Kosmos Energy (KOS) 10-Q 7 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 01, 2018
Document and Entity Information
Entity Registrant Name	Kosmos Energy Ltd.
Entity Central Index Key	1,509,991
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		396,123,151
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 198,841	$ 233,412
Restricted cash	35,378	56,380
Receivables:
Joint interest billings, net	76,642	134,565
Related party	2,780	780
Other	20,752	25,616
Inventories	79,710	71,861
Prepaid expenses and other	31,311	9,306
Derivatives	3,461	1,682
Total current assets	448,875	533,602
Property and equipment:
Oil and gas properties, net	2,297,246	2,310,973
Other property, net	9,291	6,855
Property and equipment, net	2,306,537	2,317,828
Other assets:
Equity method investment	190,211	236,514
Restricted cash	21,509	15,194
Long-term receivables - joint interest billings	28,001	34,941
Deferred financing costs, net of accumulated amortization of $14,636 and $13,951 at March 31, 2018 and December 31, 2017, respectively	1,825	2,510
Deferred tax assets	22,240	22,517
Derivatives	1,093	39
Other	10,237	29,458
Total assets	3,030,528	3,192,603
Current liabilities:
Accounts payable	138,233	141,787
Accrued liabilities	136,260	219,412
Derivatives	84,015	67,531
Total current liabilities	358,508	428,730
Long-term liabilities:
Long-term debt, net	1,265,196	1,282,797
Derivatives	35,127	30,209
Asset retirement obligations	68,325	66,595
Deferred tax liabilities	451,574	476,548
Other long-term liabilities	8,394	10,612
Total long-term liabilities	1,828,616	1,866,761
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at March 31, 2018 and December 31, 2017	0	0
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 404,979,468 and 398,599,457 issued at March 31, 2018 and December 31, 2017, respectively	4,050	3,986
Additional paid-in capital	2,011,489	2,014,525
Accumulated deficit	(1,123,428)	(1,073,202)
Treasury stock, at cost, 9,263,269 and 9,188,819 shares at March 31, 2018 and December 31, 2017, respectively	(48,707)	(48,197)
Total shareholders’ equity	843,404	897,112
Total liabilities and shareholders’ equity	$ 3,030,528	$ 3,192,603

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Deferred financing costs, accumulated amortization	$ 14,636	$ 13,951
Preference shares, par value (in dollars per share)	$ 0.01	$ 0.01
Preference shares, authorized shares (in shares)	200,000,000	200,000,000
Preference shares, issued shares (in shares)	0	0
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, authorized shares (in shares)	2,000,000,000	2,000,000,000
Common shares, issued shares (in shares)	404,979,468	398,599,457
Treasury stock shares (in shares)	9,263,269	9,188,819

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues and other income:
Oil and gas revenue	$ 127,196	$ 103,432
Other income, net	(19)	48,534
Total revenues and other income	127,177	151,966
Costs and expenses:
Oil and gas production	46,768	19,886
Facilities insurance modifications, net	8,449	2,574
Exploration expenses	21,193	105,714
General and administrative	21,883	15,787
Depletion and depreciation	54,277	34,978
Interest and other financing costs, net	25,694	16,786
Derivatives, net	38,478	(37,857)
Gain on equity method investments, net	(18,696)	0
Other expenses, net	3,705	762
Total costs and expenses	201,751	158,630
Loss before income taxes	(74,574)	(6,664)
Income tax expense (benefit)	(24,348)	22,177
Net loss	$ (50,226)	$ (28,841)
Net loss per share:
Basic (in dollars per share)	$ (0.13)	$ (0.07)
Diluted (in dollars per share)	$ (0.13)	$ (0.07)
Weighted average number of shares used to compute net loss per share:
Basic (in shares)	395,600	387,312
Diluted (in shares)	395,600	387,312

