, 2011	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity-based Compensation
Tax shortfall related to equity-based compensation					$ 3,086,000	$ 5,504,000	$ 18,603,000
LTIP
Equity-based Compensation
Additional shares authorized (in shares)			15,000,000
Approved and authorized awards (in shares)			39,500,000
Number of shares remaining available for grant (in shares)					3,400,000
Compensation expense recognized					$ 40,000,000	40,100,000	75,100,000
Tax benefit					13,200,000	13,000,000	25,700,000
Tax shortfall related to equity-based compensation					$ 3,100,000	5,500,000	18,600,000
Minimum | LTIP
Equity-based Compensation
Vesting period					3 years
Maximum | LTIP
Equity-based Compensation
Vesting period					4 years
Profit units | Kosmos Energy Holdings
Equity-based Compensation
Vesting period	4 years
Number of common shares into which the units were exchanged (in shares)				31,700,000
Threshold value of awards cancelled (in dollars per unit)				$ 90
Incremental compensation costs				$ 0
Granted (in dollars per share)					$ 17
Expected dividend yield					0.00%
Profit units | Kosmos Energy Holdings | Founding Management and Directors
Equity-based Compensation
Vesting rights as of the date of issuance	20.00%
Additional vesting rights on the anniversary date for each of the next four years	20.00%
Profit units | Kosmos Energy Holdings | Employees
Equity-based Compensation
Vesting rights on the second and fourth anniversary of issuance date	50.00%
Profit units | Kosmos Energy Holdings | Minimum
Equity-based Compensation
Threshold value to employees, management and directors (in dollars per units)	$ 0.85
Expected volatility					25.00%
Risk-free interest rate					1.30%
Expected life					1 year 2 months 12 days
Profit units | Kosmos Energy Holdings | Minimum | Employees
Equity-based Compensation
Projected turnover rate					7.00%
Profit units | Kosmos Energy Holdings | Maximum
Equity-based Compensation
Threshold value to employees, management and directors (in dollars per units)	$ 90
Expected volatility					66.00%
Risk-free interest rate					5.10%
Expected life					8 years 1 month 6 days
Profit units | Kosmos Energy Holdings | Maximum | Employees
Equity-based Compensation
Projected turnover rate					27.00%
Restricted stock awards
Equity-based Compensation
Exchanged (in shares)				10,000,000
Restricted stock awards | LTIP
Equity-based Compensation
Exchanged (in shares)				10,000,000
Restricted Stock Awards and Restricted Stock Units | LTIP
Equity-based Compensation
Fair value of awards vested					$ 21,200,000	$ 14,400,000	$ 52,200,000
Compensation expense not yet recognized					$ 23,600,000
Weighted average period over which compensation expense is to be recognized					1 year 6 months
Market/Service Vesting Restricted Stock Awards | LTIP
Equity-based Compensation
Granted (in dollars per share)					$ 0	$ 0	$ 0
Risk-free interest rate					0.50%
Market/Service Vesting Restricted Stock Awards | Minimum | LTIP
Equity-based Compensation
Granted (in dollars per share)					$ 6.70
Expected volatility					41.30%
Market/Service Vesting Restricted Stock Awards | Maximum | LTIP
Equity-based Compensation
Vesting percentage of the awards granted					100.00%
Granted (in dollars per share)					$ 13.57
Expected volatility					56.70%
Market/Service Vesting Restricted Stock Units | LTIP
Equity-based Compensation
Granted (in dollars per share)					$ 9.50	4.88	12.96
Market/Service Vesting Restricted Stock Units | Minimum | LTIP
Equity-based Compensation
Granted (in dollars per share)					$ 4.83
Expected volatility					44.00%
Risk-free interest rate					0.50%
Market/Service Vesting Restricted Stock Units | Maximum | LTIP
Equity-based Compensation
Vesting percentage of the awards granted					200.00%
Granted (in dollars per share)					$ 15.81
Expected volatility					54.00%
Risk-free interest rate					1.40%
Service Vesting Restricted Stock Units | LTIP
Equity-based Compensation
Granted (in dollars per share)					$ 6.43	$ 4.05	$ 8.37
Subsequent Event | Market/Service Vesting Restricted Stock Units | LTIP
Equity-based Compensation
Granted (in shares)		2,300,000
Subsequent Event | Service Vesting Restricted Stock Units | LTIP
Equity-based Compensation
Granted (in shares)		1,800,000
Subsequent Event | Restricted stock units | LTIP
Equity-based Compensation
Compensation expense not yet recognized		$ 34,300,000
Weighted average period over which compensation expense is to be recognized		3 years

