Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2018	Feb. 15, 2019	Jun. 30, 2018
Document and Entity Information
Entity Registrant Name	Kosmos Energy Ltd.
Entity Central Index Key	0001509991
Document Type	10-K
Document Period End Date	Dec. 31, 2018
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 Shell Company	false
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Entity Public Float			$ 1,954,943,075
Entity Common Stock, Shares Outstanding		401,252,135

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 173,515	$ 233,412
Restricted cash	4,527	56,380
Receivables:
Joint interest billings, net	64,572	134,565
Oil sales	48,164	0
Related party	5,580	780
Other	21,690	25,616
Inventories	84,827	71,861
Prepaid expenses and other	68,040	9,306
Derivatives	38,785	1,682
Total current assets	509,700	533,602
Property and equipment:
Oil and gas properties, net	3,444,864	2,310,973
Other property, net	14,837	6,855
Property and equipment, net	3,459,701	2,317,828
Other assets:
Equity method investment	51,896	236,514
Restricted cash	7,574	15,194
Long-term receivables - joint interest billings	19,002	34,941
Deferred financing costs, net of accumulated amortization of $12,065 and $13,951 at December 31, 2018 and December 31, 2017, respectively	8,937	2,510
Deferred tax assets	14,004	22,517
Derivatives	14,312	39
Other	3,063	29,458
Total assets	4,088,189	3,192,603
Current liabilities:
Accounts payable	176,540	141,787
Accrued liabilities	195,596	219,412
Derivatives	12,172	67,531
Total current liabilities	384,308	428,730
Long-term liabilities:
Long-term debt, net	2,120,547	1,282,797
Derivatives	10,181	30,209
Asset retirement obligations	145,336	66,595
Deferred tax liabilities	477,179	476,548
Other long-term liabilities	9,160	10,612
Total long-term liabilities	2,762,403	1,866,761
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2018 and December 31, 2017	0	0
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 442,914,675 and 398,599,457 issued at December 31, 2018 and December 31, 2017, respectively	4,429	3,986
Additional paid-in capital	2,341,249	2,014,525
Accumulated deficit	(1,167,193)	(1,073,202)
Treasury stock, at cost, 44,263,269 and 9,188,819 shares at December 31, 2018 and December 31, 2017, respectively	(237,007)	(48,197)
Total shareholders’ equity	941,478	897,112
Total liabilities and shareholders’ equity	$ 4,088,189	$ 3,192,603

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Deferred financing costs, accumulated amortization (in dollars)	$ 12,065	$ 13,951
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	442,914,675	398,599,457
Treasury stock shares	44,263,269	9,188,819

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues and other income:
Oil and gas revenue									$ 886,666	$ 578,139	$ 310,377
Gain on sale of assets									7,666	0	0
Other income, net									8,037	58,697	74,978
Total revenues and other income	$ 309,500	$ 250,219	$ 215,473	$ 127,177	$ 187,104	$ 151,242	$ 146,524	$ 151,966	902,369	636,836	385,355
Costs and expenses:
Oil and gas production									224,727	126,850	119,367
Facilities insurance modifications, net									6,955	(820)	14,961
Exploration expenses									301,492	216,050	202,280
General and administrative									99,856	68,302	87,623
Depletion and depreciation									329,835	255,203	140,404
Interest and other financing costs, net									101,176	77,595	44,147
Derivatives, net									(31,430)	59,968	48,021
(Gain) loss on equity method investments, net									(72,881)	6,252	0
Other expenses, net									(6,501)	5,291	23,116
Total costs and expenses	22,475	364,912	364,091	201,751	308,647	216,162	131,252	158,630	953,229	814,691	679,919
Loss before income taxes									(50,860)	(177,855)	(294,564)
Income tax expense (benefit)									43,131	44,937	(10,784)
Net loss	$ 185,565	$ (126,057)	$ (103,273)	$ (50,226)	$ (122,079)	$ (63,405)	$ (8,467)	$ (28,841)	$ (93,991)	$ (222,792)	$ (283,780)
Net loss per share:
Basic (in dollars per share)	$ 0.44	$ (0.31)	$ (0.26)	$ (0.13)	$ (0.31)	$ (0.16)	$ (0.02)	$ (0.07)	$ (0.23)	$ (0.57)	$ (0.74)
Diluted (in dollars per share)	$ 0.43	$ (0.31)	$ (0.26)	$ (0.13)	$ (0.31)	$ (0.16)	$ (0.02)	$ (0.07)	$ (0.23)	$ (0.57)	$ (0.74)
Weighted average number of shares used to compute net loss per share:
Basic (in shares)									404,585	388,375	385,402
Diluted (in shares)									404,585	388,375	385,402

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Treasury Stock
Balance (in shares) at Dec. 31, 2015		393,903
Balance at Dec. 31, 2015	$ 1,325,513	$ 3,939	$ 1,933,189	$ (564,686)	$ (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)	(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)	(48,197)
Increase (Decrease) in Shareholders' Equity
Acquisition of oil and gas properties (in shares)		34,994
Acquisition of oil and gas properties	307,944	$ 350	307,594
Equity-based compensation	36,464		36,464
Restricted stock awards and units (in shares)		9,322
Restricted stock awards and units	0	$ 93	(93)
Purchase of treasury stock	(206,051)		(17,241)		(188,810)
Net loss	(93,991)			(93,991)
Balance (in shares) at Dec. 31, 2018		442,915
Balance at Dec. 31, 2018	$ 941,478	$ 4,429	$ 2,341,249	$ (1,167,193)	$ (237,007)

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating activities
Net loss	$ (93,991)	$ (222,792)	$ (283,780)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization	339,214	265,407	150,608
Deferred income taxes	9,145	9,505	(23,561)
Unsuccessful well costs	123,199	43,201	6,079
Change in fair value of derivatives	(29,960)	71,822	46,559
Cash settlements on derivatives, net (including $(137.1) million and $38.7 million and $188.0 million on commodity hedges during 2018, 2017, and 2016)	(137,942)	25,888	188,895
Equity-based compensation	35,230	39,913	40,084
Gain on sale of assets	(7,666)	0	0
Loss on extinguishment of debt	4,324	0	0
Loss on equity method investment, net / (Undistributed equity in earnings)	(45)	6,252	0
Other	2,865	5,952	13,355
Changes in assets and liabilities:
(Increase) decrease in receivables	175,954	29,365	(20,558)
(Increase) decrease in inventories	8,848	1,653	(4,107)
(Increase) decrease in prepaid expenses and other	(18,731)	(31,710)	17,557
Increase (decrease) in accounts payable	7,440	(94,434)	(75,487)
Increase (decrease) in accrued liabilities	(157,393)	86,595	(3,567)
Net cash provided by operating activities	260,491	236,617	52,077
Investing activities
Oil and gas assets	(213,806)	(140,495)	(535,975)
Other property	(7,935)	(2,858)	(1,998)
Acquisition of oil and gas properties, net of cash acquired	(961,764)	0	0
Equity method investment	0	(231,280)	0
Return of investment from KTIPI	184,664	0	0
Proceeds on sale of assets	13,703	222,068	210
Net cash used in investing activities	(985,138)	(152,565)	(537,763)
Financing activities
Borrowings under long-term debt	1,175,000	200,000	450,000
Payments on long-term debt	(325,000)	(250,000)	0
Purchase of treasury stock / tax withholdings	(206,051)	(2,194)	(1,981)
Deferred financing costs	(38,672)	(67)	0
Net cash provided by (used in) financing activities	605,277	(52,261)	448,019
Net increase (decrease) in cash, cash equivalents and restricted cash	(119,370)	31,791	(37,667)
Cash, cash equivalents and restricted cash at beginning of period	185,616	304,986	273,195
Cash, cash equivalents and restricted cash at end of period	304,986	273,195	310,862
Cash paid for:
Interest, net of capitalized interest	83,831	55,381	27,860
Income taxes	45,984	48,815	13,997
Non-cash activity:
Conversion of joint interest billings receivable to long-term note receivable	0	0	9,814
Contribution to equity method investment	0	133,893	0
Dissolution of equity method investment	0	(122,407)	0
Common stock issued for acquisition of oil and gas properties	$ 307,944	$ 0	$ 0

Organization	12 Months Ended
Organization	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Kosmos Energy Ltd. changed its jurisdiction of incorporation from Bermuda to the State of Delaware (the "Redomestication") in December 2018. All outstanding common shares of Kosmos Energy Ltd., an exempted company incorporated pursuant to the laws of Bermuda, were automatically converted by operation of law, on a one-for-one basis, into shares of common stock of Kosmos Energy Ltd., a company incorporated pursuant to the laws of Delaware. The number of shares of the Company’s common stock outstanding immediately after the Redomestication was the same as the number of common shares of Kosmos Energy Ltd. outstanding immediately prior to the Redomestication. Kosmos Energy Ltd. was originally incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. As part of the Redomestication, we transferred all of our equity interests in Kosmos Energy Holdings to a new, wholly-owned subsidiary, Kosmos Energy Delaware Holdings, LLC, a Delaware limited liability company. 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 full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable exploration program balanced between proven basin infrastructure-led exploration (Equatorial Guinea and U.S. Gulf of Mexico), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Cote d'Ivoire, Namibia and Sao Tome and Principe). Kosmos is listed on the New York Stock Exchange (“NYSE”) and London Stock Exchange ("LSE") and is traded under the ticker symbol KOS. Kosmos is engaged in a single line of business, which is the exploration and production of oil and natural gas. We have operations in four geographic areas: Ghana, Equatorial Guinea, Mauritania/Senegal and the United States of America.

Accounting Policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

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 Company’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 Company are integral to the Company’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,
	2018		2017		2016
	(In thousands)
Cash and cash equivalents	$	173,515	$	233,412	$	194,057
Restricted cash - current	4,527		56,380		24,506
Restricted cash - long-term	7,574		15,194		54,632
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	185,616	$	304,986	$	273,195

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 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, 2018 and 2017, we had $4.5 million and $31.6 million, respectively, of current restricted cash and $7.4 million and $15.2 million, respectively, of long‑term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts. As of December 31, 2018, we also had $0.2 million in other long-term restricted cash.

In addition, prior to our reserves-based debt facility (the “Facility”) being amended and restated in February 2018, we were required to maintain a restricted cash balance that was sufficient to meet the payment of interest and fees for the next six‑month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver or the Facility, whichever was greater. As of December 31, 2017, we had $24.8 million in current restricted cash to meet this requirement. Under the amended and restated Facility, we are no longer required to maintain a restricted cash balance provided we are compliant with certain financial covenant ratios.

Receivables

Our receivables consist of joint interest billings, oil and gas sales, related party and other receivables. For our oil sales receivable in Ghana, 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 $1.2 million and zero in current joint interest billings receivables as of December 31, 2018 and 2017, respectively.

Inventories

Inventories consisted of $83.4 million (including $22.1 million acquired through the Deep Gulf Energy, (together with its subsidiaries "DGE") acquisition) and $63.5 million of materials and supplies and $1.4 million and $8.4 million of hydrocarbons as of December 31, 2018 and 2017, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded write downs of $0.3 million, $0.9 million and $14.9 million during the years ended December 31, 2018, 2017 and 2016 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 or in service 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 have used 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. 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. 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, 2018 and 2017, we had no oil and gas imbalances recorded in our consolidated financial statements.

Our oil and gas revenues are recognized when production has been sold to a purchaser at a fixed or determinable price, title has transferred and collectability is probable. Certain 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.

Oil and gas revenue is composed of the following:



	Years Ended December 31,
	2018			2017			2016

Revenues from contracts with customers - Ghana	$	741,033		$	590,642		$	307,837
Revenues from contracts with customers - U.S. Gulf of Mexico	147,596			—			—
Provisional oil sales contracts	(1,963		)	(12,503		)	2,540
Oil and gas revenue	$	886,666		$	578,139		$	310,377

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. In November 2018, Kosmos repurchased 35 million shares of our common stock from funds affiliated with Warburg Pincus LLC in a privately negotiated transaction at a price per share of $5.38. The total aggregate purchase price for the share repurchase was approximately $188 million. 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. As of December 2018, SAB 118 provisional period has expired and the Company has no further provisional amounts recorded in our financial statements.

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 international operations. For our U.S. Gulf of Mexico operations, crude oil and natural gas are transported to customers using third-party pipelines. For the year ended December 31, 2018, revenue from Phillips 66 Company made up approximately 11% of our total consolidated revenue and was included in our U.S. Gulf of Mexico segment.

Recent Accounting Standards

Recently Adopted

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company adopted the new standard during the first quarter of 2018 using the modified retrospective approach and there is no impact to our previously recorded revenue under the new standard.

In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740).” ASU 2018-05 was issued to include amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 ("SAB 118") and addresses certain circumstances that may arise for registrants in accounting for the income tax effects of the Tax Cut and Jobs Act (the "Tax Reform Act"), including when certain income tax effects of the Tax Reform Act are incomplete by the time the financial statements are issued. The Company adopted the new standard during the first quarter of 2018 and there was no material impact to our financial statements.

Not Yet Adopted

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. In July 2018, the FASB issued ASU 2018-11, which added a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required, and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. The Company intends to elect this transitional practical expedient.

In the normal course of business, the Company enters into various lease agreements for real estate and equipment related to its exploration, development and production activities that are currently accounted for as operating leases. The Company continues to evaluate contracts that exist as of the adoption date and performing the necessary calculations to determine the balance sheet impact. At this time, the Company cannot reasonably estimate the financial impact this will have on its consolidated financial statements; however, the Company believes adoption and implementation of this ASU will significantly impact its balance sheet, resulting in an increase in both assets and liabilities relating to its leasing activities.

Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Acquisitions and Divestitures

2018 Transactions

In March 2018, as part of our alliance with BP p.l.c ("BP"), we entered into petroleum contracts covering Blocks 10 and 13 with the Democratic Republic of Sao Tome and Principe. We presently have a 35% participating interest in the blocks and the operator, BP, holds a 50% participating interest. The national petroleum agency, Agencia Nacional Do Petroleo De Sao Tome E Principe ("ANP-STP") has a 15% carried interest in the blocks through exploration. The petroleum contracts cover approximately 13,600 square kilometers, with a first exploration period of four years from the effective date (March 2018). The exploration periods can be extended an additional four years at our election subject to fulfilling specific work obligations. The first exploration period work programs include a 13,500 square kilometer 3D seismic acquisition requirement across the two blocks.

In June 2018, we completed a farm-in agreement with a subsidiary of Ophir Energy plc ("Ophir") for Block EG-24, offshore Equatorial Guinea, whereby we acquired a 40% non-operated participating interest. As part of the agreement, we reimbursed a portion of Ophir's previously incurred exploration costs and will fully carry Ophir's share of the costs of a planned 3D seismic program as well as pay a disproportionate share of the well commitment should we enter the second exploration sub-period. The petroleum contract covers approximately 3,500 square kilometers, with a first exploration period of three years from the effective date (March 2018) which can be extended up to four additional years at our election subject to fulfilling specific work obligations. The first exploration period work program includes a 3,000 square kilometer 3D seismic acquisition requirement which was completed in November 2018. In January 2019, we entered into an agreement to acquire Ophir's remaining interest in the block, subject to customary governmental approvals, which will result in Kosmos owning an 80% interest in Block EG-24.

In September 2018, we completed the acquisition of DGE, a deepwater company operating in the U.S. Gulf of Mexico, from First Reserve Corporation and other shareholders for a total consideration of $1.275 billion, comprised of $952.6 million in cash, $307.9 million in Kosmos common stock and $14.9 million of transaction related costs. We funded the cash portion of the purchase price using cash on hand and drawings under our existing credit facilities. We also received $200.0 million of additional firm commitments under the Facility, which provided further liquidity to the Company. The DGE acquisition was accounted for under the asset acquisition method and the purchase price allocation is shown below. The purchase price allocation was based on the estimated relative fair value of identifiable assets acquired and liabilities assumed.

The estimated fair value measurements of oil and gas assets acquired and asset retirement obligations liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation. Significant inputs to the valuation of oil and gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future plugging and abandonment costs, (v) estimated future cash flows, and (vi) a market-based weighted average cost of capital rate.



	Purchase Price Allocation (in thousands)
Fair value of assets acquired:
Proved oil and gas properties	$	1,037,511
Unproved oil and gas properties	298,159
Accounts receivable and other	180,989
Total assets acquired	$	1,516,659

Fair value of liabilities assumed:
Accrued liabilities and other	$	126,530
Asset retirement obligations	74,482
Derivative liabilities	40,265
Total liabilities assumed	$	241,277

Purchase price:
Cash consideration paid	$	952,586
Fair value of common stock(1)	307,944
Transaction related costs	14,852
Total purchase price	$	1,275,382

______________________________________


(1)	Based on 34,993,585 shares of common stock issued at a price of $8.80 per share, which was the opening Kosmos common stock price on September 14, 2018, the closing date of the acquisition.

As a result of the DGE acquisition, we have included $147.6 million of revenues and $30.5 million of direct operating expenses in our consolidated statements of operations for the period from September 14, 2018 to December 31, 2018.

In October 2018, Kosmos entered into a strategic exploration alliance with Shell Exploration Company B.V. (“Shell”) to jointly explore in Southern West Africa. Initially the alliance will focus on Namibia where Kosmos has completed a farm-in to Shell's acreage in PEL 39, and Sao Tome and Principe where we have entered into exclusive negotiations for Shell to take an interest in Kosmos’ acreage in Blocks 5, 6, 11, and 12. As part of the alliance, the two companies will also jointly evaluate opportunities in adjacent geographies. This alliance is consistent with Kosmos’ strategy of partnering with supermajors to leverage complementary skill sets. Shell has deep expertise in carbonate plays, while Kosmos brings significant knowledge of the Cretaceous in West Africa. Furthermore, by working with Shell, Kosmos has a partner with the expertise to efficiently move exploration successes through the development stage.

2017 Transactions

In December 2016, we announced transactions with affiliates of 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 Kosmos BP Senegal Limited ("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 reimbursed Tullow a portion of past and interim period costs and will 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 was accounted for as an equity method investment. See Note 7—Equity Method Investments for further discussion of our investment in KTIPI.