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - 3 months ended Mar. 31, 2018 - USD ($) shares in Thousands, $ in Thousands	Total	Common Shares	Additional Paid-in Capital	Accumulated Deficit	Treasury Stock
Balance at the beginning (in shares) at Dec. 31, 2017		398,599
Balance at the beginning at Dec. 31, 2017	$ 897,112	$ 3,986	$ 2,014,525	$ (1,073,202)	$ (48,197)
Increase (Decrease) in Shareholders' Equity
Equity-based compensation	8,392		8,392
Restricted stock awards and units (in shares)		6,380
Restricted stock awards and units	0	$ 64	(64)
Purchase of treasury stock / tax withholdings	(11,874)		(11,364)		(510)
Net loss	(50,226)			(50,226)
Balance at the end (in shares) at Mar. 31, 2018		404,979
Balance at the end at Mar. 31, 2018	$ 843,404	$ 4,050	$ 2,011,489	$ (1,123,428)	$ (48,707)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating activities
Net loss	$ (50,226)	$ (28,841)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and amortization	56,717	37,529
Deferred income taxes	(24,697)	22,133
Unsuccessful well costs	43	88
Change in fair value of derivatives	38,966	(38,177)
Cash settlements on derivatives, net (including $(19.7) million and $11.4 million on commodity hedges during 2018 and 2017)	(20,397)	11,153
Equity-based compensation	8,017	9,830
Loss on extinguishment of debt	4,056	0
Distributions in excess of equity in earnings	5,234	0
Other	(478)	621
Changes in assets and liabilities:
(Increase) decrease in receivables	67,937	(44,853)
Increase in inventories	(7,849)	(10,044)
(Increase) decrease in prepaid expenses and other	(2,439)	352
Decrease in accounts payable	(3,554)	(2,905)
Increase (decrease) in accrued liabilities	(88,346)	12,732
Net cash used in operating activities	(17,016)	(30,382)
Investing activities
Oil and gas assets	(34,712)	(31,810)
Other property	(1,757)	(271)
Return of investment from KTIPI	41,070	0
Proceeds on sale of assets	0	203,919
Net cash provided by investing activities	4,601	171,838
Financing activities
Payments on long-term debt	0	(150,000)
Purchase of treasury stock / tax withholdings	(11,874)	(1,115)
Deferred financing costs	(24,969)	0
Net cash used in financing activities	(36,843)	(151,115)
Net decrease in cash, cash equivalents and restricted cash	(49,258)	(9,659)
Cash, cash equivalents and restricted cash at beginning of period	304,986	273,195
Cash, cash equivalents and restricted cash at end of period	255,728	263,536
Cash paid for:
Interest	33,280	20,559
Income taxes	21,243	0
Non-cash activity:
Conversion of joint interest billings receivable to long-term note receivable	0	4,042
Contribution to equity method investment	$ 0	$ 133,894

CONSOLIDATED STATEMENTS OF CAS7

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Statement of Cash Flows [Abstract]
Cash settlements on derivatives, net (commodity hedges)	$ (19.7)	$ 11.4

Organization

Organization	3 Months Ended
	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise. Kosmos is a pure play deepwater oil and gas company with growing production, a pipeline of development opportunities and a balanced exploration portfolio along the Atlantic Margins. Our assets include growing production offshore Ghana and Equatorial Guinea, a competitively positioned Tortue gas project in Mauritania and Senegal and a sustainable exploration program balanced between proven basins (Equatorial Guinea), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Cote d'Ivoire and Sao Tome and Principe). Kosmos is listed on the New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS. We have one reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are related to production located offshore Ghana. We also have an equity method investment generating revenues with operations offshore Equatorial Guinea.

Accounting Policies

Accounting Policies	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Accounting Policies	Accounting Policies General The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of March 31, 2018 , and the changes in the consolidated statements of shareholders’ equity, consolidated results of operations, and the consolidated cash flows for the three months ended March 31, 2018 and 2017 . The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2017 , included in our annual report on Form 10-K. Reclassifications Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net loss , current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows. Cash, Cash Equivalents and Restricted Cash March 31, December 31, (In thousands) Cash and cash equivalents $ 198,841 $ 233,412 Restricted cash - current 35,378 56,380 Restricted cash - long-term 21,509 15,194 Total cash, cash equivalents and restricted cash $ 255,728 $ 304,986 Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. In accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of March 31, 2018 and December 31, 2017 , we had $35.4 million and $31.6 million , respectively, of current restricted cash and $21.5 million and $15.2 million , respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts. In addition, prior to our commercial debt facility (the "Facility") being amended and restated, we were required to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six -month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver or the Facility, whichever is greater. As of December 31, 2017 , we had $24.8 million in current restricted cash to meet this requirement. Under the amended and restated Facility, we are no longer required to maintain a restricted cash balance provided we are compliant with certain financial covenant ratios. Inventories Inventories consisted of $67.0 million and $63.5 million of materials and supplies and $12.7 million and $8.4 million of hydrocarbons as of March 31, 2018 and December 31, 2017 , respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs. Revenue Recognition We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of March 31, 2018 and December 31, 2017 , we had no oil and gas imbalances recorded in our consolidated financial statements. Our oil and gas revenues are recognized based on the product that has transferred to the customer during the lifting process as of a point in time when control has transferred, usually over a 24 hour period, and based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale. Oil and gas revenue is composed of the following: Three Months Ended March 31, 2018 2017 (In thousands) Revenue from contracts with customers - Ghana $ 128,037 $ 103,441 Provisional oil sales contracts (841 ) (9 ) Oil and gas revenue $ 127,196 $ 103,432 Recent Accounting Standards Recently Adopted In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company adopted the new standard during the first quarter of 2018 using the modified retrospective approach and there is no impact to our previously recorded revenue under the new standard. In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740).” ASU 2018-05 was issued to include amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 ("SAB 118") and addresses certain circumstances that may arise for registrants in accounting for the income tax effects of the Tax Cut and Jobs Act (the "Tax Reform Act"), including when certain income tax effects of the Tax Reform Act are incomplete by the time the financial statements are issued. Not Yet Adopted In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The new leasing standard requires the modified retrospective adoption method. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements.