Equity-based Compensation - Sch

Equity-based Compensation - Schedule of Awards (Details) - LTIP - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Service Vesting Restricted Stock Awards
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	488	810	3,240
Granted (in shares)	0	0	660
Forfeited (in shares)	0	0	(2)
Vested (in shares)	(268)	(322)	(3,088)
Outstanding at the end of the period (in shares)	220	488	810
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 8.83	$ 9.20	$ 16.95
Granted (in dollars per share)	0	0	8.64
Forfeited (in dollars per share)	0	0	12.84
Vested (in dollars per share)	8.97	9.77	17.21
Outstanding at the end of the period (in dollars per share)	$ 8.64	$ 8.83	$ 9.20
Market/Service Vesting Restricted Stock Awards
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	0	261	3,361
Granted (in shares)	0	0	0
Forfeited (in shares)	0	(162)	(1,554)
Vested (in shares)	0	(99)	(1,546)
Outstanding at the end of the period (in shares)	0	0	261
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 0	$ 9.44	$ 13
Granted (in dollars per share)	0	0	0
Forfeited (in dollars per share)	0	9.44	13.29
Vested (in dollars per share)	0	9.44	13.30
Outstanding at the end of the period (in dollars per share)	$ 0	$ 0	$ 9.44
Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	4,160	3,592	3,367
Granted (in shares)	2,085	2,158	1,539
Forfeited (in shares)	(137)	(134)	(254)
Vested (in shares)	(1,925)	(1,456)	(1,060)
Outstanding at the end of the period (in shares)	4,183	4,160	3,592
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 6.91	$ 9.79	$ 10.76
Granted (in dollars per share)	6.43	4.05	8.37
Forfeited (in dollars per share)	6.91	8.87	10.14
Vested (in dollars per share)	7.51	9.61	10.71
Outstanding at the end of the period (in dollars per share)	$ 6.39	$ 6.91	$ 9.79
Market/Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	7,194	6,578	3,246
Granted (in shares)	2,175	1,379	3,544
Forfeited (in shares)	(21)	(70)	(212)
Vested (in shares)	(896)	(693)	0
Outstanding at the end of the period (in shares)	8,452	7,194	6,578
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 12.29	$ 14.24	$ 15.66
Granted (in dollars per share)	9.50	4.88	12.96
Forfeited (in dollars per share)	6.21	14.49	14.48
Vested (in dollars per share)	15.43	15.81	0
Outstanding at the end of the period (in dollars per share)	$ 11.26	$ 12.29	$ 14.24

Income Taxes - Components of In

Income Taxes - Components of Income (Loss) and Provision for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes
Loss before income taxes	$ (177,855)	$ (294,564)	$ 85,436
Components of the provision for income taxes attributable to income (loss) before income taxes
Current	35,432	12,777	44,486
Deferred	9,505	(23,561)	110,786
Income tax expense (benefit)	44,937	(10,784)	155,272
Reconciliation of income tax expense and the reported effective tax rate
Tax at Bermuda statutory rate	0	0	0
Foreign income (loss) taxed at different rates	(1,978)	(57,898)	94,184
Change in valuation allowance and the expiration of fully valued deferred tax assets	6,008	29,263	40,600
Non-deductible and other items	21,100	12,347	1,885
Tax shortfall on equity-based compensation	3,086	5,504	18,603
Change in U.S. tax rate	$ 16,721	$ 0	$ 0
Effective tax rate	25.00%	4.00%	182.00%
Impact of losses incurred in jurisdictions in which company is not subject to taxes on effective tax rate	$ 164,400	$ 121,400	$ 153,500
Tax related interest expense	4,700
Bermuda
Income Taxes
Loss before income taxes	(66,914)	(63,749)	(62,372)
Components of the provision for income taxes attributable to income (loss) before income taxes
Current	0	0	0
Deferred	0	0	0
United States
Income Taxes
Loss before income taxes	6,068	5,083	10,652
Components of the provision for income taxes attributable to income (loss) before income taxes
Current	10,976	12,675	15,199
Deferred	15,310	(3,594)	8,241
Foreign—other
Income Taxes
Loss before income taxes	(117,009)	(235,898)	137,156
Components of the provision for income taxes attributable to income (loss) before income taxes
Current	24,456	102	29,287
Deferred	(5,805)	$ (19,967)	$ 102,545
Morocco
Reconciliation of income tax expense and the reported effective tax rate
Tax expense from tax loss carryforward	$ 5,000