In October 2017, we entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. We had an 80% participating interest and were the operator in all three blocks. In August 2018, we closed a farm-out agreement with Trident, whereby they acquired a 40% participating interest in blocks EG-21, S, and W, resulting in a $7.7 million gain. After giving effect to the farm-out agreement, we hold a 40% participating interest and remain the operator in all three blocks. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration period of five years from the effective date (March 2018). The first exploration period consists of two sub-periods of three and two years, respectively. The first exploration sub-period work program includes a 6,000 square kilometer 3D seismic acquisition requirement across the three blocks.

In December 2017, as part of our Alliance with BP, we entered into petroleum contracts covering Blocks CI-526, CI-602, CI-603, CI-707 and CI-708 with the Government of Cote d'Ivoire. We have a 45% participating interest and are the operator in all five blocks. BP has a 45% participating interest in the blocks and the Cote d'Ivoire national oil company, PETROCI Holding ("PETROCI"), currently has a 10% carried interest. The petroleum contracts cover approximately 17,000 square kilometers, with a first exploration period of three years. The first exploration period work program includes a 12,000 square kilometer 3D seismic acquisition across the five blocks.

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 funded 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 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 funded 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 August 2018, we provided to the Office National Des Hydrocarbures et des Mines ("ONHYM") a notice to abandon the Essaouira Offshore block, located offshore Morocco, at the end of the current exploration phase (November 2018).

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.

Joint Interest Billings and Related Party Receivables	12 Months Ended
Joint Interest Billings and Related Party Receivables	Dec. 31, 2018
Joint Interest Billings
Joint Interest Billings and Related Party Receivables	Joint Interest Billings and Related Party Receivables The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur. In 2014, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners of its request for the contractor group to pay GNPC’s 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners are being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of December 31, 2018 and 2017, the current portion of the joint interest billing receivables due from GNPC for the TEN fields development costs were $14.0 million and $15.2 million, respectively, and the long-term portion were $14.0 million and $31.6 million. The Company's related party receivables consists primarily of receivables from Trident who, until January 2019, owned a 50% interest in KTIPI. As of December 31, 2018 the balance due from Trident consists of $5.6 million related to joint interest billings for the exploration blocks and Kosmos' support of KTIPI operations.

Property and Equipment

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

Property and Equipment

Property and equipment is stated at cost and consisted of the following:



	December 31,
	2018			2017
	(In thousands)
Oil and gas properties:
Proved properties	$	2,773,276		$	1,653,616
Unproved properties	759,472			465,109
Support equipment and facilities	1,463,213			1,427,054
Total oil and gas properties	4,995,961			3,545,779
Accumulated depletion	(1,551,097		)	(1,234,806		)
Oil and gas properties, net	3,444,864			2,310,973

Other property	51,987			39,405
Accumulated depreciation	(37,150		)	(32,550		)
Other property, net	14,837			6,855

Property and equipment, net	$	3,459,701		$	2,317,828

We recorded depletion expense of $316.3 million, $244.9 million and $131.5 million and depreciation expense of $4.6 million, $3.4 million and $3.5 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Suspended Well Costs

12 Months Ended

Dec. 31, 2018

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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, 2018, 2017 and 2016. The table excludes $65.6 million, $43.2 million and $2.4 million in costs that were capitalized and subsequently expensed during the same year for the years ended December 31, 2018, 2017 and 2016, 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,
	2018			2017			2016
	(In thousands)
Beginning balance	$	410,113		$	734,463		$	426,881
Additions to capitalized exploratory well costs pending the determination of proved reserves	10,518			69,567			307,582
Additions associated with the acquisition of DGE	26,224			—			—
Reclassification due to determination of proved reserves(1)	(26,224		)	(176,881		)	—
Divestitures(2)	—			(206,400		)	—
Contribution of oil and gas property to equity method investment - KBSL	—			(131,764		)	—
Dissolution of equity method investment - KBSL	—			121,128			—
Capitalized exploratory well costs charged to expense(3)	(52,966		)	—			—
Ending balance	$	367,665		$	410,113		$	734,463

______________________________________


(1)	Represents the reclassification of Nearly Headless Nick well costs associated with the DGE acquisition in 2018 and inclusion of the Mahogany and Teak discoveries in the Jubilee Unit in 2017.


(2)	Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal transactions with BP


(3)	Primarily related to Akasa and Wawa as we wrote off $38.1 million and $13.6 million, respectively, of previously capitalized costs exploratory well costs to exploration expense during the third quarter of 2018. These impairments are included in our Ghana segment.

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,
	2018		2017		2016
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	—	$	67,159	$	279,809
Exploratory well costs capitalized for a period of one to two years	299,253		291,252		244,804
Exploratory well costs capitalized for a period of three years or longer	68,412		51,702		209,850
Ending balance	$	367,665	$	410,113	$	734,463
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	3		5		5

As of December 31, 2018, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Greater Tortue discovery which crosses the Mauritania and Senegal maritime border and 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.

Greater Tortue Ahmeyim Project — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania which encountered hydrocarbon pay. Two additional wells were drilled in the Greater Tortue Ahmeyim project 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 Ahmeyim project. Data acquired from the drill stem test was used to further optimize field development and to refine process design parameters critical to the FEED process. In December 2018, we made a final investment decision to develop the Greater Tortue Ahmeyim project.

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 is expected be made.

Yakaar and Teranga Discoveries — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. In June 2017, we completed the Yakaar-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. In November 2017, an integrated Yakaar-Teranga appraisal plan was submitted. An appraisal well is scheduled in 2019 to further evaluate the discovery. Following additional evaluation, a decision regarding commerciality is expected to be made.

Equity Method Investments

12 Months Ended

Dec. 31, 2018

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Kosmos BP Senegal Limited

As part of our transaction in Senegal with BP in February 2017, our participating interests in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks ("Senegal Blocks") were contributed to KBSL, a corporate joint venture in which we owned a 50.01% interest which was accounted for under the equity method of accounting.

In October 2017, KBSL transferred a 30% participating interest in the Senegal Blocks to BP Senegal Investments Limited in exchange for its outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and no longer is accounted for under the equity method of accounting. After the transfer, KBSL has a 30% working interest in the Senegal Blocks.

Our initial contribution to KBSL was $133.9 million, which was recorded at our carrying costs. Our share of losses in KBSL during the period it was accounted for as an equity method investment is reflected in our consolidated statements of operations as (Gain) loss on equity method investments, net. During the year ended December 31, 2017, we recognized $11.5 million related to our share of losses in KBSL.

Equatorial Guinea

As part of our acquisition of KTIPI, a corporate joint venture entity in which we owned a 50% interest, we acquired an indirect participating interest in Block G offshore Equatorial Guinea. The objective of this transaction was to acquire the Ceiba Field and Okume Complex with the intent to optimize production and increase reserves. Below is a summary of financial information for KTIPI.



	December 31,
	2018			2017
	(In thousands)
Assets
Total current assets	$	149,950		$	179,070
Property and equipment, net	271,627			345,611
Other assets	21			567
Total assets	$	421,598		$	525,248

Liabilities and shareholders' deficit
Total current liabilities	$	226,311		$	106,769
Total long term liabilities	536,178			565,591
Shareholders' deficit:
Total shareholders' deficit	(340,891		)	(147,112		)
Total liabilities and shareholders' deficit	$	421,598		$	525,248



	Year Ended December 31, 2018			Period November 28, 2017 through December 31, 2017
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	721,299		$	54,615
Other income	(477		)	294
Total revenues and other income	720,822			54,909

Costs and expenses:
Oil and gas production	147,685			15,509
Depletion and depreciation	126,983			10,738
Other expenses, net	429			(19		)
Total costs and expenses	275,097			26,228

Income before income taxes	445,725			28,681
Income tax expense	156,981			6,588
Net income	$	288,744		$	22,093

Kosmos' share of net income	$	144,372		$	11,046
Basis difference amortization(1)	71,491			5,812
Equity in earnings - KTIPI	$	72,881		$	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, 2018, we determined that we had the ability to recover the carrying amount of our equity method investment in KTIPI. As such, no impairment has been recorded. Our initial investment has been increased for our net share of equity in earnings as adjusted for our basis differential and reduced by cash dividends received. During the year ended December 31, 2018, we received $257.5 million of cash dividends from KTIPI.

With an effective date of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.375% undivided interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex will be accounted for under the proportionate consolidation method of accounting going forward.

Debt

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Debt



	December 31,
	2018			2017
	(In thousands)
Outstanding debt principal balances:
Facility	$	1,325,000		$	800,000
Corporate Revolver	325,000			—
Senior Notes	525,000			525,000
Total	2,175,000			1,325,000
Unamortized deferred financing costs and discounts(1)	(54,453		)	(42,203		)
Long-term debt, net	$	2,120,547		$	1,282,797

________________________________________


(1)	Includes $40.5 million and $23.6 million of unamortized deferred financing costs related to the Facility and $14.0 million and $18.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of December 31, 2018 and December 31, 2017, respectively.

Facility

In February 2018, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions with additional commitments up to $0.5 billion being available if the existing financial institutions increase their commitments or if commitments from new financial institutions are added. In November 2018, the Company exercised its option with existing financial institutions to provide the Company with an additional commitment of $100 million in the aggregate under the Facility. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of the debt refinancing in February 2018, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and $4.1 million of existing unamortized debt issuance costs and deferred interest attributable to those participants was expensed in interest and other financing costs, net. As of December 31, 2018, we have $40.5 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility. In December 2018, the Company entered into letter agreements with existing financial institutions, which provided the Company with an additional commitment of $100 million in the aggregate under the Facility effective January 31, 2019. This took the total commitments to $1.7 billion as of January 31, 2019.

As of December 31, 2018, borrowings under the Facility totaled $1,325.0 million and the undrawn availability under the Facility was $375.0 million, which includes the additional commitments as referenced above. 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. As part of the amendment and restatement process in February 2018, commitment fees were lowered from 40% to 30% 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.

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, 2018, 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, as amended. The borrowing base amount is based on the sum of the net present value 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, 2018 (the most recent assessment date).

Corporate Revolver

In August 2018, we amended and restated the Corporate Revolver maintaining the borrowing capacity at $400.0 million, extending the maturity date from November 2018 to May 2022 and lowering the margin 100 basis points to 5%. This resulted in lower commitment fees on the undrawn portion of the total commitments, which is 30% per annum of the respective margin. The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of December 31, 2018, we have $8.9 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term. These deferred financing costs are included in the Other assets section of our consolidated balance sheets.

As of December 31, 2018, borrowings under the Corporate Revolver totaled $325.0 million and the undrawn availability under the Corporate Revolver was $75.0 million.

Interest is the aggregate of the applicable margin (5.0%); 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 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 August 2018, expires on May 31, 2022. 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, 2018 (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 was $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. In July 2018 and December 2018, the LC Facility size was voluntarily reduced to $40.0 million and$20.0 million, respectively, based on the expiration of several large outstanding letters of credit. As of December 31, 2018, there were seven outstanding letters of credit totaling $14.4 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 wholly-owned 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, 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 our wholly-owned subsidiary, Kosmos Energy Holdings, pursuant to the terms of the Charge over Shares of Kosmos Energy Delaware Holdings, LLC dated as of December 20, 2018, among Kosmos Energy Delaware Holdings, LLC, Credit Agricole Corporate and Investment Bank, as Security and Intercreditor Agent, and Wilmington Trust, National Association, as Trustee to the Senior Notes. 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, 2018, the estimated repayments of debt during the five years and thereafter are as follows:



	Payments Due by Year
	Total		2019		2020		2021		2022		2023		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,175,000	$	—	$	—	$	685,600	$	614,100	$	305,100	$	570,200

(1)

Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015, borrowings under the Facility and the Corporate Revolver. The scheduled maturities of debt related to the Facility are based on, as of December 31, 2018, our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.

Interest and other financing costs, net

Interest and other financing costs, net incurred during the period comprised of the following:



	Years Ended December 31,
	2018			2017			2016
	(In thousands)
Interest expense	$	114,134		$	92,687		$	89,029
Amortization—deferred financing costs	9,379			10,204			10,204
Loss on extinguishment of debt	4,324			—			—
Capitalized interest	(28,331		)	(30,282		)	(59,803		)
Deferred interest	(1,138		)	2,577			(581		)
Interest income	(3,455		)	(3,422		)	(1,954		)
Other, net	6,263			5,831			7,252
Interest and other financing costs, net	$	101,176		$	77,595		$	44,147

Derivative Financial Instruments

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes.

We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820—Fair Value Measurements and Disclosures.

Oil Derivative Contracts

The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average prices per Bbl for those contracts as of December 31, 2018. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.



				Weighted Average Price per Bbl
Term	Type of Contract	Index	MBbl	Net Deferred Premium Payable/(Receivable)		Swap		Sold Put		Floor		Ceiling
2019:
January — December	Three-way collars	Dated Brent	10,500	$	1.17	$	—	$	43.81	$	53.33	$	73.58
January — December	Sold calls(1)	Dated Brent	913	—		—		—		—		80.00
January — December	Swaps	NYMEX WTI	1,747	—		52.31		—		—		—
January — June	Collars	NYMEX WTI	339	—		—		—		57.77		63.70
January — December	Collars	Argus LLS	1,000	—		—		—		60.00		88.75
2020:
January — December	Three-way collars	Dated Brent	2,000	$	—	$	—	$	50.00	$	60.00	$	90.54
January — December	Sold calls(1)(2)	Dated Brent	8,000	1.17		—		—		—		85.00

______________________________________


(1)	Represents call option contracts sold to counterparties to enhance other derivative positions.


(2)	Deferred premium payable to be paid January - December 2019.

In January and February 2019, we entered into three-way collar contracts for 2.0 MMBbl from January 2020 through December 2020 with a sold put price of $40.00 per barrel, a floor price of $55.00 per barrel and a ceiling price of $75.00 per barrel. The contracts are indexed to Dated Brent prices and have a net deferred premium payable of $2.5 million.

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, 2018 and 2017 and gain/(loss) from derivatives during the years ended December 31, 2018, 2017 and 2016.



		Estimated Fair Value Asset (Liability)
		December 31,
Type of Contract	Balance Sheet Location	2018			2017
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity(1)	Derivatives assets—current	$	38,785		$	665
Interest rate	Derivatives assets—current	—			1,017
Commodity(2)	Derivatives assets—long-term	14,312			39
Derivative liabilities:
Commodity(3)	Derivatives liabilities—current	(12,172		)	(67,531		)
Commodity(4)	Derivatives liabilities—long-term	(10,181		)	(30,209		)
Total derivatives not designated as hedging instruments		$	30,744		$	(96,019	)

______________________________________


(1)	Includes $0.4 million and zero as of December 31, 2018 and December 31, 2017, respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of $1.6 million and net deferred premiums receivable of $0.8 million related to commodity derivative contracts as of December 31, 2018 and 2017, respectively.


(2)	Includes net deferred premiums payable of $1.3 million and net deferred premiums receivable of $0.1 million related to commodity derivative contracts as of December 31, 2018 and 2017, respectively.


(3)	Includes net deferred premiums payable of $18.0 million and $5.6 million related to commodity derivative contracts as of December 31, 2018 and 2017, respectively.


(4)	Includes net deferred premiums payable of $0.5 million and $4.8 million related to commodity derivative contracts as of December 31, 2018 and 2017, respectively.



		Amount of Gain/(Loss)
		Years Ended December 31,
Type of Contract	Location of Gain/(Loss)	2018			2017			2016
		(In thousands)
Derivatives not designated as hedging instruments:
Commodity(1)	Oil and gas revenue	$	(1,963	)	$	(12,502	)	$	2,538
Commodity	Derivatives, net	31,430			(59,968		)	(48,021		)
Interest rate	Interest expense	493			648			(1,076		)
Total derivatives not designated as hedging instruments		$	29,960		$	(71,822	)	$	(46,559	)

______________________________________


(1)	Amounts represent the change in fair value of our provisional oil sales contracts.

Offsetting of Derivative Assets and Derivative Liabilities

Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of December 31, 2018 and 2017, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.

Fair Value Measurements

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

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, 2018 and 2017, 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, 2018
Assets:
Commodity derivatives	$	—	$	53,097		$	—	$	53,097
Liabilities:
Commodity derivatives	—		(22,353		)	—		(22,353		)
Total	$	—	$	30,744		$	—	$	30,744
December 31, 2017
Assets:
Commodity derivatives	$	—	$	704		$	—	$	704
Interest rate derivatives	—		1,017			—		1,017
Liabilities:
Commodity derivatives	—		(97,740		)	—		(97,740		)
Total	$	—	$	(96,019	)	$	—	$	(96,019	)

The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales, related party 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, NYMEX WTI or Argus LLS oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for the respective index, (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 the respective index. 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 the respective index over the term of the pricing period designated in the sales contract and the spot price on the lifting date.

Interest Rate Derivatives

Our interest rate derivatives consisted of interest rate swaps, whereby the Company paid a fixed rate of interest and the counterparty paid a variable LIBOR‑based rate, and capped interest rate swaps, whereby the Company paid a fixed rate of interest if LIBOR is below the cap, and paid 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 were 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, 2018 and 2017:



	December 31, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Senior Notes	$	511,873	$	525,026	$	507,600	$	542,472
Corporate Revolver	325,000		325,000		—		—
Facility	1,325,000		1,325,000		800,000		800,000
Total	$	2,161,873	$	2,175,026	$	1,307,600	$	1,342,472

The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

The following table summarizes the changes in the Company’s asset retirement obligations:



	December 31,
	2018			2017
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	66,595		$	63,574
Additions associated with the acquisition of DGE	74,482			—
Liabilities incurred during period	5,311			—
Liabilities settled during period	(3,345		)	—
Revisions in estimated retirement obligations	—			(3,945		)
Accretion expense	8,910			6,966
Ending asset retirement obligations	$	151,953		$	66,595

The asset retirement obligations reflect the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our oil and gas properties. The Company utilizes current cost experience to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and gas property balance.

Equity-based Compensation

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity-based Compensation

Equity‑based Compensation

Restricted Stock Awards and Restricted Stock Units

Our Long-Term Incentive Plan ("LTIP") 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 2018 and January 2015, the board of directors approved amendments to the plan which added 11.0 million and 15.0 million shares, respectively, to the plan which were approved at the corresponding Annual General Meeting. The LTIP as amended provides for the issuance of 50.5 million shares pursuant to awards under the plan. As of December 31, 2018, the Company had approximately 15.2 million shares that remain available for issuance under the LTIP.