Acquisitions and Divestitures

Acquisitions and Divestitures	3 Months Ended
	Mar. 31, 2018
Acquisitions and Divestitures
Acquisitions and Divestitures	Acquisitions and Divestitures In March 2018, as part of our alliance with BP, we entered into petroleum contracts covering Blocks 10 and 13 with the Democratic Republic of Sao Tome and Principe. We presently have a 35% participating interest in the blocks and the operator, BP, holds a 50% participating interest. The national petroleum agency, Agencia Nacional Do Petroleo De Sao Tome E Principe ("ANP STP") has a 15% carried interest in the blocks through exploration. In March 2018, we signed a farm-in agreement with a subsidiary of Ophir Energy plc ("Ophir") for Block EG-24, offshore Equatorial Guinea, whereby we acquired a 40% 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. 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 located in Block G offshore Equatorial Guinea. Under the terms of the agreement, Kosmos and Trident each own 50% of Hess International Petroleum Inc, which was subsequently renamed Kosmos-Trident International Petroleum Inc. ("KTIPI"). Kosmos is primarily responsible for exploration and subsurface evaluation while Trident is primarily responsible for production operations and optimization. The gross acquisition price was $650 million effective as of January 1, 2017 . Kosmos paid net cash consideration of approximately $231 million at close with a combination of cash on hand and amounts borrowed under the Facility. The transaction is accounted for as an equity method investment. In October 2017, we entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. We presently have an 80% interest and are the operator in all three blocks, but pursuant to an agreement with Trident we expect to assign a 40% interest in the blocks to an affiliate of Trident. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), currently has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration period of five years from the 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. Upon the assignment of a 40% interest to the Trident affiliate noted above, interests in these three blocks will be 40% Kosmos, 40% Trident and 20% GEPetrol. In December 2017 , as part of our alliance with BP, we entered into petroleum contracts covering Blocks CI-526, CI-602, CI-603, CI-707 and CI-708 with the Government of Cote d'Ivoire. We have a 45% participating interest and are the operator in all five blocks. BP has a 45% participating interest in the blocks and the Cote d'Ivoire national oil company, PETROCI Holding ("PETROCI"), currently has a 10% carried interest. The petroleum contracts cover approximately 17,000 square kilometers, with a first exploration period of three years. The first exploration period work program includes a 12,000 square kilometer 3D seismic acquisition across the five blocks.

Joint Interest Billings

Joint Interest Billings	3 Months Ended
	Mar. 31, 2018
Joint Interest Billings
Joint Interest Billings	Joint Interest Billings The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur. In 2014, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners of its request for the contractor group to pay GNPC’s 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners will be reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of March 31, 2018 and December 31, 2017 , the current portion of the joint interest billing receivables due from GNPC for the TEN fields development costs were $14.0 million and $15.2 million , respectively, and the long-term portion were $28.0 million and $31.6 million , respectively.

Property and Equipment

Property and Equipment	3 Months Ended
	Mar. 31, 2018
Property, Plant and Equipment [Abstract]
Property and Equipment	Property and Equipment Property and equipment is stated at cost and consisted of the following: March 31, December 31, (In thousands) Oil and gas properties: Proved properties $ 1,661,368 $ 1,653,616 Unproved properties 485,281 465,109 Support equipment and facilities 1,437,010 1,427,054 Total oil and gas properties 3,583,659 3,545,779 Accumulated depletion (1,286,413 ) (1,234,806 ) Oil and gas properties, net 2,297,246 2,310,973 Other property 42,781 39,405 Accumulated depreciation (33,490 ) (32,550 ) Other property, net 9,291 6,855 Property and equipment, net $ 2,306,537 $ 2,317,828 We recorded depletion expense of $51.6 million and $32.5 million for the three months ended March 31, 2018 and 2017 , respectively.