Income Taxes - Deferred Taxes (

Income Taxes - Deferred Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred tax assets:
Foreign capitalized operating expenses	$ 68,218	$ 69,804
Foreign net operating losses	25,307	36,352
Equity compensation	20,783	30,752
Unrealized derivative losses	33,963	0
Asset retirement obligation and other	24,784	33,744
Total deferred tax assets	173,055	170,652
Valuation allowance	(93,525)	(87,517)
Total deferred tax assets, net	79,530	83,135
Deferred tax liabilities:
Depletion, depreciation and amortization related to property and equipment	(533,561)	(526,945)
Unrealized derivative gains	0	(584)
Total deferred tax liabilities	(533,561)	(527,529)
Net deferred tax liability	$ (454,031)	$ (444,394)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes
Tax Cuts and Jobs Act of 2017, income tax expense (benefit)	$ 16.7
Effective tax rate	25.00%	4.00%	182.00%
Foreign net operating loss carryforwards	$ 94.1
Foreign net operating loss carryforwards expiring in 2019	0.9
Foreign net operating loss carryforwards expiring in 2020	0.5
Foreign net operating loss carryforwards expiring in 2021	0.5
Foreign net operating loss carryforwards expiring in 2022	0.6
Foreign net operating loss carryforwards expiring in 2023	0.7
Foreign net operating loss carryforwards expiring in 2029	15
Foreign net operating loss carryforwards not expiring	75.9
Material uncertain tax positions	$ 0
United States
Income Taxes
Effective tax rate	433.00%	179.00%	220.00%
Ghana
Income Taxes
Effective tax rate	49.00%	23.00%	35.00%
Foreign—other
Income Taxes
Effective tax rate	0.00%
Federal statutory income tax rate percent	0.00%

Net Income (Loss) Per Share (De

Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Numerator:
Net loss	$ (122,079)	$ (63,405)	$ (8,467)	$ (28,841)	$ (56,700)	$ (59,763)	$ (108,324)	$ (58,993)	$ (222,792)	$ (283,780)	$ (69,836)
Basic income allocable to participating securities									0	0	0
Basic net loss allocable to common shareholders									(222,792)	(283,780)	(69,836)
Diluted adjustments to income allocable to participating securities									0	0	0
Diluted net loss allocable to common shareholders									$ (222,792)	$ (283,780)	$ (69,836)
Weighted average number of shares used to compute net income (loss) per share:
Basic (in shares)									388,375	385,402	382,610
Restricted stock awards and units (in shares)									0	0	0
Diluted (in shares)									388,375	385,402	382,610
Net income (loss) per share:
Basic (in dollars per share)	$ (0.31)	$ (0.16)	$ (0.02)	$ (0.07)	$ (0.15)	$ (0.15)	$ (0.28)	$ (0.15)	$ (0.57)	$ (0.74)	$ (0.18)
Diluted (in dollars per share)	$ (0.31)	$ (0.16)	$ (0.02)	$ (0.07)	$ (0.15)	$ (0.15)	$ (0.28)	$ (0.15)	$ (0.57)	$ (0.74)	$ (0.18)
Outstanding restricted stock awards and units excluded from the computations of diluted net income per share (in shares)									12,900	11,800	11,200