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 $35.2 million, $40.0 million and $40.1 million during the years ended December 31, 2018, 2017 and 2016, respectively. The total tax benefit for the years ended December 31, 2018, 2017 and 2016 was $6.6 million, $13.2 million and $13.0 million, respectively. Additionally, we expensed a net tax shortfall (windfall) related to equity‑based compensation of $(0.4) million, $3.1 million and $5.5 million for the years ended December 31, 2018, 2017 and 2016, respectively. The fair value of awards vested during 2018, 2017 and 2016 was approximately $85.1 million, $21.2 million, and $14.4 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 a three year period. 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, 2018:



	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, 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		—		—
Granted	—		—		—		—
Forfeited	—		—		—		—
Vested	(220	)	8.64		—		—
Outstanding at December 31, 2018:	—		—		—		—

The following table reflects the outstanding restricted stock units as of December 31, 2018:



	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, 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
Granted	2,402		7.07		8,111		12.38
Forfeited	(229	)	6.40		(302	)	8.95
Vested	(2,241	)	6.95		(9,545	)	13.75
Outstanding at December 31, 2018:	4,115		6.42		6,716		9.02

As of December 31, 2018, total equity‑based compensation to be recognized on unvested restricted stock units is $33.9 million over a weighted average period of 2.0 years.

For restricted stock units with a combination of market and service vesting criteria, the number of shares of common stock 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 200% of the awards granted. The grant date fair value ranged from $4.83 to $15.71 per award. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 44.0% to 53.0%. The risk‑free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant ranged from 0.7% to 2.2% for restricted stock units.

In January 2019, we granted 2.6 million service vesting restricted stock units and 2.8 million market and service vesting restricted stock units to our employees under our long-term incentive plan. We expect to recognize approximately $32.0 million of non-cash compensation expense related to these grants over the next three years.

Income Taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Taxes

Kosmos Energy Ltd. changed its jurisdiction of incorporation from Bermuda to the State of Delaware in December 2018. The company was not subject to taxation at the parent company level for the years ended December 31, 2017 and 2016. 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.

SAB 118 was issued in January 2018 to address situations where certain aspects of the Tax Reform Act are unclear at issuance of the registrant’s financial statements for the reporting period in which the Jobs Act became law. SAB 118 allowed us to record provisional amounts during a one-year measurement period that ended in December 2018. As of December 31, 2018, there are no provisional tax amounts recorded in our financial statements.

The components of loss before income taxes were as follows:



	Years Ended December 31,
	2018			2017			2016
	(In thousands)
United States	$	41,026		$	6,068		$	5,083
Bermuda	(73,979		)	(66,914		)	(63,749		)
Foreign—other	(17,907		)	(117,009		)	(235,898		)
Loss before income taxes	$	(50,860	)	$	(177,855	)	$	(294,564	)

The components of the provision for income taxes attributable to our income (loss) before income taxes consist of the following:



	Years Ended December 31,
	2018		2017			2016
	(In thousands)
Current:
United States	$	122	$	10,976		$	12,675
Bermuda	—		—			—
Foreign—other	33,864		24,456			102
Total current	33,986		35,432			12,777
Deferred:
United States	8,514		15,310			(3,594		)
Bermuda	—		—			—
Foreign—other	631		(5,805		)	(19,967		)
Total deferred	9,145		9,505			(23,561		)
Income tax expense (benefit)	$	43,131	$	44,937		$	(10,784	)

Our reconciliation of income tax expense (benefit) computed by applying our statutory rate and the reported effective tax rate on loss from continuing operations is as follows:



	Years Ended December 31,
	2018			2017			2016
	(In thousands)
Tax at statutory rate(1)	$	(10,681	)	$	—		$	—
Foreign income (loss) taxed at different rates	5,013			9,381			(57,898		)
Net non-taxable expense / insurance recoveries	3,256			(30		)	8,694
West Leo arbitration settlement	(2,834		)	1,736			1,098
Non-deductible compensation	2,643			1,680			1,999
Deferred tax liability - undistributed earnings	(2,565		)	2,565			—
Non-deductible and other items	656			3,790			556
Equity earnings - net of tax	(15,305		)	—			—
Tax shortfall (windfall) on equity-based compensation, net	(387		)	3,086			5,504
Change in valuation allowance	63,335			6,008			29,263
Change in U.S. tax rate	—			16,721			—
Total tax expense (benefit)	$	43,131		$	44,937		$	(10,784	)
Effective tax rate(2)	85		%	25		%	4		%

______________________________________

(1)

On December 28, 2018, we changed our jurisdiction of incorporation from Bermuda to the State of Delaware. Kosmos Energy Ltd. discontinued as a Bermuda exempted company pursuant to Section 132G of the Companies Act 1981 of Bermuda and, pursuant to Section 265 of the General Corporation Law of the State of Delaware (the “DGCL”), continued its existence under the DGCL as a corporation organized in the State of Delaware. As a result, the statutory tax rate for the 2018 reconciliation of income tax expense is the U.S. statutory tax rate of 21%. Our 2017 and 2016 reconciliation of income tax expense is based on the Bermuda statutory tax rate of 0%.


(2)	The effective tax rate during the years ended December 31, 2018, 2017 and 2016 were impacted by losses of $261.2 million, $164.4 million and $121.4 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 84%, 433% and 179% for the years ended December 31, 2018, 2017 and 2016, respectively. The effective tax rate in the United States is impacted by the effect the sum of non-deductible expenditures and 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 36%, 49% and 23% for the years ended December 31, 2018, 2017 and 2016, 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,
	2018			2017
	(In thousands)
Deferred tax assets:
Foreign capitalized operating expenses	$	128,809		$	68,218
Foreign net operating losses	28,050			25,307
United States net operating losses	59,336			—
Equity compensation	11,408			20,783
Unrealized derivative losses	—			33,963
Asset retirement obligation and other	29,450			24,784
Total deferred tax assets	257,053			173,055
Valuation allowance	(156,860		)	(93,525		)
Total deferred tax assets, net	100,193			79,530
Deferred tax liabilities:
Depletion, depreciation and amortization related to property and equipment	(547,389		)	(533,561		)
Unrealized derivative gains	(15,979		)	—
Total deferred tax liabilities	(563,368		)	(533,561		)
Net deferred tax liability	$	(463,175	)	$	(454,031	)

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 $103.0 million. Of these losses, we expect $0.9 million, $0.5 million, $0.5 million, $0.6 million, $0.7 million, $15.0 million and $0.1 million to expire in 2019, 2020, 2021, 2022, 2023, 2029 and 2030, respectively, and $84.7 million do not expire. All of these losses currently have offsetting valuation allowances. The Company has $282.5 million of United States net operating loss that will not expire.

The Company will file a 2018 U.S. federal income tax return during 2019. A subsidiary of the Company is open to U.S. federal income tax examinations for tax years 2015 through 2017 and to Texas margin tax examinations for the tax years 2014 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, 2018, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense.

Net Income (Loss) Per Share

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

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 shares of common stock or resulted in the issuance of shares of common stock 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 shares of common stock 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,
	2018			2017			2016
	(In thousands, except per share data)
Numerator:
Net loss allocable to common stockholders(1)	$	(93,991	)	$	(222,792	)	$	(283,780	)
Denominator:
Weighted average number of shares outstanding:
Basic	404,585			388,375			385,402
Restricted stock awards and units(1)(2)	—			—			—
Diluted	404,585			388,375			385,402
Net loss per share:
Basic	$	(0.23	)	$	(0.57	)	$	(0.74	)
Diluted	$	(0.23	)	$	(0.57	)	$	(0.74	)

______________________________________

(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 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 share calculation in periods we are in a net loss position. All restricted stock awards were fully vested in January 2018.


(2)	For the years ended December 31, 2018, 2017 and 2016, we excluded 10.6 million, 12.9 million and 11.8 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

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

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 redetermined tract participations. Our unit interest may change in the future should another redetermination occur.

The Company leases facilities under various operating leases that fully expire through 2027, including our office space. Rent expense under these agreements, was $4.7 million, $3.3 million and $3.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.

We currently have a commitment to drill one exploration well in Mauritania and Namibia and two exploration wells in Senegal. Our partner is obligated to fund our share of the cost of the exploration wells, subject to the remaining exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Sao Tome and Principe, we have a 3D seismic requirement of approximately 13,500 square kilometers.

Future minimum rental commitments under our leases at December 31, 2018, are as follows:



	Payments Due By Year(1)
	Total		2019		2020		2021		2022		2023		Thereafter
	(In thousands)
Operating leases(2)	$	36,508	$	2,775	$	4,173	$	3,276	$	3,326	$	3,376	$	19,582

______________________________________


(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 office leases.

Performance Obligations

As of December 31, 2018, the Company had secured performance bonds totaling $200.9 million for our supplemental bonding requirements stipulated by the Bureau of Ocean Energy Management ("BOEM") and $3.7 million to another operator related to costs anticipated for the plugging and abandonment of certain wells and the removal of certain facilities in its U.S. Gulf of Mexico fields. As of December 31, 2018, we had $0.6 million of cash collateral against these secured performance bonds which is classified as Other long term assets in our consolidated balance sheet.

In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal which obligate us separately to finance the respective national oil company’s share of certain development costs. Kosmos’ total share for the two agreements combined is up to $239.7 million, which is to be repaid through the national oil companies’ share of future revenues.

On February 25, 2019, we announced our quarterly cash dividend of $0.0452 per common share. The dividend is payable on March 28, 2019 to stockholders of record on March 7, 2019.

Additional Financial Information

12 Months Ended

Dec. 31, 2018

Additional Financial Information

Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:



	December 31,
	2018		2017
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	92,613	$	144,717
Current asset retirement obligations	6,617		—
General and administrative expenses	39,373		31,124
Interest	18,152		20,457
Income taxes	8,958		17,423
Taxes other than income	4,613		3,270
Derivatives	441		—
Revenue payable	24,379		—
Other	450		2,421
	$	195,596	$	219,412

Gain on sale of assets

During the year ended December 31, 2018, we recognized a $7.7 million gain related to the farm-out of Blocks EG-21, S, and W offshore Equatorial Guinea to Trident.

Other Income, net

Other income, net which includes Loss of Production Income (“LOPI”) payments, consisted of zero, $58.7 million and $74.8 million for the years ended December 31, 2018, 2017 and 2016, respectively. Our LOPI coverage for the turret bearing issue on the Jubilee FPSO ended in May 2017.

Oil and Gas Production

Oil and gas production expense included insurance recoveries related to our increased cost of working covered by our LOPI policy of zero, $17.1 million, and $7.5 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Facilities Insurance Modifications, net

Facilities insurance modifications, net consists of costs associated with the long-term solution to convert the Jubilee FPSO to a permanently spread moored facility, net of any insurance reimbursements.

Other Expenses, net

Other expenses, net incurred during the period is comprised of the following:



	Years Ended December 31,
	2018			2017			2016
	(In thousands)
Loss on disposal of inventory	$	280		$	866		$	14,900
Gain on insurance settlements	—			(461		)	(4,003		)
Disputed charges and related costs, net of recoveries	(9,753		)	4,962			11,299
Other, net	2,972			(76		)	920
Other expenses, net	$	(6,501	)	$	5,291		$	23,116

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 charged such expenditures to the Deepwater Tano (“DT”) joint account. Kosmos disputed through arbitration that these expenditures were chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement. In July 2018, the International Chamber of Commerce ("ICC") issued its Final Award in the arbitration in favor of Kosmos. As a result, we recovered from Tullow Ghana Limited disputed charges in the amount of $12.9 million in the form of cash payments and offsets against other unrelated joint venture costs, which include amounts previously paid under protest as well as certain costs and fees incurred pursuing the arbitration.

Business Segment Information

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

Business Segment Information

Kosmos is engaged in a single line of business, which is the exploration and development of oil and gas. At December 31, 2018, the Company had operations in four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the United States. To assess performance of the reporting segments, the Chief Operating Decision Maker ("CODM") reviews capital expenditures. Capital expenditures, as defined by the Company, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with our consolidated financial statements and notes thereto. Financial information for each area is presented below:



	Ghana			Equatorial Guinea(1)			Mauritania/Senegal			United States(2)			Corporate & Other			Eliminations(3)			Total
	(in thousands)
Year ended December 31, 2018
Revenues and other income:
Oil and gas revenue	$	739,070		$	360,649		$	—		$	147,596		$	—		$	(360,649	)	$	886,666
Gain on sale of assets	—			7,666			—			—			—			—			7,666
Other income, net	(17		)	(238		)	—			11			150,635			(142,354		)	8,037
Total revenues and other income	739,053			368,077			—			147,607			150,635			(503,003		)	902,369
Costs and expenses:
Oil and gas production	189,104			73,843			—			30,470			5,153			(73,843		)	224,727
Facilities insurance modifications, net	6,955			—			—			—			—			—			6,955
Exploration expenses	58,276			38,164			7,262			66,962			131,180			(352		)	301,492
General and administrative	19,342			5,351			5,220			10,534			168,542			(109,133		)	99,856
Depletion and depreciation	265,805			134,983			61			59,835			4,134			(134,983		)	329,835
Interest and other financing costs, net(4)	86,738			(12		)	(25,386		)	7,487			39,483			(7,134		)	101,176
Derivatives, net	—			—			—			(57,615		)	26,185			—			(31,430		)
(Gain) loss on equity method investments, net	—			—			—			—			—			(72,881		)	(72,881		)
Other expenses, net	16,414			(814		)	(23		)	598			3,510			(26,186		)	(6,501		)
Total costs and expenses	642,634			251,515			(12,866		)	118,271			378,187			(424,512		)	953,229
Loss before income taxes	96,419			116,562			12,866			29,336			(227,552		)	(78,491		)	(50,860		)
Income tax expense (benefit)	34,494			78,491			—			6,163			2,474			(78,491		)	43,131
Net loss	$	61,925		$	38,071		$	12,866		$	23,173		$	(230,026	)	$	—		$	(93,991	)

Consolidated capital expenditures	$	105,942		$	32,156		$	11,962		$	95,993		$	139,381		$	—		$	385,434

As of December 31, 2018
Property and equipment, net	$	1,698,194		$	3,919		$	411,448		$	1,308,670		$	37,470		$	—		$	3,459,701
Total assets	$	1,930,071		$	55,302		$	536,620		$	3,512,989		$	10,349,488		$	(12,296,281	)	$	4,088,189

______________________________________


(1)	Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion and depreciation for the year ended December 31, 2018, except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments.


(2)	Represents activity commencing September 14, 2018, the DGE acquisition date.


(3)	Includes elimination of proportionate consolidation amounts recorded for KTIPI to reconcile to (Gain) loss on equity method investments, net as reported in the consolidated statements of operations.


(4)	Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.



	Ghana			Equatorial Guinea(1)		Mauritania/Senegal			United States		Corporate & Other			Eliminations(2)			Total
	(in thousands)
Year ended December 31, 2017
Revenues and other income:
Oil and gas revenue	$	578,139		$	27,308	$	—		$	—	$	—		$	(27,308	)	$	578,139
Gain on sale of assets	—			—		—			—		—			—			—
Other income, net	5			147		—			—		$	219,968		(161,423		)	58,697
Total revenues and other income	578,144			27,455		—			—		219,968			(188,731		)	636,836
Costs and expenses:
Oil and gas production	137,584			7,755		—			—		(10,734		)	(7,755		)	126,850
Facilities insurance modifications, net	(820		)	—		—			—		—			—			(820		)
Exploration expenses	394			86		71,456			—		144,114			—			216,050
General and administrative	14,836			672		8,298			—		138,661			(94,165		)	68,302
Depletion and depreciation	251,890			11,181		20			—		3,293			(11,181		)	255,203
Interest and other financing costs, net(3)	71,592			—		(16,065		)	—		29,202			(7,134		)	77,595
Derivatives, net	—			—		—			—		59,968			—			59,968
Loss on equity method investments, net	—			—		11,486			—		—			(5,234		)	6,252
Other expenses, net	64,768			—		867			—		(376		)	(59,968		)	5,291
Total costs and expenses	540,244			19,694		76,062			—		364,128			(185,437		)	814,691
Income (loss) before income taxes	37,900			7,761		(76,062		)	—		(144,160		)	(3,294		)	(177,855		)
Income tax expense (benefit)	18,649			3,294		3			—		26,285			(3,294		)	44,937
Net income (loss)	$	19,251		$	4,467	$	(76,065	)	$	—	$	(170,445	)	$	—		$	(222,792	)

Consolidated capital expenditures	$	5,545		$	1,995	$	(80,929	)	$	—	$	130,821		$	—		$	57,432

As of December 31, 2017
Property and equipment, net	$	1,901,127		$	1,908	$	381,422		$	—	$	33,371		$	—		$	2,317,828
Total assets	$	2,263,824		$	237,835	$	570,044		$	—	$	8,671,437		$	(8,550,537	)	$	3,192,603

______________________________________


(1)	Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion and depreciation for the year ended December 31, 2017, except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments.


(2)	Includes elimination of proportionate consolidation amounts recorded for KTIPI to reconcile to (Gain) loss on equity method investments, net as reported in the consolidated statements of operations.


(3)	Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.



	Ghana			Equatorial Guinea			Mauritania/Senegal			United States		Corporate & Other			Eliminations			Total
	(in thousands)
Year ended December 31, 2016
Revenues and other income:
Oil and gas revenue	$	310,377		$	—		$	—		$	—	$	—		$	—		$	310,377
Gain on sale of assets	—			—			—			—		—			—			—
Other income, net	7			—			—			—		$	227,101		(152,130		)	74,978
Total revenues and other income	310,384			—			—			—		227,101			(152,130		)	385,355
Costs and expenses:
Oil and gas production	121,329			—			—			—		(1,962		)	—			119,367
Facilities insurance modifications, net	14,961			—			—			—		—			—			14,961
Exploration expenses	1,211			9			63,186			—		137,874			—			202,280
General and administrative	9,490			—			21,530			—		153,577			(96,974		)	87,623
Depletion and depreciation	137,094			—			97			—		3,213			—			140,404
Interest and other financing costs, net(1)	45,403			—			(22,404		)	—		28,282			(7,134		)	44,147
Derivatives, net	—			—			—			—		48,021			—			48,021
Loss on equity method investments, net	—			—			—			—		—			—			—
Other expenses, net	67,793			—			454			—		2,890			(48,021		)	23,116
Total costs and expenses	397,281			9			62,863			—		371,895			(152,129		)	679,919
Income (loss) before income taxes	(86,897		)	(9		)	(62,863		)	—		(144,794		)	(1		)	(294,564		)
Income tax expense (benefit)	(19,866		)	—			—			—		9,082			—			(10,784		)
Net income (loss)	$	(67,031	)	$	(9	)	$	(62,863	)	$	—	$	(153,876	)	$	(1	)	$	(283,780	)

Consolidated capital expenditures	$	221,294		$	9		$	283,442		$	—	$	139,765		$	—		$	644,510

As of December 31, 2016
Property and equipment, net	$	2,129,873		$	—		$	529,071		$	—	$	49,948		$	—		$	2,708,892
Total assets	$	2,484,497		$	(3	)	$	551,250		$	—	$	8,205,043		$	(7,899,322	)	$	3,341,465

______________________________________


(1)	Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.