Suspended Well Costs

Suspended Well Costs	3 Months Ended
	Mar. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Suspended Well Costs	Suspended Well Costs The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the three months ended March 31, 2018 . The table excludes $42.7 thousand in costs that were capitalized and subsequently expensed during the same period. March 31, (In thousands) Beginning balance $ 410,113 Additions to capitalized exploratory well costs pending the determination of proved reserves 2,018 Reclassification due to determination of proved reserves — Capitalized exploratory well costs charged to expense — Ending balance $ 412,131 The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: March 31, 2018 December 31, 2017 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 67,666 $ 67,159 Exploratory well costs capitalized for a period of one to two years 292,113 291,252 Exploratory well costs capitalized for a period of three to six years 52,352 51,702 Ending balance $ 412,131 $ 410,113 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 5 5 As of March 31, 2018 , the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Akasa discovery in the West Cape Three Points (“WCTP”) Block and the Wawa discovery in the DT Block, which are all located offshore Ghana, the Greater Tortue discovery which crosses the Mauritania and Senegal maritime border, the BirAllah discovery (formerly known as the Marsouin discovery) in Block C8 offshore Mauritania and the Teranga discovery in the Cayar Offshore Profond block offshore Senegal. Akasa Discovery — We are currently in discussions with the government of Ghana regarding additional technical studies and evaluation that we want to conduct before we are able to make a determination regarding commerciality of the discovery. If we determine the discovery to be commercial, a declaration of commerciality would be provided and a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP petroleum contract. Wawa Discovery — We are currently in discussions with the Ministry of Energy with respect to conducting further subsurface and development concept evaluation in an effort to enlarge the TEN development and production area to capture the resource accumulation located in the Wawa Discovery Area for a potential future integrated development with the TEN fields. Greater Tortue Discovery — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania which encountered hydrocarbon pay. Two additional wells have been drilled in the Greater Tortue Discovery area, Ahmeyim-2 in Mauritania and Guembeul-1 in Senegal. We completed a drill stem test on the Tortue‑1 well in August 2017, which confirmed the production capabilities of the Greater Tortue Discovery. Data acquired from the drill stem test will be used to further optimize field development and to refine process design parameters critical to the Front End Engineering Design ("FEED") process. Following additional evaluation, a decision regarding commerciality will be made. BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well (renamed BirAllah) in the northern part of Block C8 offshore Mauritania which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality will be made. Teranga Discovery — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality will be made.

Equity Method Investments

Equity Method Investments	3 Months Ended
	Mar. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Equity Method Investments Kosmos BP Senegal Limited ("KBSL") As part of our transaction in Senegal with BP in February 2017, our participating interests in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") were contributed to KBSL, a corporate joint venture in which we owned a 50.01% interest. In October 2017, KBSL transferred a 30% participating interest in the Senegal Blocks to BP Senegal Investments Limited in exchange for its outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and no longer is accounted for under the equity method of accounting. After the transfer, KBSL has a 30% participating interest in the Senegal Blocks. Prior to the acquisition of the remaining outstanding shares of KBSL in October 2017, our investment in KBSL qualified for the equity method of accounting. Our initial contribution to KBSL was $133.9 million , which was recorded at our carrying costs. Equatorial Guinea As part of our acquisition of KTIPI, a corporate joint venture in which we own a 50% interest, we acquired an indirect participating interest in Block G offshore Equatorial Guinea. The objective of this transaction was to acquire the Ceiba Field and Okume Complex with the intent to optimize production and increase reserves. Below is a summary of financial information for KTIPI presented on a 100% basis. March 31, December 31, 2018 2017 (In thousands) Assets Total current assets $ 238,567 $ 179,070 Property and equipment, net 338,096 345,611 Other assets 555 567 Total assets $ 577,218 $ 525,248 Liabilities and shareholders' equity Total current liabilities $ 177,807 $ 106,769 Total long term liabilities 552,727 565,591 Shareholders' equity: Total shareholders' equity (153,316 ) (147,112 ) Total liabilities and shareholders' equity $ 577,218 $ 525,248 Three Months Ended March 31, 2018 (In thousands) Revenues and other income: Oil and gas revenue $ 246,354 Other income 287 Total revenues and other income 246,641 Costs and expenses: Oil and gas production 51,700 Depletion and depreciation 54,070 Other expenses, net (79 ) Total costs and expenses 105,691 Income before income taxes 140,950 Income tax expense 49,632 Net income $ 91,318 Kosmos' share of net income $ 45,659 Basis difference amortization(1) 26,963 Equity in earnings - KTIPI $ 18,696 ______________________________________ (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 March 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 three months ended March 31, 2018 , we received $65 million of cash dividends from KTIPI.