Commitments and Contingencies70

Commitments and Contingencies (Details)	Oct. 14, 2011	Nov. 30, 2017well_optionwell_slot	Dec. 31, 2017USD ($)km²exploration_well	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Commitments and contingencies
Rent expense			$ 3,300,000	$ 3,300,000	$ 4,700,000
Mauritania
Commitments and contingencies
Number of exploration wells | exploration_well			1
3D seismic requirements (in square kilometers) | km²			7,600
Equatorial Guinea
Commitments and contingencies
3D seismic requirements (in square kilometers) | km²			6,000
COTE D'IVOIRE
Commitments and contingencies
3D seismic requirements (in square kilometers) | km²			12,000
Operating leases
Future minimum rental commitments
2,018			$ 4,981,000
2,019			4,370,000
2,020			484,000
2,021			419,000
2,022			418,000
Thereafter			1,954,000
Total			12,626,000
Jubilee Unitization And Unit Operating Agreement
Commitments and contingencies
Unit interest after redetermination process (as a percent)	24.10%
Farm-out agreements | Mauritania And Senegal Offshore Block | BP
Commitments and contingencies
Spending by third party for exploration and appraisal costs			$ 228,000,000
ENSCO DS-12 Drilling Rig Contract
Future minimum rental commitments
Number of well slots | well_slot		1
Number of well options | well_option		6
Number of well options exercised | well_option		1

Additional Financial Informat71

Additional Financial Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accrued liabilities:
Exploration, development and production	$ 144,717	$ 76,194
General and administrative expenses	31,124	31,243
Interest	20,457	17,247
Income taxes	17,423	2,579
Taxes other than income	3,270	1,914
Other	2,421	529
Accrued liabilities	219,412	129,706
Other Income
Other Income, net	58,700	74,800	$ 0
Other Expenses, Net
Inventory write-off	866	14,900	36
(Gain) loss on insurance settlements	(461)	(4,003)	4,151
Disputed charges and related costs	4,962	11,299	0
Other, net	(76)	920	1,059
Other expenses, net	5,291	23,116	5,246
Oil And Gas Production Expense
Trading Activity, Gains and Losses, Net [Line Items]
Insurance recoveries	$ 17,100	$ 7,500	$ 0

Supplemental Quarterly Financ72

Supplemental Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Revenues and other income	$ 187,104	$ 151,242	$ 146,524	$ 151,966	$ 210,917	$ 66,629	$ 45,676	$ 62,133	$ 636,836	$ 385,355	$ 471,556
Costs and expenses	308,647	216,162	131,252	158,630	268,337	118,890	169,544	123,148	814,691	679,919	386,120
Net loss	$ (122,079)	$ (63,405)	$ (8,467)	$ (28,841)	$ (56,700)	$ (59,763)	$ (108,324)	$ (58,993)	$ (222,792)	$ (283,780)	$ (69,836)
Earnings Per Share [Abstract]
Basic (in dollars per share)	$ (0.31)	$ (0.16)	$ (0.02)	$ (0.07)	$ (0.15)	$ (0.15)	$ (0.28)	$ (0.15)	$ (0.57)	$ (0.74)	$ (0.18)
Diluted (in dollars per share)	$ (0.31)	$ (0.16)	$ (0.02)	$ (0.07)	$ (0.15)	$ (0.15)	$ (0.28)	$ (0.15)	$ (0.57)	$ (0.74)	$ (0.18)