	Years Ended December 31,
	2018			2017			2016
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	213,806		$	140,495		$	535,975
Other property	7,935			2,858			1,998
Adjustments:
Changes in capital accruals	27,317			(6,337		)	(25,875		)
Exploration expense, excluding unsuccessful well costs(1)	178,293			172,849			196,201
Capitalized interest	(28,331		)	(30,282		)	(59,803		)
Proceeds on sale of assets	(13,703		)	(222,068		)	(210		)
Other	117			(83		)	(3,776		)
Total consolidated capital expenditures	$	385,434		$	57,432		$	644,510

______________________________________


(1)	Unsuccessful well costs are included in oil and gas assets when incurred.

Supplemental Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Supplemental Quarterly Financial Information (Unaudited)



	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	(In thousands, except per share data)
2018
Revenues and other income	$	127,177		$	215,473		$	250,219		$	309,500
Costs and expenses	201,751			364,091			364,912			22,475
Net income (loss)	(50,226		)	(103,273		)	(126,057		)	185,565
Net income (loss) per share:
Basic(1)	(0.13		)	(0.26		)	(0.31		)	0.44
Diluted(1)	(0.13		)	(0.26		)	(0.31		)	0.43
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		)

_______________________________


(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 Company Financial Statements

12 Months Ended

Dec. 31, 2018

Condensed Financial Information 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 2018, 2017 and 2016 (collectively “KEL,” the “Parent Company”), such subsidiaries may be 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,
	2018			2017
Assets
Current assets:
Cash and cash equivalents	$	6,776		$	297
Receivables from subsidiaries	2,890			—
Note receivable from subsidiary	7,941			—
Prepaid expenses and other	313			290
Total current assets	17,920			587
Investment in subsidiaries at equity	1,432,468			1,419,890
Long-term note receivable from subsidiary	607,943			—
Deferred financing costs, net of accumulated amortization of $12,065 and $13,951 at December 31, 2018 and December 31, 2017, respectively	8,937			2,510
Restricted cash	305			—
Long-term deferred tax asset	(1,132		)	—
Total assets	$	2,066,441		$	1,422,987
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable	$	975		$	4
Accounts payable to subsidiaries	—			332
Accrued liabilities	18,972			19,128
Total current liabilities	19,947			19,464
Long-term debt	836,016			506,411
Long-term note payable to subsidiary	269,000			—
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2018 and December 31, 2017	—			—
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 442,914,675 and 398,599,457 issued at December 31, 2018 and December 31, 2017, respectively	4,429			3,986
Additional paid-in capital	2,341,249			2,014,525
Accumulated deficit	(1,167,193		)	(1,073,202		)
Treasury stock, at cost, 44,263,269 and 9,188,819 shares at December 31, 2018 and December 31, 2017, respectively	(237,007		)	(48,197		)
Total shareholders’ equity	941,478			897,112
Total liabilities and shareholders’ equity	$	2,066,441		$	1,422,987

CONDENSED PARENT COMPANY STATEMENTS OF OPERATIONS

(In thousands)



	Years Ended December 31,
	2018			2017			2016
Revenues and other income:
Oil and gas revenue	$	—		$	—		$	—
Total revenues and other income	—			—			—
Costs and expenses:
General and administrative	47,279			51,544			48,542
General and administrative recoveries—related party	(36,197		)	(40,266		)	(40,047		)
Interest and other financing costs, net	66,055			55,596			55,253
Interest and other financing costs, net—related party	(7,941		)	—			—
Other expenses, net	49			40			1
Equity in losses of subsidiaries	23,614			155,878			220,031
Total costs and expenses	92,859			222,792			283,780
Loss before income taxes	(92,859		)	(222,792		)	(283,780		)
Income tax expense	1,132			—			—
Net loss	$	(93,991	)	$	(222,792	)	$	(283,780	)

CONDENSED PARENT COMPANY STATEMENTS OF CASH FLOWS

(In thousands)



	Years Ended December 31,
	2018			2017			2016
Operating activities
Net loss	$	(93,991	)	$	(222,792	)	$	(283,780	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in losses of subsidiaries	23,614			155,878			220,031
Equity-based compensation	35,230			39,913			40,423
Amortization	7,292			3,070			3,070
Deferred income taxes	1,132			—			—
Other	268			3,884			3,530
Changes in assets and liabilities:
Decrease in receivables	1,234			986			—
(Increase) decrease in prepaid expenses and other	(23		)	127			52
(Increase) decrease due to/from related party	(42,163		)	14,463			(15,201		)
Increase in accounts payable and accrued liabilities	816			1,179			312
Net cash provided by (used in) operating activities	(66,591		)	(3,292		)	(31,563		)
Investing activities
Investment in subsidiaries	(36,192		)	4,691			(40,047		)
Net cash provided by (used in) investing activities	(36,192		)	4,691			(40,047		)
Financing activities
Borrowings under long-term debt	400,000			—			—
Payments on long-term debt	(75,000		)
Purchase of treasury stock	(206,051		)	(2,194		)	(1,981		)
Deferred financing costs	(9,382		)	—			—
Net cash provided by (used in) financing activities	109,567			(2,194		)	(1,981		)
Net increase (decrease) in cash and cash equivalents	6,784			(795		)	(73,591		)
Cash, cash equivalents and restricted cash at beginning of period	297			1,092			74,683
Cash, cash equivalents and restricted cash at end of period	$	7,081		$	297		$	1,092

Non-cash activity:
Issuance of common stock for related party receivable	$	307,944		$	—		$	—

Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Principles of Consolidation

Use of Estimates

Reclassifications

Cash, Cash Equivalents and Restricted Cash



	December 31,
	2018		2017		2016
	(In thousands)
Cash and cash equivalents	$	173,515	$	233,412	$	194,057
Restricted cash - current	4,527		56,380		24,506
Restricted cash - long-term	7,574		15,194		54,632
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	185,616	$	304,986	$	273,195

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.

Receivables

Inventories

Exploration and Development Costs

Depletion, Depreciation and Amortization



	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

Asset Retirement Obligations

Impairment of Long-lived Assets

Impairment of Long‑lived Assets

Derivative Instruments and Hedging Activities

Estimates of Proved Oil and Natural Gas Reserves


•	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

Equity-based Compensation

Equity‑based Compensation

Treasury Stock

Income Taxes

Foreign Currency Translation

Concentration of Credit Risk

Recent Accounting Standards

Recently Adopted

Not Yet Adopted

Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Schedule of cash and cash equivalents



	December 31,
	2018		2017		2016
	(In thousands)
Cash and cash equivalents	$	173,515	$	233,412	$	194,057
Restricted cash - current	4,527		56,380		24,506
Restricted cash - long-term	7,574		15,194		54,632
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	185,616	$	304,986	$	273,195

Schedule of estimated useful lives of other property



	Years Depreciated
Leasehold improvements	1 to 8
Office furniture, fixtures and computer equipment	3 to 7
Vehicles	5

Schedule of oil and gas revenue

Oil and gas revenue is composed of the following:



	Years Ended December 31,
	2018			2017			2016

Revenues from contracts with customers - Ghana	$	741,033		$	590,642		$	307,837
Revenues from contracts with customers - U.S. Gulf of Mexico	147,596			—			—
Provisional oil sales contracts	(1,963		)	(12,503		)	2,540
Oil and gas revenue	$	886,666		$	578,139		$	310,377

Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]



	Purchase Price Allocation (in thousands)
Fair value of assets acquired:
Proved oil and gas properties	$	1,037,511
Unproved oil and gas properties	298,159
Accounts receivable and other	180,989
Total assets acquired	$	1,516,659

Fair value of liabilities assumed:
Accrued liabilities and other	$	126,530
Asset retirement obligations	74,482
Derivative liabilities	40,265
Total liabilities assumed	$	241,277

Purchase price:
Cash consideration paid	$	952,586
Fair value of common stock(1)	307,944
Transaction related costs	14,852
Total purchase price	$	1,275,382

______________________________________


(1)	Based on 34,993,585 shares of common stock issued at a price of $8.80 per share, which was the opening Kosmos common stock price on September 14, 2018, the closing date of the acquisition.

Suspended Well Costs (Tables)

12 Months Ended

Dec. 31, 2018

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of capitalized exploratory well costs



	Years Ended December 31,
	2018			2017			2016
	(In thousands)
Beginning balance	$	410,113		$	734,463		$	426,881
Additions to capitalized exploratory well costs pending the determination of proved reserves	10,518			69,567			307,582
Additions associated with the acquisition of DGE	26,224			—			—
Reclassification due to determination of proved reserves(1)	(26,224		)	(176,881		)	—
Divestitures(2)	—			(206,400		)	—
Contribution of oil and gas property to equity method investment - KBSL	—			(131,764		)	—
Dissolution of equity method investment - KBSL	—			121,128			—
Capitalized exploratory well costs charged to expense(3)	(52,966		)	—			—
Ending balance	$	367,665		$	410,113		$	734,463

______________________________________


(1)	Represents the reclassification of Nearly Headless Nick well costs associated with the DGE acquisition in 2018 and inclusion of the Mahogany and Teak discoveries in the Jubilee Unit in 2017.


(2)	Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal transactions with BP


(3)	Primarily related to Akasa and Wawa as we wrote off $38.1 million and $13.6 million, respectively, of previously capitalized costs exploratory well costs to exploration expense during the third quarter of 2018. These impairments are included in our Ghana segment.

Schedule of aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year



	Years Ended December 31,
	2018		2017		2016
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	—	$	67,159	$	279,809
Exploratory well costs capitalized for a period of one to two years	299,253		291,252		244,804
Exploratory well costs capitalized for a period of three years or longer	68,412		51,702		209,850
Ending balance	$	367,665	$	410,113	$	734,463
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	3		5		5

Equity Method Investments (Tables)

12 Months Ended

Dec. 31, 2018

Equity Method Investments and Joint Ventures [Abstract]

Summary of Financial Information of KTIPI

Below is a summary of financial information for KTIPI.



	December 31,
	2018			2017
	(In thousands)
Assets
Total current assets	$	149,950		$	179,070
Property and equipment, net	271,627			345,611
Other assets	21			567
Total assets	$	421,598		$	525,248

Liabilities and shareholders' deficit
Total current liabilities	$	226,311		$	106,769
Total long term liabilities	536,178			565,591
Shareholders' deficit:
Total shareholders' deficit	(340,891		)	(147,112		)
Total liabilities and shareholders' deficit	$	421,598		$	525,248



	Year Ended December 31, 2018			Period November 28, 2017 through December 31, 2017
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	721,299		$	54,615
Other income	(477		)	294
Total revenues and other income	720,822			54,909

Costs and expenses:
Oil and gas production	147,685			15,509
Depletion and depreciation	126,983			10,738
Other expenses, net	429			(19		)
Total costs and expenses	275,097			26,228

Income before income taxes	445,725			28,681
Income tax expense	156,981			6,588
Net income	$	288,744		$	22,093

Kosmos' share of net income	$	144,372		$	11,046
Basis difference amortization(1)	71,491			5,812
Equity in earnings - KTIPI	$	72,881		$	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)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Schedule of debt



	December 31,
	2018			2017
	(In thousands)
Outstanding debt principal balances:
Facility	$	1,325,000		$	800,000
Corporate Revolver	325,000			—
Senior Notes	525,000			525,000
Total	2,175,000			1,325,000
Unamortized deferred financing costs and discounts(1)	(54,453		)	(42,203		)
Long-term debt, net	$	2,120,547		$	1,282,797

________________________________________


(1)	Includes $40.5 million and $23.6 million of unamortized deferred financing costs related to the Facility and $14.0 million and $18.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of December 31, 2018 and December 31, 2017, 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, 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, 2018, the estimated repayments of debt during the five years and thereafter are as follows:



	Payments Due by Year
	Total		2019		2020		2021		2022		2023		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,175,000	$	—	$	—	$	685,600	$	614,100	$	305,100	$	570,200

(1)

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,
	2018			2017			2016
	(In thousands)
Interest expense	$	114,134		$	92,687		$	89,029
Amortization—deferred financing costs	9,379			10,204			10,204
Loss on extinguishment of debt	4,324			—			—
Capitalized interest	(28,331		)	(30,282		)	(59,803		)
Deferred interest	(1,138		)	2,577			(581		)
Interest income	(3,455		)	(3,422		)	(1,954		)
Other, net	6,263			5,831			7,252
Interest and other financing costs, net	$	101,176		$	77,595		$	44,147

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
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-Name Accounting Standards Codification
-Topic 210
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Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
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-Name Accounting Standards Codification
-Topic 942
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-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
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-Name Accounting Standards Codification
-Topic 835
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-Section 55
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-URI http://asc.fasb.org/extlink&oid=114775985&loc=d3e28878-108400

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
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-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21475-112644

+ Details

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of oil derivative contracts



				Weighted Average Price per Bbl
Term	Type of Contract	Index	MBbl	Net Deferred Premium Payable/(Receivable)		Swap		Sold Put		Floor		Ceiling
2019:
January — December	Three-way collars	Dated Brent	10,500	$	1.17	$	—	$	43.81	$	53.33	$	73.58
January — December	Sold calls(1)	Dated Brent	913	—		—		—		—		80.00
January — December	Swaps	NYMEX WTI	1,747	—		52.31		—		—		—
January — June	Collars	NYMEX WTI	339	—		—		—		57.77		63.70
January — December	Collars	Argus LLS	1,000	—		—		—		60.00		88.75
2020:
January — December	Three-way collars	Dated Brent	2,000	$	—	$	—	$	50.00	$	60.00	$	90.54
January — December	Sold calls(1)(2)	Dated Brent	8,000	1.17		—		—		—		85.00

______________________________________


(1)	Represents call option contracts sold to counterparties to enhance other derivative positions.


(2)	Deferred premium payable to be paid January - December 2019.

Schedule of derivative instruments by balance sheet location

The following tables disclose the Company’s derivative instruments as of December 31, 2018 and 2017 and gain/(loss) from derivatives during the years ended December 31, 2018, 2017 and 2016.



		Estimated Fair Value Asset (Liability)
		December 31,
Type of Contract	Balance Sheet Location	2018			2017
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity(1)	Derivatives assets—current	$	38,785		$	665
Interest rate	Derivatives assets—current	—			1,017
Commodity(2)	Derivatives assets—long-term	14,312			39
Derivative liabilities:
Commodity(3)	Derivatives liabilities—current	(12,172		)	(67,531		)
Commodity(4)	Derivatives liabilities—long-term	(10,181		)	(30,209		)
Total derivatives not designated as hedging instruments		$	30,744		$	(96,019	)

______________________________________


(1)	Includes $0.4 million and zero as of December 31, 2018 and December 31, 2017, respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of $1.6 million and net deferred premiums receivable of $0.8 million related to commodity derivative contracts as of December 31, 2018 and 2017, respectively.


(2)	Includes net deferred premiums payable of $1.3 million and net deferred premiums receivable of $0.1 million related to commodity derivative contracts as of December 31, 2018 and 2017, respectively.


(3)	Includes net deferred premiums payable of $18.0 million and $5.6 million related to commodity derivative contracts as of December 31, 2018 and 2017, respectively.


(4)	Includes net deferred premiums payable of $0.5 million and $4.8 million related to commodity derivative contracts as of December 31, 2018 and 2017, 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)	2018			2017			2016
		(In thousands)
Derivatives not designated as hedging instruments:
Commodity(1)	Oil and gas revenue	$	(1,963	)	$	(12,502	)	$	2,538
Commodity	Derivatives, net	31,430			(59,968		)	(48,021		)
Interest rate	Interest expense	493			648			(1,076		)
Total derivatives not designated as hedging instruments		$	29,960		$	(71,822	)	$	(46,559	)

______________________________________


(1)	Amounts represent the change in fair value of our provisional oil sales contracts.