Debt

Debt	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Debt	Debt March 31, December 31, (In thousands) Outstanding debt principal balances: Facility $ 800,000 $ 800,000 Senior Notes 525,000 525,000 Total 1,325,000 1,325,000 Unamortized deferred financing costs and discounts(1) (59,804 ) (42,203 ) Long-term debt, net $ 1,265,196 $ 1,282,797 __________________________________ (1) Includes $42.3 million and $23.6 million of unamortized deferred financing costs related to the Facility and $17.5 million and $18.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of March 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. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of the debt refinancing in February 2018, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and $4.1 million of existing unamortized debt issuance costs and deferred interest attributable to those participants was expensed in interest and other financing costs, net in the first quarter of 2018. As of March 31, 2018 , we have $42.3 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility. As of March 31, 2018 , borrowings under the Facility totaled $800.0 million and the undrawn availability under the Facility was $700.0 million . In May 2018, the Company voluntarily repaid $75.0 million of outstanding borrowings under the Facility, bringing the outstanding borrowings to $725.0 million . 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 March 31, 2018 , we had no letters of credit issued under the Facility. We were in compliance with the financial covenants contained in the Facility as of March 31, 2018 (the most recent assessment date). The Facility contains customary cross default provisions. Corporate Revolver Our Corporate Revolver, from a number of financial institutions, has borrowing capacity to $400.0 million and is available for all subsidiaries for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of March 31, 2018 , we have $1.8 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term, which expires in November 2018. These deferred financing costs are included in the Other assets section of the consolidated balance sheets. As of March 31, 2018 , there were no outstanding borrowings under the Corporate Revolver. We were in compliance with the financial covenants contained in the Corporate Revolver as of March 31, 2018 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions. Revolving Letter of Credit Facility We have a revolving letter of credit facility agreement (“LC Facility”), which matures in July 2019 . During the first quarter of 2018, the LC Facility size was increased to $73.0 million to facilitate the issuance of additional letters of credit. As of March 31, 2018 , there were thirteen outstanding letters of credit totaling $72.8 million under the LC Facility. The LC Facility contains customary cross default provisions. 7.875% Senior Secured Notes due 2021 During August 2014, the Company issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. During April 2015, we issued an additional $225.0 million of Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million of Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued. The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries. At March 31, 2018 , the estimated repayments of debt during the five fiscal year periods and thereafter are as follows: Payments Due by Year Total 2018(2) 2019 2020 2021 2022 Thereafter (In thousands) Principal debt repayments(1) $ 1,325,000 $ — $ — $ — $ 525,000 $ — $ 800,000 __________________________________ (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on, as of March 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. As of March 31, 2018 , there were no borrowings under the Corporate Revolver. (2) Represents payments for the period April 1, 2018 through December 31, 2018 . Interest and other financing costs, net Interest and other financing costs, net incurred during the periods is comprised of the following: Three Months Ended March 31, 2018 2017 (In thousands) Interest expense $ 24,893 $ 23,181 Amortization—deferred financing costs 2,440 2,551 Loss on extinguishment of debt 4,056 — Capitalized interest (4,820 ) (9,559 ) Deferred interest (1,256 ) 315 Interest income (948 ) (980 ) Other, net 1,329 1,278 Interest and other financing costs, net $ 25,694 $ 16,786