Schedule I - Condensed Parent73

Schedule I - Condensed Parent Company Financial Statements - Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 233,412	$ 194,057	$ 275,004
Prepaid expenses and other	9,306	7,209
Total current assets	533,602	475,187
Investment in subsidiaries at equity	236,514	0
Deferred financing costs, net of accumulated amortization of $13,951 and $11,213 at December 31, 2017 and December 31, 2016, respectively	2,510	5,248
Total assets	3,192,603	3,341,465
Current liabilities:
Accounts payable	141,787	220,627
Accrued liabilities	219,412	129,706
Total current liabilities	428,730	370,025
Long-term debt, net	1,282,797	1,321,874
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2017 and December 31, 2016	0	0
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 398,599,457 and 395,859,061 issued at December 31, 2017 and December 31, 2016, respectively	3,986	3,959
Additional paid-in capital	2,014,525	1,975,247
Accumulated deficit	(1,073,202)	(850,410)
Treasury stock, at cost, 9,188,819 and 9,101,395 shares at December 31, 2017 and December 31, 2016, respectively	(48,197)	(47,597)
Total shareholders’ equity	897,112	1,081,199	1,325,513	$ 1,338,959
Total liabilities and shareholders’ equity	$ 3,192,603	3,341,465
Parent company
Condensed Balance Sheet Statements, Captions [Line Items]
Ownership percentage	100.00%
Current assets:
Cash and cash equivalents	$ 297	1,092	$ 74,683	$ 165,894
Receivables from subsidiaries	0	14,131
Prepaid expenses and other	290	417
Total current assets	587	15,640
Investment in subsidiaries at equity	1,419,890	1,580,459
Deferred financing costs, net of accumulated amortization of $13,951 and $11,213 at December 31, 2017 and December 31, 2016, respectively	2,510	5,248
Total assets	1,422,987	1,601,347
Current liabilities:
Accounts payable	4	13
Accounts payable to subsidiaries	332	0
Accrued liabilities	19,128	17,939
Total current liabilities	19,464	17,952
Long-term debt, net	506,411	502,196
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2017 and December 31, 2016	0	0
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 398,599,457 and 395,859,061 issued at December 31, 2017 and December 31, 2016, respectively	3,986	3,959
Additional paid-in capital	2,014,525	1,975,247
Accumulated deficit	(1,073,202)	(850,410)
Treasury stock, at cost, 9,188,819 and 9,101,395 shares at December 31, 2017 and December 31, 2016, respectively	(48,197)	(47,597)
Total shareholders’ equity	897,112	1,081,199
Total liabilities and shareholders’ equity	$ 1,422,987	$ 1,601,347

Schedule I - Condensed Parent74

Schedule I - Condensed Parent Company Financial Statements - Balance Sheet (Parenthetical) (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Condensed Balance Sheet Statements, Captions [Line Items]
Deferred financing costs, accumulated amortization (in dollars)	$ 13,951	$ 11,213
Preference shares, par value (in dollars per share)	$ 0.01	$ 0.01
Preference shares, authorized shares	200,000,000	200,000,000
Preference shares, issued shares	0	0
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, authorized shares	2,000,000,000	2,000,000,000
Common shares, issued shares	398,599,457	395,859,061
Treasury stock shares	9,188,819	9,101,395
Parent company
Condensed Balance Sheet Statements, Captions [Line Items]
Deferred financing costs, accumulated amortization (in dollars)	$ 13,951	$ 11,213
Preference shares, par value (in dollars per share)	$ 0.01	$ 0.01
Preference shares, authorized shares	200,000,000	200,000,000
Preference shares, issued shares	0	0
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, authorized shares	2,000,000,000	2,000,000,000
Common shares, issued shares	398,599,457	395,859,061
Treasury stock shares	9,188,819	9,101,395

Schedule I - Condensed Parent75

Schedule I - Condensed Parent Company Financial Statements - Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues and other income:
Oil and gas revenue									$ 578,139	$ 310,377	$ 446,696
Total revenues and other income	$ 187,104	$ 151,242	$ 146,524	$ 151,966	$ 210,917	$ 66,629	$ 45,676	$ 62,133	636,836	385,355	471,556
Costs and expenses:
General and administrative									68,302	87,623	136,809
Interest and other financing costs, net									77,595	44,147	37,209
Other expenses, net									5,291	23,116	5,246
Loss on equity method investment, net									6,252	0	0
Total costs and expenses	308,647	216,162	131,252	158,630	268,337	118,890	169,544	123,148	814,691	679,919	386,120
Income (loss) before income taxes									(177,855)	(294,564)	85,436
Income tax expense (benefit)									(44,937)	10,784	(155,272)
Net loss	$ (122,079)	$ (63,405)	$ (8,467)	$ (28,841)	$ (56,700)	$ (59,763)	$ (108,324)	$ (58,993)	(222,792)	(283,780)	(69,836)
Parent company
Revenues and other income:
Oil and gas revenue									0	0	0
Total revenues and other income									0	0	0
Costs and expenses:
General and administrative									51,544	48,542	85,103
General and administrative recoveries—related party									(40,266)	(40,047)	(72,543)
Interest and other financing costs, net									55,596	55,253	49,572
Other expenses, net									40	1	240
Equity in losses of subsidiaries									(155,878)	(220,031)	(7,464)
Total costs and expenses									222,792	283,780	69,836
Income (loss) before income taxes									(222,792)	(283,780)	(69,836)
Income tax expense (benefit)									0	0	0
Net loss									$ (222,792)	$ (283,780)	$ (69,836)