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Schedule of Company's assets and liabilities that are measured at fair value on a recurring basis

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2018 and 2017, 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, 2018
Assets:
Commodity derivatives	$	—	$	53,097		$	—	$	53,097
Liabilities:
Commodity derivatives	—		(22,353		)	—		(22,353		)
Total	$	—	$	30,744		$	—	$	30,744
December 31, 2017
Assets:
Commodity derivatives	$	—	$	704		$	—	$	704
Interest rate derivatives	—		1,017			—		1,017
Liabilities:
Commodity derivatives	—		(97,740		)	—		(97,740		)
Total	$	—	$	(96,019	)	$	—	$	(96,019	)

Schedule of carrying values and fair values of financial instruments that are not carried at fair value

The following table presents the carrying values and fair values at December 31, 2018 and 2017:



	December 31, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Senior Notes	$	511,873	$	525,026	$	507,600	$	542,472
Corporate Revolver	325,000		325,000		—		—
Facility	1,325,000		1,325,000		800,000		800,000
Total	$	2,161,873	$	2,175,026	$	1,307,600	$	1,342,472

Equity-based Compensation (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of plan activity

The following table reflects the outstanding restricted stock awards as of December 31, 2018:



	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, 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		—		—
Granted	—		—		—		—
Forfeited	—		—		—		—
Vested	(220	)	8.64		—		—
Outstanding at December 31, 2018:	—		—		—		—

The following table reflects the outstanding restricted stock units as of December 31, 2018:



	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, 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
Granted	2,402		7.07		8,111		12.38
Forfeited	(229	)	6.40		(302	)	8.95
Vested	(2,241	)	6.95		(9,545	)	13.75
Outstanding at December 31, 2018:	4,115		6.42		6,716		9.02

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Schedule of components of income (loss) before income taxes

The components of loss before income taxes were as follows:



	Years Ended December 31,
	2018			2017			2016
	(In thousands)
United States	$	41,026		$	6,068		$	5,083
Bermuda	(73,979		)	(66,914		)	(63,749		)
Foreign—other	(17,907		)	(117,009		)	(235,898		)
Loss before income taxes	$	(50,860	)	$	(177,855	)	$	(294,564	)

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,
	2018		2017			2016
	(In thousands)
Current:
United States	$	122	$	10,976		$	12,675
Bermuda	—		—			—
Foreign—other	33,864		24,456			102
Total current	33,986		35,432			12,777
Deferred:
United States	8,514		15,310			(3,594		)
Bermuda	—		—			—
Foreign—other	631		(5,805		)	(19,967		)
Total deferred	9,145		9,505			(23,561		)
Income tax expense (benefit)	$	43,131	$	44,937		$	(10,784	)

Schedule of reconciliation of income tax expense and the reported effective tax rate

Our reconciliation of income tax expense (benefit) computed by applying our statutory rate and the reported effective tax rate on loss from continuing operations is as follows:



	Years Ended December 31,
	2018			2017			2016
	(In thousands)
Tax at statutory rate(1)	$	(10,681	)	$	—		$	—
Foreign income (loss) taxed at different rates	5,013			9,381			(57,898		)
Net non-taxable expense / insurance recoveries	3,256			(30		)	8,694
West Leo arbitration settlement	(2,834		)	1,736			1,098
Non-deductible compensation	2,643			1,680			1,999
Deferred tax liability - undistributed earnings	(2,565		)	2,565			—
Non-deductible and other items	656			3,790			556
Equity earnings - net of tax	(15,305		)	—			—
Tax shortfall (windfall) on equity-based compensation, net	(387		)	3,086			5,504
Change in valuation allowance	63,335			6,008			29,263
Change in U.S. tax rate	—			16,721			—
Total tax expense (benefit)	$	43,131		$	44,937		$	(10,784	)
Effective tax rate(2)	85		%	25		%	4		%

______________________________________

(1)


(2)	The effective tax rate during the years ended December 31, 2018, 2017 and 2016 were impacted by losses of $261.2 million, $164.4 million and $121.4 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,
	2018			2017
	(In thousands)
Deferred tax assets:
Foreign capitalized operating expenses	$	128,809		$	68,218
Foreign net operating losses	28,050			25,307
United States net operating losses	59,336			—
Equity compensation	11,408			20,783
Unrealized derivative losses	—			33,963
Asset retirement obligation and other	29,450			24,784
Total deferred tax assets	257,053			173,055
Valuation allowance	(156,860		)	(93,525		)
Total deferred tax assets, net	100,193			79,530
Deferred tax liabilities:
Depletion, depreciation and amortization related to property and equipment	(547,389		)	(533,561		)
Unrealized derivative gains	(15,979		)	—
Total deferred tax liabilities	(563,368		)	(533,561		)
Net deferred tax liability	$	(463,175	)	$	(454,031	)

Net Income (Loss) Per Share (Tables)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Schedule of reconciliation between net income (loss) and the amounts used to compute basic and diluted net income (loss) per share and the weighted average shares outstanding used to compute basic and diluted net income (loss) per share



	Years Ended
	December 31,
	2018			2017			2016
	(In thousands, except per share data)
Numerator:
Net loss allocable to common stockholders(1)	$	(93,991	)	$	(222,792	)	$	(283,780	)
Denominator:
Weighted average number of shares outstanding:
Basic	404,585			388,375			385,402
Restricted stock awards and units(1)(2)	—			—			—
Diluted	404,585			388,375			385,402
Net loss per share:
Basic	$	(0.23	)	$	(0.57	)	$	(0.74	)
Diluted	$	(0.23	)	$	(0.57	)	$	(0.74	)

______________________________________

(1)


(2)	For the years ended December 31, 2018, 2017 and 2016, we excluded 10.6 million, 12.9 million and 11.8 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.

Additional Financial Information (Tables)

12 Months Ended

Dec. 31, 2018

Additional Financial Information

Schedule of accrued liabilities

Accrued liabilities consisted of the following:



	December 31,
	2018		2017
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	92,613	$	144,717
Current asset retirement obligations	6,617		—
General and administrative expenses	39,373		31,124
Interest	18,152		20,457
Income taxes	8,958		17,423
Taxes other than income	4,613		3,270
Derivatives	441		—
Revenue payable	24,379		—
Other	450		2,421
	$	195,596	$	219,412

Schedule of other expenses, net incurred

Other expenses, net incurred during the period is comprised of the following:



	Years Ended December 31,
	2018			2017			2016
	(In thousands)
Loss on disposal of inventory	$	280		$	866		$	14,900
Gain on insurance settlements	—			(461		)	(4,003		)
Disputed charges and related costs, net of recoveries	(9,753		)	4,962			11,299
Other, net	2,972			(76		)	920
Other expenses, net	$	(6,501	)	$	5,291		$	23,116

Business Segment Information (Tables)

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

Schedule of Business Segment Information



	Ghana			Equatorial Guinea(1)			Mauritania/Senegal			United States(2)			Corporate & Other			Eliminations(3)			Total
	(in thousands)
Year ended December 31, 2018
Revenues and other income:
Oil and gas revenue	$	739,070		$	360,649		$	—		$	147,596		$	—		$	(360,649	)	$	886,666
Gain on sale of assets	—			7,666			—			—			—			—			7,666
Other income, net	(17		)	(238		)	—			11			150,635			(142,354		)	8,037
Total revenues and other income	739,053			368,077			—			147,607			150,635			(503,003		)	902,369
Costs and expenses:
Oil and gas production	189,104			73,843			—			30,470			5,153			(73,843		)	224,727
Facilities insurance modifications, net	6,955			—			—			—			—			—			6,955
Exploration expenses	58,276			38,164			7,262			66,962			131,180			(352		)	301,492
General and administrative	19,342			5,351			5,220			10,534			168,542			(109,133		)	99,856
Depletion and depreciation	265,805			134,983			61			59,835			4,134			(134,983		)	329,835
Interest and other financing costs, net(4)	86,738			(12		)	(25,386		)	7,487			39,483			(7,134		)	101,176
Derivatives, net	—			—			—			(57,615		)	26,185			—			(31,430		)
(Gain) loss on equity method investments, net	—			—			—			—			—			(72,881		)	(72,881		)
Other expenses, net	16,414			(814		)	(23		)	598			3,510			(26,186		)	(6,501		)
Total costs and expenses	642,634			251,515			(12,866		)	118,271			378,187			(424,512		)	953,229
Loss before income taxes	96,419			116,562			12,866			29,336			(227,552		)	(78,491		)	(50,860		)
Income tax expense (benefit)	34,494			78,491			—			6,163			2,474			(78,491		)	43,131
Net loss	$	61,925		$	38,071		$	12,866		$	23,173		$	(230,026	)	$	—		$	(93,991	)

Consolidated capital expenditures	$	105,942		$	32,156		$	11,962		$	95,993		$	139,381		$	—		$	385,434

As of December 31, 2018
Property and equipment, net	$	1,698,194		$	3,919		$	411,448		$	1,308,670		$	37,470		$	—		$	3,459,701
Total assets	$	1,930,071		$	55,302		$	536,620		$	3,512,989		$	10,349,488		$	(12,296,281	)	$	4,088,189

______________________________________


(1)	Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion and depreciation for the year ended December 31, 2018, except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments.


(2)	Represents activity commencing September 14, 2018, the DGE acquisition date.


(3)	Includes elimination of proportionate consolidation amounts recorded for KTIPI to reconcile to (Gain) loss on equity method investments, net as reported in the consolidated statements of operations.


(4)	Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.



	Ghana			Equatorial Guinea(1)		Mauritania/Senegal			United States		Corporate & Other			Eliminations(2)			Total
	(in thousands)
Year ended December 31, 2017
Revenues and other income:
Oil and gas revenue	$	578,139		$	27,308	$	—		$	—	$	—		$	(27,308	)	$	578,139
Gain on sale of assets	—			—		—			—		—			—			—
Other income, net	5			147		—			—		$	219,968		(161,423		)	58,697
Total revenues and other income	578,144			27,455		—			—		219,968			(188,731		)	636,836
Costs and expenses:
Oil and gas production	137,584			7,755		—			—		(10,734		)	(7,755		)	126,850
Facilities insurance modifications, net	(820		)	—		—			—		—			—			(820		)
Exploration expenses	394			86		71,456			—		144,114			—			216,050
General and administrative	14,836			672		8,298			—		138,661			(94,165		)	68,302
Depletion and depreciation	251,890			11,181		20			—		3,293			(11,181		)	255,203
Interest and other financing costs, net(3)	71,592			—		(16,065		)	—		29,202			(7,134		)	77,595
Derivatives, net	—			—		—			—		59,968			—			59,968
Loss on equity method investments, net	—			—		11,486			—		—			(5,234		)	6,252
Other expenses, net	64,768			—		867			—		(376		)	(59,968		)	5,291
Total costs and expenses	540,244			19,694		76,062			—		364,128			(185,437		)	814,691
Income (loss) before income taxes	37,900			7,761		(76,062		)	—		(144,160		)	(3,294		)	(177,855		)
Income tax expense (benefit)	18,649			3,294		3			—		26,285			(3,294		)	44,937
Net income (loss)	$	19,251		$	4,467	$	(76,065	)	$	—	$	(170,445	)	$	—		$	(222,792	)

Consolidated capital expenditures	$	5,545		$	1,995	$	(80,929	)	$	—	$	130,821		$	—		$	57,432

As of December 31, 2017
Property and equipment, net	$	1,901,127		$	1,908	$	381,422		$	—	$	33,371		$	—		$	2,317,828
Total assets	$	2,263,824		$	237,835	$	570,044		$	—	$	8,671,437		$	(8,550,537	)	$	3,192,603

______________________________________


(1)	Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion and depreciation for the year ended December 31, 2017, except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments.


(2)	Includes elimination of proportionate consolidation amounts recorded for KTIPI to reconcile to (Gain) loss on equity method investments, net as reported in the consolidated statements of operations.


(3)	Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.



	Ghana			Equatorial Guinea			Mauritania/Senegal			United States		Corporate & Other			Eliminations			Total
	(in thousands)
Year ended December 31, 2016
Revenues and other income:
Oil and gas revenue	$	310,377		$	—		$	—		$	—	$	—		$	—		$	310,377
Gain on sale of assets	—			—			—			—		—			—			—
Other income, net	7			—			—			—		$	227,101		(152,130		)	74,978
Total revenues and other income	310,384			—			—			—		227,101			(152,130		)	385,355
Costs and expenses:
Oil and gas production	121,329			—			—			—		(1,962		)	—			119,367
Facilities insurance modifications, net	14,961			—			—			—		—			—			14,961
Exploration expenses	1,211			9			63,186			—		137,874			—			202,280
General and administrative	9,490			—			21,530			—		153,577			(96,974		)	87,623
Depletion and depreciation	137,094			—			97			—		3,213			—			140,404
Interest and other financing costs, net(1)	45,403			—			(22,404		)	—		28,282			(7,134		)	44,147
Derivatives, net	—			—			—			—		48,021			—			48,021
Loss on equity method investments, net	—			—			—			—		—			—			—
Other expenses, net	67,793			—			454			—		2,890			(48,021		)	23,116
Total costs and expenses	397,281			9			62,863			—		371,895			(152,129		)	679,919
Income (loss) before income taxes	(86,897		)	(9		)	(62,863		)	—		(144,794		)	(1		)	(294,564		)
Income tax expense (benefit)	(19,866		)	—			—			—		9,082			—			(10,784		)
Net income (loss)	$	(67,031	)	$	(9	)	$	(62,863	)	$	—	$	(153,876	)	$	(1	)	$	(283,780	)

Consolidated capital expenditures	$	221,294		$	9		$	283,442		$	—	$	139,765		$	—		$	644,510

As of December 31, 2016
Property and equipment, net	$	2,129,873		$	—		$	529,071		$	—	$	49,948		$	—		$	2,708,892
Total assets	$	2,484,497		$	(3	)	$	551,250		$	—	$	8,205,043		$	(7,899,322	)	$	3,341,465

______________________________________


(1)	Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.



	Years Ended December 31,
	2018			2017			2016
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	213,806		$	140,495		$	535,975
Other property	7,935			2,858			1,998
Adjustments:
Changes in capital accruals	27,317			(6,337		)	(25,875		)
Exploration expense, excluding unsuccessful well costs(1)	178,293			172,849			196,201
Capitalized interest	(28,331		)	(30,282		)	(59,803		)
Proceeds on sale of assets	(13,703		)	(222,068		)	(210		)
Other	117			(83		)	(3,776		)
Total consolidated capital expenditures	$	385,434		$	57,432		$	644,510

______________________________________


(1)	Unsuccessful well costs are included in oil and gas assets when incurred.

Accounting Policies - Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Cash and cash equivalents	$ 173,515	$ 233,412	$ 194,057
Restricted cash - current	4,527	56,380	24,506
Restricted cash - long-term	7,574	15,194	54,632
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$ 185,616	$ 304,986	$ 273,195	$ 310,862

Accounting Policies - Useful Lives (Details)	12 Months Ended
Accounting Policies - Useful Lives (Details)	Dec. 31, 2018
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 (Details) - USD ($) $ / shares in Units, shares in Millions		1 Months Ended	12 Months Ended
	Jan. 31, 2018	Nov. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2014
Restricted Cash
Restricted cash - current			$ 4,527,000	$ 56,380,000	$ 24,506,000
Restricted cash - long-term			7,574,000	15,194,000	54,632,000
Receivables
Allowance for doubtful accounts			1,200,000	0
Inventories
Materials and supplies inventory			83,400,000	63,500,000
Hydrocarbons inventory			1,400,000	8,400,000
Write down of materials and supplies			280,000	866,000	14,900,000
Impairment of Long-lived Assets
Impairment of oil and gas			0
Revenues and other income:
Oil and gas imbalances			0	0
Treasury Stock
Shares repurchased (in shares)		35
Shares repurchased price (in dollars per share)		$ 5.38
Shares repurchased		$ 188,000,000	206,051,000	2,194,000	$ 1,981,000
Restricted Cash \| Petroleum agreements - performance guarantees
Restricted Cash
Restricted cash - current			4,500,000	31,600,000
Restricted cash - long-term			7,400,000	15,200,000
Restricted Cash \| Non-Petroleum Agreements
Restricted Cash
Restricted cash - long-term			$ 200,000
Restricted Cash \| Facility interest or the Senior Notes plus the Corporate Revolver interest
Restricted Cash
Restricted cash - current				$ 24,800,000
Restricted cash period required as per commercial debt facility to meet interest and commitment fee payments	6 months
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
DGE Acquisition
Inventories
Inventory acquired			$ 22,100,000
Sales Revenue \| Customer Concentration Risk
Concentration of Credit Risk
Concentration risk percentage			11.00%

Accounting Policies - Summary of Oil and Gas Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Provisional oil sales contracts	$ 29,960	$ (71,822)	$ (46,559)
Oil and gas revenue	886,666	578,139	310,377
Ghana
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	741,033	590,642	307,837
Gulf of Mexico
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	147,596	0	0
Oil and gas revenue
Disaggregation of Revenue [Line Items]
Provisional oil sales contracts	(1,963)	(12,503)	2,540
Oil and gas revenue	$ 886,666	$ 578,139	$ 310,377

Acquisitions and Divestitures - 2018 Acquisitions (Details)	1 Months Ended					4 Months Ended
	Jan. 31, 2019	Oct. 31, 2018 company	Sep. 30, 2018 USD ($)	Jun. 30, 2018 km²	Mar. 31, 2018 km² block	Dec. 31, 2018 USD ($)	Aug. 31, 2018 USD ($)	Feb. 28, 2018 USD ($)
Business Acquisition [Line Items]
Number of companies in alliance \| company		2
Deep Gulf Energy, LP
Business Acquisition [Line Items]
Total purchase price			$ 1,275,382,000
Cash consideration paid			952,586,000
Fair value of common stock			307,944,000
Transaction related costs			14,852,000
Revenue of acquiree since acquisition date						$ 147,600,000
Operating expenses of acquiree since acquisition date						30,500,000
Blocks 10 and 13 \| Petroleum agreement
Business Acquisition [Line Items]
Participating interest percentage					35.00%
Area of petroleum exploration \| km²					13,600
Initial exploration period					4 years
First sub exploration period					4 years
3D seismic requirements (in square kilometers) \| km²					13,500
Number of blocks \| block					2
Block EG-24 \| Farm-in agreement
Business Acquisition [Line Items]
Area of petroleum exploration \| km²				3,500
Initial exploration period				3 years
First sub exploration period				4 years
3D seismic requirements (in square kilometers) \| km²				3,000
Participation interest acquired				40.00%
BP \| Blocks 10 and 13 \| Petroleum agreement
Business Acquisition [Line Items]
Participating interest percentage					50.00%
ANP STP \| Blocks 10 and 13 \| Petroleum agreement
Business Acquisition [Line Items]
Carried participating interest					15.00%
Common Stock \| Deep Gulf Energy, LP
Business Acquisition [Line Items]
Fair value of common stock			307,900,000
Revolving Credit Facility \| The Facility
Business Acquisition [Line Items]
Additional commitments			$ 200,000,000.0			$ 100,000,000	$ 100,000,000	$ 500,000,000.0
Subsequent Event \| Block EG-24 \| Farm-in agreement
Business Acquisition [Line Items]
Participation interest acquired	80.00%

Acquisitions and Divestitures - 2018 Acquisitions Schedule (Details) - Deep Gulf Energy, LP - USD ($) $ / shares in Units, $ in Thousands		1 Months Ended
	Sep. 14, 2018	Sep. 30, 2018
Fair value of assets acquired:
Proved oil and gas properties		$ 1,037,511
Unproved oil and gas properties		298,159
Accounts receivable and other		180,989
Total assets acquired		1,516,659
Fair value of liabilities assumed:
Accrued liabilities and other		126,530
Asset retirement obligations		74,482
Derivative liabilities		40,265
Total liabilities assumed		241,277
Cash consideration paid		952,586
Fair value of common stock		307,944
Transaction related costs		14,852
Total purchase price		1,275,382
Common Stock
Fair value of liabilities assumed:
Fair value of common stock		$ 307,900
Common shares issued (in shares)	34,993,585
Common Stock
Fair value of liabilities assumed:
Share price (in dollars per share)	$ 8.80