Derivative Financial Instrument

Derivative Financial Instruments	3 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Derivative Financial Instruments We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes. We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820 — Fair Value Measurements and Disclosures. Oil Derivative Contracts The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of March 31, 2018 . Volumes and weighted average prices are net of any offsetting derivative contracts entered into. Weighted Average Dated Brent Price per Bbl Net Deferred Premium Term Type of Contract MBbl Payable/(Receivable) Swap Sold Put Floor Ceiling Call 2018: April — December Swap with puts 1,500 $ — $ 54.32 $ 40.00 $ — $ — $ — July — December Swap with puts 2,000 — 57.96 45.00 — — — April — June Swaps 500 — 57.25 — — — — April — December Three-way collars 2,193 0.74 — 41.57 56.57 65.90 — April — December Four-way collars 2,252 1.06 — 40.00 50.00 61.33 70.00 April — December Sold calls(1) 1,505 — — — — 65.00 — July — December Purchased Calls 1,000 — — — — — 70.00 2019: January — December Three-way collars 9,500 $ (0.06 ) $ — $ 43.16 $ 52.63 $ 65.01 $ — January — December Sold calls(1) 913 — — — — 80.00 — __________________________________ (1) Represents call option contracts sold to counterparties to enhance other derivative positions. In April 2018, we entered into three-way collar contracts for 1.0 MMBbl from January 2019 through December 2019 with a sold put price of $50.00 per barrel, a floor price of $60.00 per barrel and a ceiling price of $75.00 per barrel. The contracts are indexed to Dated Brent prices. Interest Rate Derivative Contracts The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of March 31, 2018 : Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) April 2018 — December 2018 Capped swap 1-month LIBOR $ 200,000 1.23 % 3.00 % The following tables disclose the Company’s derivative instruments as of March 31, 2018 and December 31, 2017 and gain/(loss) from derivatives during the three months ended March 31, 2018 and 2017 , respectively: Estimated Fair Value Asset (Liability) Type of Contract Balance Sheet Location March 31, December 31, (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ 2,279 $ 665 Interest rate Derivatives assets—current 1,182 1,017 Commodity(2) Derivatives assets—long-term 1,093 39 Derivative liabilities: Commodity(3) Derivatives liabilities—current (84,015 ) (67,531 ) Commodity(4) Derivatives liabilities—long-term (35,127 ) (30,209 ) Total derivatives not designated as hedging instruments $ (114,588 ) $ (96,019 ) __________________________________ (1) Includes net deferred premiums payable of $0.4 million and net deferred premiums receivable of $0.8 million related to commodity derivative contracts as of March 31, 2018 and December 31, 2017 , respectively. (2) Includes net deferred premiums receivable of $4.0 million and $0.1 million related to commodity derivative contracts as of March 31, 2018 and December 31, 2017 , respectively. (3) Includes net deferred premiums payable of $5.3 million and $5.6 million related to commodity derivative contracts as of March 31, 2018 and December 31, 2017 , respectively. (4) Includes net deferred premiums payable of $3.5 million and $4.8 million related to commodity derivative contracts as of March 31, 2018 and December 31, 2017 , respectively. Amount of Gain/(Loss) Three Months Ended March 31, Type of Contract Location of Gain/(Loss) 2018 2017 (In thousands) Derivatives not designated as hedging instruments: Commodity(1) Oil and gas revenue $ (841 ) $ (8 ) Commodity Derivatives, net (38,478 ) 37,857 Interest rate Interest expense 353 328 Total derivatives not designated as hedging instruments $ (38,966 ) $ 38,177 __________________________________ (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 March 31, 2018 and December 31, 2017 , there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements In accordance with ASC Topic 820 — Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy: • Level 1 — quoted prices for identical assets or liabilities in active markets. • Level 2 — quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means. • Level 3 — unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2018 and December 31, 2017 , for each fair value hierarchy level: Fair Value Measurements Using: Quoted Prices in Active Markets for Significant Other Significant Identical Assets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) March 31, 2018 Assets: Commodity derivatives $ — $ 3,372 $ — $ 3,372 Interest rate derivatives — 1,182 — 1,182 Liabilities: Commodity derivatives — (119,142 ) — (119,142 ) Total $ — $ (114,588 ) $ — $ (114,588 ) December 31, 2017 Assets: Commodity derivatives $ — $ 704 $ — $ 704 Interest rate derivatives — 1,017 — 1,017 Liabilities: Commodity derivatives — (97,740 ) — (97,740 ) Total $ — $ (96,019 ) $ — $ (96,019 ) The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs. Commodity Derivatives Our commodity derivatives represent crude oil collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for Dated Brent, (iii) a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for Dated Brent. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 9 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments. Provisional Oil Sales The value attributable to provisional oil sales derivatives is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for Dated Brent over the term of the pricing period designated in the sales contract and the spot price on the lifting date. Interest Rate Derivatives Our interest rate derivatives consist of interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate, and capped interest rate swaps, whereby the Company pays a fixed rate of interest if LIBOR is below the cap and pays the market rate less the spread between the cap and the fixed rate of interest if LIBOR is above the cap. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) LIBOR yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market. Debt The following table presents the carrying values and fair values at March 31, 2018 and December 31, 2017 : March 31, 2018 December 31, 2017 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 508,630 $ 537,773 $ 507,600 $ 542,472 Facility 800,000 800,000 800,000 800,000 Total $ 1,308,630 $ 1,337,773 $ 1,307,600 $ 1,342,472 The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.

Equity-based Compensation

Equity-based Compensation	3 Months Ended
	Mar. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-based Compensation	Equity-based Compensation Restricted Stock Awards and Restricted Stock Units We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long-Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $8.0 million and $9.8 million during the three months ended March 31, 2018 and 2017 , respectively. The total tax benefit for the three months ended March 31, 2018 and 2017 was $0.9 million and $3.3 million , respectively. Additionally, we expensed a tax shortfall related to equity-based compensation of $0.2 million and $0.5 million for the three months ended March 31, 2018 and 2017 , respectively. The fair value of awards vested during the three months ended March 31, 2018 and 2017 was approximately $56.6 million and $8.8 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 these awards vest over three or four year periods. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock. The following table reflects the outstanding restricted stock awards as of March 31, 2018 : Weighted- Service Vesting Average Restricted Stock Grant-Date Awards Fair Value (In thousands) Outstanding at December 31, 2017 220 $ 8.64 Granted — — Forfeited — — Vested (220 ) 8.64 Outstanding at March 31, 2018 — — The following table reflects the outstanding restricted stock units as of March 31, 2018 : Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Units Fair Value Units Fair Value (In thousands) (In thousands) Outstanding at December 31, 2017 4,183 $ 6.39 8,452 $ 11.26 Granted(1) 1,893 6.99 7,259 12.42 Forfeited (23 ) 6.57 (25 ) 15.71 Vested (1,524 ) 5.88 (6,519 ) 12.99 Outstanding at March 31, 2018 4,529 6.76 9,167 10.94 __________________________________ (1) The restricted stock units with a combination of market and service vesting criteria include 4.9 million shares granted as a result of the 2014 and 2015 awards achieving 200% of their respective market performance conditions. As of March 31, 2018 , total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $50.3 million over a weighted average period of 2.38 years . At March 31, 2018 , the Company had approximately 4.6 million shares that remain available for issuance under the LTIP. For restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 200% of the awards granted. The grant date fair value ranged from $4.83 to $15.71 per award. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 44.0% to 53.0% . The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.7% to 2.2% .