Schedule I - Condensed Parent76

Schedule I - Condensed Parent Company Financial Statements - Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities
Net loss	$ (122,079)	$ (63,405)	$ (8,467)	$ (28,841)	$ (56,700)	$ (59,763)	$ (108,324)	$ (58,993)	$ (222,792)	$ (283,780)	$ (69,836)
Adjustments to reconcile net loss to net cash provided by operating activities:
Equity-based compensation									39,913	40,084	75,057
Other									5,952	13,355	7,875
Changes in assets and liabilities:
Decrease in receivables									29,365	(20,558)	2,209
(Increase) decrease in prepaid expenses and other									(31,710)	17,557	512
Net cash provided by operating activities									236,617	52,077	440,779
Investing activities
Net cash used in investing activities									(152,565)	(537,763)	(796,433)
Financing activities
Net proceeds from issuance of senior secured notes									0	0	206,774
Purchase of treasury stock									(2,194)	(1,981)	(18,110)
Deferred financing costs									(67)	0	(9,030)
Net cash provided by (used in) financing activities									(52,261)	448,019	79,634
Cash and cash equivalents at beginning of period				194,057				275,004	194,057	275,004
Cash and cash equivalents at end of period	233,412				194,057				233,412	194,057	275,004
Parent company
Operating activities
Net loss									(222,792)	(283,780)	(69,836)
Adjustments to reconcile net loss to net cash provided by operating activities:
Equity in losses of subsidiaries									155,878	220,031	7,464
Equity-based compensation									39,913	40,423	75,267
Amortization									3,070	3,070	3,190
Other									3,884	3,530	2,704
Changes in assets and liabilities:
Decrease in receivables									986	0	0
(Increase) decrease in prepaid expenses and other									127	52	(34)
(Increase) decrease due to/from related party									14,463	(15,201)	1,224
Increase in accounts payable and accrued liabilities									1,179	312	2,721
Net cash provided by operating activities									(3,292)	(31,563)	22,700
Investing activities
Investment in subsidiaries									4,691	(40,047)	(293,545)
Net cash used in investing activities									4,691	(40,047)	(293,545)
Financing activities
Net proceeds from issuance of senior secured notes									0	0	206,774
Purchase of treasury stock									(2,194)	(1,981)	(18,110)
Deferred financing costs									0	0	(9,030)
Net cash provided by (used in) financing activities									(2,194)	(1,981)	179,634
Net decrease in cash and cash equivalents									(795)	(73,591)	(91,211)
Cash and cash equivalents at beginning of period				$ 1,092				$ 74,683	1,092	74,683	165,894
Cash and cash equivalents at end of period	$ 297				$ 1,092				$ 297	$ 1,092	$ 74,683

Valuation and Qualifying Acco77

Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Allowance for doubtful receivables
Changes in valuation and qualifying Accounts
Balance at the beginning of the period	$ 574	$ 0	$ 0
Charged to Costs and Expenses	77	574	0
Charged To Other Accounts	0	0	0
Deductions From Reserves	(651)	0	0
Balance at the end of the period	0	574	0
Allowance for deferred tax assets
Changes in valuation and qualifying Accounts
Balance at the beginning of the period	87,517	116,541	75,941
Charged to Costs and Expenses	6,008	(29,024)	40,600
Charged To Other Accounts	0	0	0
Deductions From Reserves	0	0	0
Balance at the end of the period	$ 93,525	$ 87,517	$ 116,541