Acquisitions and Divestitures - 2017 Acquisitions (Details)	1 Months Ended							2 Months Ended	3 Months Ended		12 Months Ended
	Aug. 31, 2018 USD ($) km² sub_period block	Dec. 31, 2017 USD ($) km² block $ / bbl MBbls	Oct. 31, 2017 block	Sep. 30, 2017	Aug. 31, 2017 USD ($)	Apr. 30, 2017	Dec. 31, 2016 USD ($)	Feb. 28, 2017 instrument	Dec. 31, 2017 USD ($) km² $ / bbl MBbls	Mar. 31, 2017 USD ($)	Dec. 31, 2017 USD ($) km² $ / bbl MBbls	Nov. 30, 2015 USD ($)
Kosmos BP Senegal Limited \| Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Acquisitions and Divestitures
Participating interest percentage											60.00%
Farm-out agreements \| Block EG-21 and Block S and Block W
Acquisitions and Divestitures
Participating interest percentage	40.00%
Gain on sale of assets	$ 7,700,000
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
Petroleum agreement \| Block EG-21 and Block S and Block W
Acquisitions and Divestitures
Participating interest percentage			80.00%
Number of blocks \| block	3		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
Timis Corporation Limited \| Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Acquisitions and Divestitures
Participating interest percentage						30.00%
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 \| 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
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%
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							$ 120,000,000.0
Tullow \| Farm-in agreement \| Block C18 Offshore Mauritania
Acquisitions and Divestitures
Participating interest percentage				15.00%
Hess \| Ceiba Field and Okume Complex Assets
Acquisitions and Divestitures
Paying interest									85.00%
Revenue interests									80.75%
Trident Energy \| Farm-out agreements \| Block EG-21 and Block S and Block W
Acquisitions and Divestitures
Participation interest acquired	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%
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
Total purchase price									$ 650,000,000
Cash consideration paid									$ 231,000,000
Maximum \| BP \| Farm-out agreements \| Mauritania And Senegal Offshore Block
Acquisitions and Divestitures
Amount of potential and variable consideration per barrel \| $ / bbl		2							2		2
Number of barrels \| MBbls		1,000,000							1,000,000		1,000,000
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 \| Sales and purchase agreement \| Ceiba Field and Okume Complex Assets
Acquisitions and Divestitures
Ownership percentage		50.00%							50.00%		50.00%
Hess \| Trident Energy \| Sales and purchase agreement \| Ceiba Field and Okume Complex Assets
Acquisitions and Divestitures
Ownership percentage		50.00%							50.00%		50.00%

Acquisitions and Divestitures - 2016 Acquisitions (Details) a in Millions	1 Months Ended						2 Months Ended	12 Months Ended
	Jan. 31, 2017 USD ($)	Dec. 31, 2016	Oct. 31, 2016 a km²	Sep. 30, 2016 USD ($)	May 31, 2016	Apr. 30, 2016 km²	Oct. 31, 2016 a	Dec. 31, 2018	Oct. 31, 2016	Oct. 31, 2016 km²
Block 5
Business Acquisition [Line Items]
Participating interest percentage								45.00%
Block 12
Business Acquisition [Line Items]
Participating interest percentage								45.00%
Essaouira Offshore Block
Business Acquisition [Line Items]
Participating interest percentage							75.00%
ANP STP \| Block 5
Business Acquisition [Line Items]
Carried participating interest								15.00%
ANP STP \| Block 12
Business Acquisition [Line Items]
Carried participating interest								12.50%
BP \| Essaouira Offshore Block
Business Acquisition [Line Items]
Amount received in lieu of drilling exploration well \| $	$ 30,000,000
Amount due in lieu of drilling exploration well \| $				$ 30,000,000
Participating interest reassigned				45.00%
Farm-out agreements \| Block 42
Business Acquisition [Line Items]
Participating interest percentage						33.33%
Farm-out agreements \| Hess Corporation \| Block 42
Business Acquisition [Line Items]
Participating interest percentage						33.33%
3D seismic requirements (in square kilometers) \| km²						6,500
Farm-out agreements \| Staatsolie \| Block 42
Business Acquisition [Line Items]
Maximum percentage interest available upon approval						10.00%
Farm-out agreements \| Chevron Global Energy Inc \| Block 42
Business Acquisition [Line Items]
Participating interest percentage						33.33%
Farm-out agreements \| GALP \| Block 5, Block 11, and Block 12
Business Acquisition [Line Items]
Non operated interest		20.00%
Petroleum agreement \| Boujdour Maritime block
Business Acquisition [Line Items]
Participating interest percentage					55.00%
Petroleum agreement \| Block C6 Related To Mauritania
Business Acquisition [Line Items]
Participating interest percentage			28.00%
3D seismic requirements (in square kilometers) \| km²			2,000
Area of petroleum exploration			1.1				1.1			4,300
Initial exploration period			4 years
Petroleum agreement \| Cairn \| Boujdour Maritime block
Business Acquisition [Line Items]
Participating interest percentage					20.00%
Petroleum agreement \| ONHYM \| Boujdour Maritime block
Business Acquisition [Line Items]
Carried participating interest					25.00%
Petroleum agreement \| SMHPM \| Block C6 Related To Mauritania
Business Acquisition [Line Items]
Carried participating interest									10.00%

Joint Interest Billings and Related Party Receivables (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2018	Dec. 31, 2017
Joint interest billings
Joint interest billings, net		$ 64,572	$ 134,565
Long-term receivables - joint interest billings		19,002	34,941
Related party receivable		5,580	780
TEN Discoveries \| GNPC
Joint interest billings
Joint interest billings, net		14,000	15,200
Long-term receivables - joint interest billings		$ 14,000	$ 31,600
TEN Discoveries \| GNPC
Joint interest billings
GNPC's paying interest (as a percent)	5.00%
Kosmos-Trident International Petroleum Inc. \| Trident Energy
Joint interest billings
Ownership percentage		50.00%
Kosmos-Trident International Petroleum Inc.
Joint interest billings
Related party receivable		$ 5,600

Property and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and gas properties:
Proved properties	$ 2,773,276	$ 1,653,616
Unproved properties	759,472	465,109
Support equipment and facilities	1,463,213	1,427,054
Total oil and gas properties	4,995,961	3,545,779
Accumulated depletion	(1,551,097)	(1,234,806)
Oil and gas properties, net	3,444,864	2,310,973
Other property	51,987	39,405
Accumulated depreciation	(37,150)	(32,550)
Other property, net	14,837	6,855
Property and equipment, net	3,459,701	2,317,828	$ 2,708,892
Depletion expense	316,300	244,900	131,500
Depreciation expense	$ 4,600	$ 3,400	$ 3,500

Suspended Well Costs (Details) $ in Thousands	12 Months Ended
Suspended Well Costs (Details) $ in Thousands	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2018 USD ($) project	Dec. 31, 2017 USD ($) project	Dec. 31, 2016 USD ($) project
Reconciliation of capitalized exploratory well costs on completed wells
Beginning balance	$ 410,113	$ 734,463	$ 426,881
Additions to capitalized exploratory well costs pending the determination of proved reserves	10,518	69,567	307,582
Additions associated with the acquisition of DGE	26,224	0	0
Reclassification due to determination of proved reserves	(26,224)	(176,881)	0
Divestitures	0	(206,400)	0
Contribution of oil and gas property to equity method investment - KBSL	0	(131,764)	0
Dissolution of equity method investment - KBSL	0	121,128	0
Capitalized exploratory well costs charged to expense	(52,966)	0	0
Ending balance	367,665	410,113	734,463
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				$ 0	$ 67,159	$ 279,809
Exploratory well costs capitalized for a period of one to two years				299,253	291,252	244,804
Exploratory well costs capitalized for a period of three years or longer				68,412	51,702	209,850
Ending balance	410,113	$ 734,463	$ 426,881	$ 367,665	$ 410,113	$ 734,463
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year \| project				3	5	5
Akasa Discovery
Reconciliation of capitalized exploratory well costs on completed wells
Capitalized exploratory well costs charged to expense	(38,100)
Wawa Discovery
Reconciliation of capitalized exploratory well costs on completed wells
Capitalized exploratory well costs charged to expense	$ (13,600)

Equity Method Investments - Narrative (Details) - USD ($)		1 Months Ended			12 Months Ended
	Jan. 01, 2019	Dec. 31, 2017	Oct. 31, 2017	Feb. 28, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Contribution to equity method investment					$ 0	$ 133,893,000	$ 0
(Gain) loss on equity method investments, net					$ (72,881,000)	6,252,000	$ 0
Kosmos BP Senegal Limited
Schedule of Equity Method Investments [Line Items]
Ownership percentage				50.01%
Contribution to equity method investment				$ 133,900,000
(Gain) loss on equity method investments, net						$ 11,500,000
Kosmos-Trident International Petroleum Inc.
Schedule of Equity Method Investments [Line Items]
Ownership percentage					50.00%
(Gain) loss on equity method investments, net		$ (5,234,000)			$ (72,881,000)
Impairment of equity method investment					0
Cash dividends					$ 257,500,000
Cayar Offshore Profond And Saint Louis Offshore Profond Blocks \| BP Senegal Investments Limited \| Kosmos BP Senegal Limited
Schedule of Equity Method Investments [Line Items]
Participating 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%
Subsequent Event \| Ceiba Field and Okume Complex Assets \| Kosmos-Trident International Petroleum Inc.
Schedule of Equity Method Investments [Line Items]
Direct interest acquired due to transfer	40.375%

Equity Method Investments - Summary of Financial Information (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Costs and expenses:
Equity in earnings - KTIPI		$ 72,881	$ (6,252)	$ 0
Kosmos-Trident International Petroleum Inc.
Assets
Total current assets	$ 179,070	149,950	179,070
Property and equipment, net	345,611	271,627	345,611
Other assets	567	21	567
Total assets	525,248	421,598	525,248
Liabilities and shareholders' deficit
Total current liabilities	106,769	226,311	106,769
Total long term liabilities	565,591	536,178	565,591
Shareholders' deficit:
Total shareholders' deficit	(147,112)	(340,891)	(147,112)
Total liabilities and shareholders' deficit	525,248	421,598	$ 525,248
Revenues and other income:
Oil and gas revenue	54,615	721,299
Other income	294	(477)
Total revenues and other income	54,909	720,822
Costs and expenses:
Oil and gas production	15,509	147,685
Depletion and depreciation	10,738	126,983
Other expenses, net	(19)	429
Total costs and expenses	26,228	275,097
Income before income taxes	28,681	445,725
Income tax expense	6,588	156,981
Net income	22,093	288,744
Kosmos' share of net income	11,046	144,372
Basis difference amortization	5,812	71,491
Equity in earnings - KTIPI	$ 5,234	$ 72,881

Debt - Schedule of Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Outstanding debt principal	$ 2,175,000	$ 1,325,000
Unamortized issuance costs and discount	(54,453)	(42,203)
Long-term debt	2,120,547	1,282,797
Senior Notes
Debt Instrument [Line Items]
Outstanding debt principal	525,000	525,000
Unamortized issuance costs and discount	(14,000)	(18,600)
The Facility \| Revolving Credit Facility
Debt Instrument [Line Items]
Outstanding debt principal	1,325,000	800,000
Unamortized issuance costs and discount	(40,500)	(23,600)
Corporate Revolver \| Revolving Credit Facility
Debt Instrument [Line Items]
Outstanding debt principal	$ 325,000	$ 0

Debt - Facility (Details) - USD ($)		1 Months Ended	12 Months Ended
Debt - Facility (Details) - USD ($)	Jan. 31, 2018	Feb. 28, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 31, 2019	Sep. 30, 2018	Aug. 31, 2018
Debt Instrument [Line Items]
Loss on extinguishment of debt			$ 4,324,000	$ 0	$ 0
Revolving Credit Facility \| The Facility
Debt Instrument [Line Items]
Total commitment		$ 1,500,000,000.0
Additional commitments		500,000,000.0	100,000,000				$ 200,000,000.0	$ 100,000,000
Loss on extinguishment of debt		$ 4,100,000
Net deferred financing costs			40,500,000
Amount outstanding			1,325,000,000
Undrawn availability			$ 375,000,000
Interval period for payment of interest			6 months
Commitment fee percentage of the then-applicable margin when commitment is available for utilization	40.00%	30.00%
Commitment fee percentage of the then-applicable margin when commitment is not available for utilization			20.00%
Availability period of revolving-credit			1 month
Amount outstanding under letters of credit			$ 0
Revolving Credit Facility \| The Facility \| LIBOR \| Minimum
Debt Instrument [Line Items]
Applicable margin (as a percent)			3.25%
Revolving Credit Facility \| The Facility \| LIBOR \| Maximum
Debt Instrument [Line Items]
Applicable margin (as a percent)			4.50%
Subsequent Event \| Revolving Credit Facility \| The Facility
Debt Instrument [Line Items]
Total commitment						$ 1,700,000,000.0

Debt - Corporate Revolver (Details) - USD ($)	1 Months Ended	12 Months Ended
Debt - Corporate Revolver (Details) - USD ($)	Aug. 31, 2018	Dec. 31, 2018	Feb. 28, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Deferred financing costs, net		$ 8,937,000		$ 2,510,000
Revolving Credit Facility \| The Facility
Debt Instrument [Line Items]
Total commitment			$ 1,500,000,000.0
Amount outstanding		1,325,000,000
Undrawn availability		$ 375,000,000
Revolving Credit Facility \| Corporate Revolver
Debt Instrument [Line Items]
Total commitment	$ 400,000,000.0
Change in basis points	(1.00%)
Applicable margin (as a percent)	5.00%
Commitment fee percentage	30.00%	30.00%
Deferred financing costs, net		$ 8,900,000
Amount outstanding		325,000,000
Undrawn availability		$ 75,000,000
Interval period for payment of interest		6 months
Revolving Credit Facility \| Corporate Revolver \| LIBOR
Debt Instrument [Line Items]
Applicable margin (as a percent)		5.00%

Debt - Revolving Letter of Credit Facility (Details) - Revolving Letter of Credit Facility	1 Months Ended
	Jul. 31, 2016	Jun. 30, 2016	Jul. 31, 2015 USD ($)	Dec. 31, 2018 USD ($) letter_of_credit	Jul. 31, 2018 USD ($)	Feb. 28, 2018 USD ($)	Apr. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)
Debt Instrument [Line Items]
Total commitment			$ 75,000,000	$ 20,000,000.0	$ 40,000,000.0	$ 73,000,000	$ 70,000,000	$ 115,000,000.0
Additional commitments			$ 50,000,000
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%
Applicable margin (as a percent)	0.80%	0.50%
Commitment fee percentage	0.65%
Number of letters of credit \| letter_of_credit				7
Amount outstanding				$ 14,400,000

Debt - Senior Notes (Details) - Senior Notes - 7.875% senior notes due 2021 - USD ($)	1 Months Ended		12 Months Ended
	Apr. 30, 2015	Aug. 31, 2014	Dec. 31, 2018	Jan. 31, 2018	Aug. 01, 2015	Feb. 01, 2015
Debt Instrument [Line Items]
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%

Debt - Redemption Prices (Details) - Senior Notes - 7.875% senior notes due 2021	12 Months Ended
	Dec. 31, 2018
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) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Scheduled maturities of debt during the five year period and thereafter
Total	$ 2,175,000	$ 1,325,000
2019	0
2020	0
2021	685,600
2022	614,100
2023	305,100
Thereafter	570,200
Debt Instrument [Line Items]
Outstanding debt principal	2,175,000	1,325,000
Senior Notes
Scheduled maturities of debt during the five year period and thereafter
Total	525,000	525,000
Debt Instrument [Line Items]
Outstanding debt principal	525,000	$ 525,000
Senior Notes \| 7.875% senior notes due 2021
Scheduled maturities of debt during the five year period and thereafter
Total	525,000
Debt Instrument [Line Items]
Outstanding debt principal	$ 525,000

Debt - Debt Interest (Details) - USD ($) $ in Thousands	12 Months Ended
Debt - Debt Interest (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Interest expense	$ 114,134	$ 92,687	$ 89,029
Amortization—deferred financing costs	9,379	10,204	10,204
Loss on extinguishment of debt	4,324	0	0
Capitalized interest	(28,331)	(30,282)	(59,803)
Deferred interest	(1,138)	2,577	(581)
Interest income	(3,455)	(3,422)	(1,954)
Other, net	6,263	5,831	7,252
Interest and other financing costs, net	$ 101,176	$ 77,595	$ 44,147

Derivative Financial Instruments - Oil Derivative Contracts (Details) $ in Millions	2 Months Ended	12 Months Ended
	Feb. 28, 2019 USD ($) $ / bbl MBbls	Dec. 31, 2018 $ / bbl MBbls
Dated Brent \| January 2019 - December 2019 \| Three-way collars
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls		10,500
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)		1.17
Swap (USD per Bbl)		0.00
Put (USD per Bbl)		43.81
Floor (USD per Bbl)		53.33
Ceiling (USD per Bbl)		73.58
Dated Brent \| January 2019 - December 2019 \| Sold calls
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls		913
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)		0.00
Swap (USD per Bbl)		0.00
Put (USD per Bbl)		0.00
Floor (USD per Bbl)		0.00
Ceiling (USD per Bbl)		80.00
Dated Brent \| January 2020 - December 2020 \| Three-way collars
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls		2,000
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)		0.00
Swap (USD per Bbl)		0.00
Put (USD per Bbl)		50.00
Floor (USD per Bbl)		60.00
Ceiling (USD per Bbl)		90.54
Dated Brent \| January 2020 - December 2020 \| Sold calls
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls		8,000
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)		1.17
Swap (USD per Bbl)		0.00
Put (USD per Bbl)		0.00
Floor (USD per Bbl)		0.00
Ceiling (USD per Bbl)		85.00
NYMEX WTI \| January 2019 - December 2019 \| Swaps
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls		1,747
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)		0.00
Swap (USD per Bbl)		52.31
Put (USD per Bbl)		0.00
Floor (USD per Bbl)		0.00
Ceiling (USD per Bbl)		0.00
NYMEX WTI \| January 2019 - June 2019 \| Collars
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls		339
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)		0.00
Swap (USD per Bbl)		0.00
Put (USD per Bbl)		0.00
Floor (USD per Bbl)		57.77
Ceiling (USD per Bbl)		63.70
Argus LLS \| January 2019 - December 2019 \| Collars
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls		1,000
Weighted Average Price per Bbl [Abstract]
Net deferred premium payable/(receivable) (USD per Bbl)		0.00
Swap (USD per Bbl)		0.00
Put (USD per Bbl)		0.00
Floor (USD per Bbl)		60.00
Ceiling (USD per Bbl)		88.75
Subsequent Event \| Dated Brent \| January 2020 - December 2020 \| Three-way collars
Derivative Financial Instruments
Volumes (in MBbl) \| MBbls	2,000
Weighted Average Price per Bbl [Abstract]
Put (USD per Bbl)	40.00
Floor (USD per Bbl)	55.00
Ceiling (USD per Bbl)	75.00
Deferred premium payable \| $	$ 2.5