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero tax rate and tax-exempt jurisdictions from our evaluation of the estimated annual effective income tax rate. The tax effect of discrete items are recognized in the period in which they occur at the applicable statutory tax rate. On December 22, 2017, the President of the United States signed P.L. 115-97, the Tax Reform Act into law. SAB 118 was issued in January 2018 to address situations where certain aspects of the Jobs Act are unclear at issuance of a registrant’s financial statements for the reporting period in which the Jobs Act became law. SAB 118 allows us to record provisional amounts during a one-year measurement period. We are analyzing certain aspects of the Jobs Act which could affect the measurement of deferred tax balances or potentially give rise to new deferred tax amounts. The income tax provision consists of United States and Ghanaian income and Texas margin taxes. Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets. Income (loss) before income taxes is composed of the following: Three Months Ended March 31, 2018 2017 (In thousands) Bermuda $ (16,071 ) $ (16,181 ) United States 1,633 1,412 Foreign—other (60,136 ) 8,105 Income (loss) before income taxes $ (74,574 ) $ (6,664 ) Our effective tax rate for the three months ended March 31, 2018 and 2017 is 33% and 333% , respectively. The effective tax rate is primarily impacted by the effect of non-deductible expenditures, including amounts associated with the damage to the Jubilee turret bearing, which we expect to recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax. The Company files income tax returns in all jurisdictions where such requirements exist, however, our primary tax jurisdictions are Ghana and the United States. The Company is open to Ghanaian federal income tax examinations for tax years 2014 through 2017 and in the United States, to federal income tax examinations for tax years 2014 through 2017. As of March 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 Loss Per Share

Net Loss Per Share	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Net Loss Per Share	Net Loss Per Share The following table is a reconciliation between net loss and the amounts used to compute basic and diluted net loss per share and the weighted average shares outstanding used to compute basic and diluted net loss per share: Three Months Ended March 31, 2018 2017 Numerator: Net loss $ (50,226 ) $ (28,841 ) Basic income allocable to participating securities(1) — — Basic net loss allocable to common shareholders (50,226 ) (28,841 ) Diluted adjustments to income allocable to participating securities(1) — — Diluted net loss allocable to common shareholders $ (50,226 ) $ (28,841 ) Denominator: Weighted average number of shares outstanding: Basic 395,600 387,312 Restricted stock awards and units(1)(2) — — Diluted 395,600 387,312 Net loss per share: Basic $ (0.13 ) $ (0.07 ) Diluted $ (0.13 ) $ (0.07 ) __________________________________ (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net loss per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net loss per common share calculation in periods we are in a net loss position. (2) We excluded outstanding restricted stock awards and units of 11.3 million and 14.6 million for the three months ended March 31, 2018 and 2017 , respectively, from the computations of diluted net loss per share because the effect would have been anti-dilutive .

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year. We currently have a commitment to drill one exploration well in Mauritania. In Mauritania, our partner is obligated to fund our share of the cost of the exploration well, subject to the remaining exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Cote d'Ivoire, Equatorial Guinea, Mauritania and Sao Tome and Principe, we have 3D seismic requirements of approximately 12,000 square kilometers, 9,000 square kilometers, 7,600 square kilometers and 13,500 square kilometers, respectively. Future minimum rental commitments under our leases at March 31, 2018 , are as follows: Payments Due By Year(1) Total 2018(2) 2019 2020 2021 2022 Thereafter (In thousands) Operating leases(3) $ 13,489 $ 4,080 $ 5,251 $ 1,366 $ 419 $ 419 $ 1,954 __________________________________ (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. (2) Represents payments for the period from April 1, 2018 through December 31, 2018 . (3) Primarily relates to corporate office and foreign office leases.