Derivative Financial Instruments - Derivative Instruments and Gain/(Loss) from Derivatives (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Derivative instruments, Balance Sheet Location
Derivatives assets—current	$ 38,785,000	$ 1,682,000
Derivatives assets—long-term	14,312,000	39,000
Derivatives liabilities—current	(12,172,000)	(67,531,000)
Derivatives liabilities—long-term	(10,181,000)	(30,209,000)
Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Total derivatives not designated as hedging instruments	30,744,000	(96,019,000)
Commodity derivatives \| Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Derivatives assets—current	38,785,000	665,000
Derivatives assets—long-term	14,312,000	39,000
Derivatives liabilities—current	(12,172,000)	(67,531,000)
Derivatives liabilities—long-term	(10,181,000)	(30,209,000)
Deferred premium payable, current	1,600,000
Deferred premium receivable, current		800,000
Deferred premium payable, noncurrent	1,300,000
Deferred premium receivable, noncurrent		100,000
Net deferred premiums payable related to commodity derivative contracts - current liabilities	18,000,000	5,600,000
Net deferred premiums payable related to commodity derivative contracts - non current liabilities	500,000	4,800,000
Commodity derivatives \| Not designated as hedging instruments \| Oil and gas revenue
Derivative instruments, Balance Sheet Location
Derivatives assets—current	400,000
Derivatives liabilities—current		0
Interest rate contracts \| Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Derivatives assets—current	$ 0	$ 1,017,000

Derivative Financial Instruments - Location of Gain (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative instruments, Location of Gain/(Loss)
Derivative, not designated as hedge, gain (loss)	$ 29,960	$ (71,822)	$ (46,559)
Commodity derivatives \| Oil and gas revenue
Derivative instruments, Location of Gain/(Loss)
Derivative, not designated as hedge, gain (loss)	(1,963)	(12,502)	2,538
Commodity derivatives \| Derivatives, net
Derivative instruments, Location of Gain/(Loss)
Derivative, not designated as hedge, gain (loss)	31,430	(59,968)	(48,021)
Interest rate contracts \| Interest expense
Derivative instruments, Location of Gain/(Loss)
Derivative, not designated as hedge, gain (loss)	$ 493	$ 648	$ (1,076)

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Carrying Value
Liabilities:
Long-term debt	$ 2,161,873	$ 1,307,600
Fair Value
Liabilities:
Long-term debt	2,175,026	1,342,472
Senior Notes \| Carrying Value
Liabilities:
Long-term debt	511,873	507,600
Senior Notes \| Fair Value
Liabilities:
Long-term debt	525,026	542,472
Recurring basis
Liabilities:
Total fair value, net	30,744	(96,019)
Recurring basis \| Commodity derivatives
Assets:
Derivative asset, fair value	53,097	704
Liabilities:
Derivative liability, fair value	(22,353)	(97,740)
Recurring basis \| Interest rate derivatives
Assets:
Derivative asset, fair value		1,017
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
Recurring basis \| Level 2
Liabilities:
Total fair value, net	30,744	(96,019)
Recurring basis \| Level 2 \| Commodity derivatives
Assets:
Derivative asset, fair value	53,097	704
Liabilities:
Derivative liability, fair value	(22,353)	(97,740)
Recurring basis \| Level 2 \| Interest rate derivatives
Assets:
Derivative asset, fair value		1,017
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
Corporate Revolver \| Revolving Credit Facility \| Carrying Value
Liabilities:
Long-term debt	325,000	0
Corporate Revolver \| Revolving Credit Facility \| Fair Value
Liabilities:
Long-term debt	325,000	0
The Facility \| Revolving Credit Facility \| Carrying Value
Liabilities:
Long-term debt	1,325,000	800,000
The Facility \| Revolving Credit Facility \| Fair Value
Liabilities:
Long-term debt	$ 1,325,000	$ 800,000

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset retirement obligations:
Beginning asset retirement obligations	$ 66,595	$ 63,574
Additions associated with the acquisition of DGE	74,482	0
Liabilities incurred during period	5,311	0
Liabilities settled during period	(3,345)	0
Revisions in estimated retirement obligations	0	(3,945)
Accretion expense	8,910	6,966
Ending asset retirement obligations	$ 151,953	$ 66,595

Equity-based Compensation - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended			12 Months Ended
	Jan. 31, 2019	Jan. 31, 2018	Jan. 31, 2015	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2015
Equity-based Compensation
Tax shortfall (windfall) related to equity-based compensation				$ 2,643	$ 1,680	$ 1,999
LTIP
Equity-based Compensation
Additional shares authorized (in shares)		11,000,000.0	15,000,000.0
Approved and authorized awards (in shares)							50,500,000
Number of shares remaining available for grant (in shares)				15,200,000
Compensation expense recognized				$ 35,200	40,000	40,100
Tax benefit				6,600	13,200	13,000
Tax shortfall (windfall) related to equity-based compensation				$ (400)	3,100	5,500
Minimum \| LTIP
Equity-based Compensation
Vesting period				3 years
Restricted Stock Awards and Restricted Stock Units \| LTIP
Equity-based Compensation
Fair value of awards vested				$ 85,100	$ 21,200	$ 14,400
Market/Service Vesting Restricted Stock Awards \| LTIP
Equity-based Compensation
Granted (in dollars per share)				$ 0.00	$ 0.00	$ 0.00
Market/Service Vesting Restricted Stock Units \| LTIP
Equity-based Compensation
Granted (in dollars per share)				12.38	9.50	4.88
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				0.70%
Market/Service Vesting Restricted Stock Units \| Maximum \| LTIP
Equity-based Compensation
Vesting percentage of the awards granted				200.00%
Granted (in dollars per share)				$ 15.71
Expected volatility				53.00%
Risk-free interest rate				2.20%
Service Vesting Restricted Stock Units \| LTIP
Equity-based Compensation
Granted (in dollars per share)				$ 7.07	$ 6.43	$ 4.05
Restricted stock units \| LTIP
Equity-based Compensation
Compensation expense not yet recognized				$ 33,900
Weighted average period over which compensation expense is to be recognized				2 years 10 days
Subsequent Event \| Market/Service Vesting Restricted Stock Units \| LTIP
Equity-based Compensation
Granted (in shares)	2,800,000
Subsequent Event \| Service Vesting Restricted Stock Units \| LTIP
Equity-based Compensation
Granted (in shares)	2,600,000
Subsequent Event \| Restricted stock units \| LTIP
Equity-based Compensation
Compensation expense not yet recognized	$ 32,000
Weighted average period over which compensation expense is to be recognized	3 years

Equity-based Compensation - Schedule of Awards (Details) - LTIP - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Service Vesting Restricted Stock Awards
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	220	488	810
Granted (in shares)	0	0	0
Forfeited (in shares)	0	0	0
Vested (in shares)	(220)	(268)	(322)
Outstanding at the end of the period (in shares)	0	220	488
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 8.64	$ 8.83	$ 9.20
Granted (in dollars per share)	0.00	0.00	0.00
Forfeited (in dollars per share)	0.00	0.00	0.00
Vested (in dollars per share)	8.64	8.97	9.77
Outstanding at the end of the period (in dollars per share)	$ 0.00	$ 8.64	$ 8.83
Market/Service Vesting Restricted Stock Awards
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	0	0	261
Granted (in shares)	0	0	0
Forfeited (in shares)	0	0	(162)
Vested (in shares)	0	0	(99)
Outstanding at the end of the period (in shares)	0	0	0
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 0.00	$ 0.00	$ 9.44
Granted (in dollars per share)	0.00	0.00	0.00
Forfeited (in dollars per share)	0.00	0.00	9.44
Vested (in dollars per share)	0.00	0.00	9.44
Outstanding at the end of the period (in dollars per share)	$ 0.00	$ 0.00	$ 0.00
Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	4,183	4,160	3,592
Granted (in shares)	2,402	2,085	2,158
Forfeited (in shares)	(229)	(137)	(134)
Vested (in shares)	(2,241)	(1,925)	(1,456)
Outstanding at the end of the period (in shares)	4,115	4,183	4,160
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 6.39	$ 6.91	$ 9.79
Granted (in dollars per share)	7.07	6.43	4.05
Forfeited (in dollars per share)	6.40	6.91	8.87
Vested (in dollars per share)	6.95	7.51	9.61
Outstanding at the end of the period (in dollars per share)	$ 6.42	$ 6.39	$ 6.91
Market/Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	8,452	7,194	6,578
Granted (in shares)	8,111	2,175	1,379
Forfeited (in shares)	(302)	(21)	(70)
Vested (in shares)	(9,545)	(896)	(693)
Outstanding at the end of the period (in shares)	6,716	8,452	7,194
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 11.26	$ 12.29	$ 14.24
Granted (in dollars per share)	12.38	9.50	4.88
Forfeited (in dollars per share)	8.95	6.21	14.49
Vested (in dollars per share)	13.75	15.43	15.81
Outstanding at the end of the period (in dollars per share)	$ 9.02	$ 11.26	$ 12.29

Income Taxes - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
Income Taxes - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes
Tax Cuts and Jobs Act of 2017, income tax expense (benefit)	$ 16.7
Effective tax rate		85.00%	25.00%	4.00%
Federal statutory income tax rate percent			21.00%
Foreign net operating loss carryforwards		$ 103.0
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		15.0
Foreign net operating loss carryforwards expiring in 2030		0.1
Foreign net operating loss carryforwards not expiring		84.7
Material uncertain tax positions		$ 0.0
United States
Income Taxes
Effective tax rate		84.00%	433.00%	179.00%
Foreign net operating loss carryforwards not expiring		$ 282.5
Ghana
Income Taxes
Effective tax rate		36.00%	49.00%	23.00%
Foreign—other
Income Taxes
Effective tax rate		0.00%
Federal statutory income tax rate percent		0.00%

Income Taxes - Components of Income (Loss) and Provision for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes
Loss before income taxes	$ (50,860)	$ (177,855)	$ (294,564)
Components of the provision for income taxes attributable to income (loss) before income taxes
Current	33,986	35,432	12,777
Deferred	9,145	9,505	(23,561)
Income tax expense (benefit)	43,131	44,937	(10,784)
Reconciliation of income tax expense and the reported effective tax rate
Tax at statutory rate	(10,681)	0	0
Foreign income (loss) taxed at different rates	5,013	9,381	(57,898)
Net non-taxable expense / insurance recoveries	3,256	(30)	8,694
West Leo arbitration settlement	(2,834)	1,736	1,098
Non-deductible compensation	2,643	1,680	1,999
Deferred tax liability - undistributed earnings	(2,565)	2,565	0
Non-deductible and other items	656	3,790	556
Equity earnings - net of tax	(15,305)	0	0
Tax shortfall (windfall) on equity-based compensation, net	(387)	3,086	5,504
Change in valuation allowance	63,335	6,008	29,263
Change in U.S. tax rate	$ 0	$ 16,721	$ 0
Effective tax rate	85.00%	25.00%	4.00%
Federal statutory income tax rate percent		21.00%
Impact of losses incurred in jurisdictions in which company is not subject to taxes on effective tax rate	$ 261,200	$ 164,400	$ 121,400
United States
Income Taxes
Loss before income taxes	41,026	6,068	5,083
Components of the provision for income taxes attributable to income (loss) before income taxes
Current	122	10,976	12,675
Deferred	8,514	15,310	(3,594)
Bermuda
Income Taxes
Loss before income taxes	(73,979)	(66,914)	(63,749)
Components of the provision for income taxes attributable to income (loss) before income taxes
Current	0	0	0
Deferred	0	0	0
Foreign—other
Income Taxes
Loss before income taxes	(17,907)	(117,009)	(235,898)
Components of the provision for income taxes attributable to income (loss) before income taxes
Current	33,864	24,456	102
Deferred	$ 631	$ (5,805)	$ (19,967)
Bermuda
Reconciliation of income tax expense and the reported effective tax rate
Federal statutory income tax rate percent		0.00%	0.00%

Income Taxes - Deferred Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred tax assets:
Foreign capitalized operating expenses	$ 128,809	$ 68,218
Foreign net operating losses	28,050	25,307
United States net operating losses	59,336	0
Equity compensation	11,408	20,783
Unrealized derivative losses	0	33,963
Asset retirement obligation and other	29,450	24,784
Total deferred tax assets	257,053	173,055
Valuation allowance	(156,860)	(93,525)
Total deferred tax assets, net	100,193	79,530
Deferred tax liabilities:
Depletion, depreciation and amortization related to property and equipment	(547,389)	(533,561)
Unrealized derivative gains	(15,979)	0
Total deferred tax liabilities	(563,368)	(533,561)
Net deferred tax liability	$ (463,175)	$ (454,031)

Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Numerator:
Net loss	$ 185,565	$ (126,057)	$ (103,273)	$ (50,226)	$ (122,079)	$ (63,405)	$ (8,467)	$ (28,841)	$ (93,991)	$ (222,792)	$ (283,780)
Weighted average number of shares used to compute net income (loss) per share:
Basic (in shares)									404,585	388,375	385,402
Restricted stock awards and units (in shares)									0	0	0
Diluted (in shares)									404,585	388,375	385,402
Net income (loss) per share:
Basic (in dollars per share)	$ 0.44	$ (0.31)	$ (0.26)	$ (0.13)	$ (0.31)	$ (0.16)	$ (0.02)	$ (0.07)	$ (0.23)	$ (0.57)	$ (0.74)
Diluted (in dollars per share)	$ 0.43	$ (0.31)	$ (0.26)	$ (0.13)	$ (0.31)	$ (0.16)	$ (0.02)	$ (0.07)	$ (0.23)	$ (0.57)	$ (0.74)
Outstanding restricted stock awards and units excluded from the computations of diluted net income per share (in shares)									10,600	12,900	11,800

Commitments and Contingencies (Details) $ / shares in Units, $ in Thousands			1 Months Ended	12 Months Ended
	Feb. 25, 2019 $ / shares	Oct. 14, 2011	Feb. 28, 2019 USD ($) agreement	Dec. 31, 2018 USD ($) km² exploration_well	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Commitments and contingencies
Rent expense				$ 4,700	$ 3,300	$ 3,300
Mauritania
Commitments and contingencies
Number of exploration wells \| exploration_well				1
Namibia
Commitments and contingencies
Number of exploration wells \| exploration_well				1
Senegal
Commitments and contingencies
Number of exploration wells \| exploration_well				2
Sao Tome and Principe
Commitments and contingencies
3D seismic requirements (in square kilometers) \| km²				13,500
Operating leases
Future minimum rental commitments
2019				$ 2,775
2020				4,173
2021				3,276
2022				3,326
2023				3,376
Thereafter				19,582
Total				36,508
Jubilee Unitization And Unit Operating Agreement
Commitments and contingencies
Unit interest after redetermination process (as a percent)		24.10%
Surety Bond \| Gulf of Mexico
Future minimum rental commitments
Cash collateral				600
Bureau Of Ocean Energy Management \| Surety Bond \| Gulf of Mexico
Future minimum rental commitments
Required performance bonds				200,900
Third Party \| Surety Bond \| Gulf of Mexico
Future minimum rental commitments
Required performance bonds				$ 3,700
Subsequent Event
Future minimum rental commitments
Dividends declared per common stock (in dollars per share) \| $ / shares	$ 0.0452
Subsequent Event \| National Oil Companies Of Mauritania And Senegal \| Carry Advance Agreements
Future minimum rental commitments
Number of agreements \| agreement			2
Share of development costs to be financed, up to			$ 239,700

Additional Financial Information (Details) - USD ($)	1 Months Ended	12 Months Ended
Additional Financial Information (Details) - USD ($)	Jul. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accrued liabilities:
Exploration, development and production		$ 92,613,000	$ 144,717,000
Current asset retirement obligations		6,617,000	0
General and administrative expenses		39,373,000	31,124,000
Interest		18,152,000	20,457,000
Income taxes		8,958,000	17,423,000
Taxes other than income		4,613,000	3,270,000
Derivatives		441,000	0
Revenue payable		24,379,000	0
Other		450,000	2,421,000
Accrued liabilities		195,596,000	219,412,000
Gain on sale of assets		7,666,000	0	$ 0
Other Income
Other Income, net		0	58,700,000	74,800,000
Other Expenses, Net
Loss on disposal of inventory		280,000	866,000	14,900,000
Gain on insurance settlements		0	(461,000)	(4,003,000)
Disputed charges and related costs, net of recoveries		(9,753,000)	4,962,000	11,299,000
Other, net		2,972,000	(76,000)	920,000
Other expenses, net		(6,501,000)	5,291,000	23,116,000
Recoveries	$ 12,900,000
Oil And Gas Production Expense
Other Income
Insurance recoveries		0	$ 17,100,000	$ 7,500,000
Farm-out agreements \| Block EG-21 and Block S and Block W
Accrued liabilities:
Gain on sale of assets		$ 7,700,000

Business Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Oil and gas revenue									$ 886,666	$ 578,139	$ 310,377
Gain on sale of assets									7,666	0	0
Other income, net									8,037	58,697	74,978
Total revenues and other income	$ 309,500	$ 250,219	$ 215,473	$ 127,177	$ 187,104	$ 151,242	$ 146,524	$ 151,966	902,369	636,836	385,355
Oil and gas production									224,727	126,850	119,367
Facilities insurance modifications, net									6,955	(820)	14,961
Exploration expenses									301,492	216,050	202,280
General and administrative									99,856	68,302	87,623
Depletion and depreciation									329,835	255,203	140,404
Interest and other financing costs, net									101,176	77,595	44,147
Derivatives, net									(31,430)	59,968	48,021
(Gain) loss on equity method investments, net									(72,881)	6,252	0
Other expenses, net									(6,501)	5,291	23,116
Total costs and expenses	22,475	364,912	364,091	201,751	308,647	216,162	131,252	158,630	953,229	814,691	679,919
Loss before income taxes									(50,860)	(177,855)	(294,564)
Income tax expense (benefit)									43,131	44,937	(10,784)
Net loss	185,565	$ (126,057)	$ (103,273)	$ (50,226)	(122,079)	$ (63,405)	$ (8,467)	$ (28,841)	(93,991)	(222,792)	(283,780)
Consolidated capital expenditures									385,434	57,432	644,510
Property and equipment, net	3,459,701				2,317,828				3,459,701	2,317,828	2,708,892
Total assets	4,088,189				3,192,603				4,088,189	3,192,603	3,341,465
Corporate & Other
Segment Reporting Information [Line Items]
Oil and gas revenue									0	0	0
Gain on sale of assets									0	0	0
Other income, net									150,635	219,968	227,101
Total revenues and other income									150,635	219,968	227,101
Oil and gas production									5,153	(10,734)	(1,962)
Facilities insurance modifications, net									0	0	0
Exploration expenses									131,180	144,114	137,874
General and administrative									168,542	138,661	153,577
Depletion and depreciation									4,134	3,293	3,213
Interest and other financing costs, net									39,483	29,202	28,282
Derivatives, net									26,185	59,968	48,021
(Gain) loss on equity method investments, net									0	0	0
Other expenses, net									3,510	(376)	2,890
Total costs and expenses									378,187	364,128	371,895
Loss before income taxes									(227,552)	(144,160)	(144,794)
Income tax expense (benefit)									2,474	26,285	9,082
Net loss									(230,026)	(170,445)	(153,876)
Consolidated capital expenditures									139,381	130,821	139,765
Property and equipment, net	37,470				33,371				37,470	33,371	49,948
Total assets	10,349,488				8,671,437				10,349,488	8,671,437	8,205,043
Eliminations
Segment Reporting Information [Line Items]
Oil and gas revenue									(360,649)	(27,308)	0
Gain on sale of assets									0	0	0
Other income, net									(142,354)	(161,423)	(152,130)
Total revenues and other income									(503,003)	(188,731)	(152,130)
Oil and gas production									(73,843)	(7,755)	0
Facilities insurance modifications, net									0	0	0
Exploration expenses									(352)	0	0
General and administrative									(109,133)	(94,165)	(96,974)
Depletion and depreciation									(134,983)	(11,181)	0
Interest and other financing costs, net									(7,134)	(7,134)	(7,134)
Derivatives, net									0	0	0
(Gain) loss on equity method investments, net									(72,881)	(5,234)	0
Other expenses, net									(26,186)	(59,968)	(48,021)
Total costs and expenses									(424,512)	(185,437)	(152,129)
Loss before income taxes									(78,491)	(3,294)	(1)
Income tax expense (benefit)									(78,491)	(3,294)	0
Net loss									0	0	(1)
Consolidated capital expenditures									0	0	0
Property and equipment, net	0				0				0	0	0
Total assets	(12,296,281)				(8,550,537)				(12,296,281)	(8,550,537)	(7,899,322)
Ghana \| Operating Segments
Segment Reporting Information [Line Items]
Oil and gas revenue									739,070	578,139	310,377
Gain on sale of assets									0	0	0
Other income, net									(17)	5	7
Total revenues and other income									739,053	578,144	310,384
Oil and gas production									189,104	137,584	121,329
Facilities insurance modifications, net									6,955	(820)	14,961
Exploration expenses									58,276	394	1,211
General and administrative									19,342	14,836	9,490
Depletion and depreciation									265,805	251,890	137,094
Interest and other financing costs, net									86,738	71,592	45,403
Derivatives, net									0	0	0
(Gain) loss on equity method investments, net									0	0	0
Other expenses, net									16,414	64,768	67,793
Total costs and expenses									642,634	540,244	397,281
Loss before income taxes									96,419	37,900	(86,897)
Income tax expense (benefit)									34,494	18,649	(19,866)
Net loss									61,925	19,251	(67,031)
Consolidated capital expenditures									105,942	5,545	221,294
Property and equipment, net	1,698,194				1,901,127				1,698,194	1,901,127	2,129,873
Total assets	1,930,071				2,263,824				1,930,071	2,263,824	2,484,497
Equatorial Guinea \| Operating Segments
Segment Reporting Information [Line Items]
Oil and gas revenue									360,649	27,308	0
Gain on sale of assets									7,666	0	0
Other income, net									(238)	147	0
Total revenues and other income									368,077	27,455	0
Oil and gas production									73,843	7,755	0
Facilities insurance modifications, net									0	0	0
Exploration expenses									38,164	86	9
General and administrative									5,351	672	0
Depletion and depreciation									134,983	11,181	0
Interest and other financing costs, net									(12)	0	0
Derivatives, net									0	0	0
(Gain) loss on equity method investments, net									0	0	0
Other expenses, net									(814)	0	0
Total costs and expenses									251,515	19,694	9
Loss before income taxes									116,562	7,761	(9)
Income tax expense (benefit)									78,491	3,294	0
Net loss									38,071	4,467	(9)
Consolidated capital expenditures									32,156	1,995	9
Property and equipment, net	3,919				1,908				3,919	1,908	0
Total assets	55,302				237,835				55,302	237,835	(3)
Mauritania And Senegal \| Operating Segments
Segment Reporting Information [Line Items]
Oil and gas revenue									0	0	0
Gain on sale of assets									0	0	0
Other income, net									0	0	0
Total revenues and other income									0	0	0
Oil and gas production									0	0	0
Facilities insurance modifications, net									0	0	0
Exploration expenses									7,262	71,456	63,186
General and administrative									5,220	8,298	21,530
Depletion and depreciation									61	20	97
Interest and other financing costs, net									(25,386)	(16,065)	(22,404)
Derivatives, net									0	0	0
(Gain) loss on equity method investments, net									0	11,486	0
Other expenses, net									(23)	867	454
Total costs and expenses									(12,866)	76,062	62,863
Loss before income taxes									12,866	(76,062)	(62,863)
Income tax expense (benefit)									0	3	0
Net loss									12,866	(76,065)	(62,863)
Consolidated capital expenditures									11,962	(80,929)	283,442
Property and equipment, net	411,448				381,422				411,448	381,422	529,071
Total assets	536,620				570,044				536,620	570,044	551,250
United States \| Operating Segments
Segment Reporting Information [Line Items]
Oil and gas revenue									147,596	0	0
Gain on sale of assets									0	0	0
Other income, net									11	0	0
Total revenues and other income									147,607	0	0
Oil and gas production									30,470	0	0
Facilities insurance modifications, net									0	0	0
Exploration expenses									66,962	0	0
General and administrative									10,534	0	0
Depletion and depreciation									59,835	0	0
Interest and other financing costs, net									7,487	0	0
Derivatives, net									(57,615)	0	0
(Gain) loss on equity method investments, net									0	0	0
Other expenses, net									598	0	0
Total costs and expenses									118,271	0	0
Loss before income taxes									29,336	0	0
Income tax expense (benefit)									6,163	0	0
Net loss									23,173	0	0
Consolidated capital expenditures									95,993	0	0
Property and equipment, net	1,308,670				0				1,308,670	0	0
Total assets	$ 3,512,989				$ 0				$ 3,512,989	$ 0	$ 0

Business Segment Information Consolidated Capital Expenditures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting [Abstract]
Oil and gas assets	$ 213,806	$ 140,495	$ 535,975
Other property	7,935	2,858	1,998
Changes in capital accruals	27,317	(6,337)	(25,875)
Exploration expense, excluding unsuccessful well costs	178,293	172,849	196,201
Capitalized interest	(28,331)	(30,282)	(59,803)
Proceeds on sale of assets	(13,703)	(222,068)	(210)
Other	117	(83)	(3,776)
Consolidated capital expenditures	$ 385,434	$ 57,432	$ 644,510

Supplemental Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Revenues and other income	$ 309,500	$ 250,219	$ 215,473	$ 127,177	$ 187,104	$ 151,242	$ 146,524	$ 151,966	$ 902,369	$ 636,836	$ 385,355
Costs and expenses	22,475	364,912	364,091	201,751	308,647	216,162	131,252	158,630	953,229	814,691	679,919
Net loss	$ 185,565	$ (126,057)	$ (103,273)	$ (50,226)	$ (122,079)	$ (63,405)	$ (8,467)	$ (28,841)	$ (93,991)	$ (222,792)	$ (283,780)
Earnings Per Share [Abstract]
Basic (in dollars per share)	$ 0.44	$ (0.31)	$ (0.26)	$ (0.13)	$ (0.31)	$ (0.16)	$ (0.02)	$ (0.07)	$ (0.23)	$ (0.57)	$ (0.74)
Diluted (in dollars per share)	$ 0.43	$ (0.31)	$ (0.26)	$ (0.13)	$ (0.31)	$ (0.16)	$ (0.02)	$ (0.07)	$ (0.23)	$ (0.57)	$ (0.74)

- Definition

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

+ References

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-Name Accounting Standards Codification
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+ Details

- Definition

The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.

+ References

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+ Details

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Schedule I - Condensed Parent Company Financial Statements - Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 173,515	$ 233,412	$ 194,057
Prepaid expenses and other	68,040	9,306
Total current assets	509,700	533,602
Investment in subsidiaries at equity	51,896	236,514
Deferred financing costs, net of accumulated amortization of $12,065 and $13,951 at December 31, 2018 and December 31, 2017, respectively	8,937	2,510
Restricted cash	7,574	15,194	54,632
Long-term deferred tax asset	14,004	22,517
Total assets	4,088,189	3,192,603	3,341,465
Current liabilities:
Accounts payable	176,540	141,787
Accrued liabilities	195,596	219,412
Total current liabilities	384,308	428,730
Long-term debt, net	2,120,547	1,282,797
Deferred tax liabilities	477,179	476,548
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2018 and December 31, 2017	0	0
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 442,914,675 and 398,599,457 issued at December 31, 2018 and December 31, 2017, respectively	4,429	3,986
Additional paid-in capital	2,341,249	2,014,525
Accumulated deficit	(1,167,193)	(1,073,202)
Treasury stock, at cost, 44,263,269 and 9,188,819 shares at December 31, 2018 and December 31, 2017, respectively	(237,007)	(48,197)
Total shareholders’ equity	941,478	897,112	$ 1,081,199	$ 1,325,513
Total liabilities and shareholders’ equity	$ 4,088,189	3,192,603
Parent company
Condensed Balance Sheet Statements, Captions [Line Items]
Ownership percentage	100.00%
Current assets:
Cash and cash equivalents	$ 6,776	297
Receivables from subsidiaries	2,890	0
Note receivable from subsidiary	7,941	0
Prepaid expenses and other	313	290
Total current assets	17,920	587
Investment in subsidiaries at equity	1,432,468	1,419,890
Long-term note receivable from subsidiary	607,943	0
Deferred financing costs, net of accumulated amortization of $12,065 and $13,951 at December 31, 2018 and December 31, 2017, respectively	8,937	2,510
Restricted cash	305	0
Long-term deferred tax asset	(1,132)	0
Total assets	2,066,441	1,422,987
Current liabilities:
Accounts payable	975	4
Accounts payable to subsidiaries	0	332
Accrued liabilities	18,972	19,128
Total current liabilities	19,947	19,464
Long-term debt, net	836,016	506,411
Long-term note payable to subsidiary	269,000	0
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2018 and December 31, 2017	0	0
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 442,914,675 and 398,599,457 issued at December 31, 2018 and December 31, 2017, respectively	4,429	3,986
Additional paid-in capital	2,341,249	2,014,525
Accumulated deficit	(1,167,193)	(1,073,202)
Treasury stock, at cost, 44,263,269 and 9,188,819 shares at December 31, 2018 and December 31, 2017, respectively	(237,007)	(48,197)
Total shareholders’ equity	941,478	897,112
Total liabilities and shareholders’ equity	$ 2,066,441	$ 1,422,987

Schedule I - Condensed Parent Company Financial Statements - Balance Sheet (Parenthetical) (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Condensed Balance Sheet Statements, Captions [Line Items]
Deferred financing costs, accumulated amortization (in dollars)	$ 12,065	$ 13,951
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	442,914,675	398,599,457
Treasury stock shares	44,263,269	9,188,819
Parent company
Condensed Balance Sheet Statements, Captions [Line Items]
Deferred financing costs, accumulated amortization (in dollars)	$ 12,065	$ 13,951
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	442,914,675	398,599,457
Treasury stock shares	44,263,269	9,188,819

Schedule I - Condensed Parent Company Financial Statements - Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues and other income:
Oil and gas revenue									$ 886,666	$ 578,139	$ 310,377
Total revenues and other income	$ 309,500	$ 250,219	$ 215,473	$ 127,177	$ 187,104	$ 151,242	$ 146,524	$ 151,966	902,369	636,836	385,355
Costs and expenses:
General and administrative									99,856	68,302	87,623
Interest and other financing costs, net									101,176	77,595	44,147
Other expenses, net									(6,501)	5,291	23,116
Total costs and expenses	22,475	364,912	364,091	201,751	308,647	216,162	131,252	158,630	953,229	814,691	679,919
Loss before income taxes									(50,860)	(177,855)	(294,564)
Income tax expense (benefit)									43,131	44,937	(10,784)
Net loss	$ 185,565	$ (126,057)	$ (103,273)	$ (50,226)	$ (122,079)	$ (63,405)	$ (8,467)	$ (28,841)	(93,991)	(222,792)	(283,780)
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									47,279	51,544	48,542
General and administrative recoveries—related party									(36,197)	(40,266)	(40,047)
Interest and other financing costs, net									66,055	55,596	55,253
Interest Expense (Income), Net, Related Party									(7,941)	0	0
Other expenses, net									49	40	1
Equity in losses of subsidiaries									(23,614)	(155,878)	(220,031)
Total costs and expenses									92,859	222,792	283,780
Loss before income taxes									(92,859)	(222,792)	(283,780)
Income tax expense (benefit)									1,132	0	0
Net loss									$ (93,991)	$ (222,792)	$ (283,780)

Schedule I - Condensed Parent Company Financial Statements - Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating activities
Net loss	$ 185,565	$ (126,057)	$ (103,273)	$ (50,226)	$ (122,079)	$ (63,405)	$ (8,467)	$ (28,841)	$ (93,991)	$ (222,792)	$ (283,780)
Adjustments to reconcile net loss to net cash provided by operating activities:
Equity-based compensation									35,230	39,913	40,084
Deferred income taxes									9,145	9,505	(23,561)
Other									2,865	5,952	13,355
Changes in assets and liabilities:
Decrease in receivables									175,954	29,365	(20,558)
(Increase) decrease in prepaid expenses and other									(18,731)	(31,710)	17,557
Net cash provided by operating activities									260,491	236,617	52,077
Investing activities
Net cash used in investing activities									(985,138)	(152,565)	(537,763)
Financing activities
Payments on long-term debt									(325,000)	(250,000)	0
Purchase of treasury stock / tax withholdings									(206,051)	(2,194)	(1,981)
Deferred financing costs									(38,672)	(67)	0
Net cash provided by (used in) financing activities									605,277	(52,261)	448,019
Net increase (decrease) in cash, cash equivalents and restricted cash									(119,370)	31,791	(37,667)
Cash, cash equivalents and restricted cash at end of period				304,986				273,195	304,986	273,195	310,862
Cash, cash equivalents and restricted cash at beginning of period	185,616				304,986				185,616	304,986	273,195
Parent company
Operating activities
Net loss									(93,991)	(222,792)	(283,780)
Adjustments to reconcile net loss to net cash provided by operating activities:
Equity in losses of subsidiaries									23,614	155,878	220,031
Equity-based compensation									35,230	39,913	40,423
Amortization									7,292	3,070	3,070
Deferred income taxes									1,132	0	0
Other									268	3,884	3,530
Changes in assets and liabilities:
Decrease in receivables									1,234	986	0
(Increase) decrease in prepaid expenses and other									(23)	127	52
(Increase) decrease due to/from related party									(42,163)	14,463	(15,201)
Increase in accounts payable and accrued liabilities									816	1,179	312
Net cash provided by operating activities									(66,591)	(3,292)	(31,563)
Investing activities
Investment in subsidiaries									(36,192)	4,691	(40,047)
Net cash used in investing activities									(36,192)	4,691	(40,047)
Financing activities
Net proceeds from issuance of senior secured notes									400,000	0	0
Payments on long-term debt									(75,000)
Purchase of treasury stock / tax withholdings									(206,051)	(2,194)	(1,981)
Deferred financing costs									(9,382)	0	0
Net cash provided by (used in) financing activities									109,567	(2,194)	(1,981)
Net increase (decrease) in cash, cash equivalents and restricted cash									6,784	(795)	(73,591)
Cash, cash equivalents and restricted cash at end of period				$ 297				$ 1,092	297	1,092	74,683
Cash, cash equivalents and restricted cash at beginning of period	$ 7,081				$ 297				7,081	297	1,092
Non-cash activity:
Issuance of common stock for related party receivable									$ 307,944	$ 0	$ 0

Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Allowance for doubtful receivables
Changes in valuation and qualifying Accounts
Balance at the beginning of the period	$ 0	$ 574	$ 0
Charged to Costs and Expenses	1,211	77	574
Charged To Other Accounts	0	0	0
Deductions From Reserves	0	(651)	0
Balance at the end of the period	1,211	0	574
Allowance for deferred tax assets
Changes in valuation and qualifying Accounts
Balance at the beginning of the period	93,525	87,517	116,541
Charged to Costs and Expenses	63,335	6,008	(29,024)
Charged To Other Accounts	0	0	0
Deductions From Reserves	0	0	0
Balance at the end of the period	$ 156,860	$ 93,525	$ 87,517

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Cash Flows [Abstract]
Cash settlements on commodity hedges derivatives	$ (137.1)	$ 38.7	$ 188.0

Organization (Details)	12 Months Ended
Organization (Details)	Dec. 31, 2018 segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of reportable geographic areas	4

Suspended Well Costs - Narrative (Details) $ in Millions	1 Months Ended	12 Months Ended
Suspended Well Costs - Narrative (Details) $ in Millions	May 31, 2015 exploration_well	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Capitalized Contract Cost [Line Items]
Capitalized exploratory well costs subsequently expensed in the same period \| $		$ 65.6	$ 43.2	$ 2.4
Greater Tortue Ahmeyim Project
Capitalized Contract Cost [Line Items]
Number of additional wells drilled \| exploration_well	2