Additional Financial Informatio

Additional Financial Information	3 Months Ended
	Mar. 31, 2018
Additional Financial Information
Additional Financial Information	Additional Financial Information Accrued Liabilities Accrued liabilities consisted of the following: March 31, December 31, (In thousands) Accrued liabilities: Exploration, development and production $ 99,905 $ 144,717 General and administrative expenses 12,881 31,124 Interest 11,040 20,457 Income taxes 898 17,423 Taxes other than income 1,794 3,270 Derivatives 5,825 825 Deferred financing costs 1,492 — Other 2,425 1,596 $ 136,260 $ 219,412 Other Income, Net Other income, net consisted of zero and $48.5 million Loss of Production Income (“LOPI”) proceeds, net related to the turret bearing issue on the Jubilee FPSO for the three months ended March 31, 2018 and 2017 . Our LOPI coverage for this incident ended in May 2017. Oil and Gas Production Oil and gas production expense included insurance recoveries related to our increased cost of working covered by our LOPI policy of zero and $3.4 million for the three months ended March 31, 2018 and 2017 , respectively. Facilities Insurance Modifications, Net Facilities insurance modifications, net consists of costs associated with the long-term solution to convert the Jubilee FPSO to a permanently spread moored facility which we expect to recover from our insurance policy net of any insurance reimbursements. Other Expenses, Net Other expenses, net incurred during the period is comprised of the following: Three Months Ended March 31, 2018 2017 (In thousands) Gain on insurance settlements $ — $ (461 ) Disputed charges and related costs 3,268 1,230 Other, net 437 (7 ) Other expenses, net $ 3,705 $ 762 The disputed charges and related costs are expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow has charged such expenditures to the Deepwater Tano (“DT”) joint account. Kosmos disputes that these expenditures are chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement.

Accounting Policies (Policies)

Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
General	General The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of March 31, 2018 , and the changes in the consolidated statements of shareholders’ equity, consolidated results of operations, and the consolidated cash flows for the three months ended March 31, 2018 and 2017 . The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2017 , included in our annual report on Form 10-K.
Reclassifications	Reclassifications Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net loss , current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows.
Cash, Cash Equivalents and Restricted Cash	Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. In accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. Cash, Cash Equivalents and Restricted Cash
Inventories	The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs. Inventories
Revenue Recognition	Revenue Recognition We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. Our oil and gas revenues are recognized based on the product that has transferred to the customer during the lifting process as of a point in time when control has transferred, usually over a 24 hour period, and based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale.
Recent Accounting Standards	Recent Accounting Standards Recently Adopted In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company adopted the new standard during the first quarter of 2018 using the modified retrospective approach and there is no impact to our previously recorded revenue under the new standard. In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740).” ASU 2018-05 was issued to include amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 ("SAB 118") and addresses certain circumstances that may arise for registrants in accounting for the income tax effects of the Tax Cut and Jobs Act (the "Tax Reform Act"), including when certain income tax effects of the Tax Reform Act are incomplete by the time the financial statements are issued. Not Yet Adopted In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The new leasing standard requires the modified retrospective adoption method. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements.

Accounting Policies (Tables)

Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Schedule of cash and cash equivalents	March 31, December 31, (In thousands) Cash and cash equivalents $ 198,841 $ 233,412 Restricted cash - current 35,378 56,380 Restricted cash - long-term 21,509 15,194 Total cash, cash equivalents and restricted cash $ 255,728 $ 304,986
Schedule of oil and gas revenue	Oil and gas revenue is composed of the following: Three Months Ended March 31, 2018 2017 (In thousands) Revenue from contracts with customers - Ghana $ 128,037 $ 103,441 Provisional oil sales contracts (841 ) (9 ) Oil and gas revenue $ 127,196 $ 103,432

Property and Equipment (Tables)

Property and Equipment (Tables)	3 Months Ended
	Mar. 31, 2018
Property, Plant and Equipment [Abstract]
Schedule of property and equipment	Property and equipment is stated at cost and consisted of the following: March 31, December 31, (In thousands) Oil and gas properties: Proved properties $ 1,661,368 $ 1,653,616 Unproved properties 485,281 465,109 Support equipment and facilities 1,437,010 1,427,054 Total oil and gas properties 3,583,659 3,545,779 Accumulated depletion (1,286,413 ) (1,234,806 ) Oil and gas properties, net 2,297,246 2,310,973 Other property 42,781 39,405 Accumulated depreciation (33,490 ) (32,550 ) Other property, net 9,291 6,855 Property and equipment, net $ 2,306,537 $ 2,317,828

Suspended Well Costs (Tables)

Suspended Well Costs (Tables)	3 Months Ended
	Mar. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of capitalized exploratory well costs	The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the three months ended March 31, 2018 . The table excludes $42.7 thousand in costs that were capitalized and subsequently expensed during the same period. March 31, (In thousands) Beginning balance $ 410,113 Additions to capitalized exploratory well costs pending the determination of proved reserves 2,018 Reclassification due to determination of proved reserves — Capitalized exploratory well costs charged to expense — Ending balance $ 412,131
Schedule of aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year	The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: March 31, 2018 December 31, 2017 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 67,666 $ 67,159 Exploratory well costs capitalized for a period of one to two years 292,113 291,252 Exploratory well costs capitalized for a period of three to six years 52,352 51,702 Ending balance $ 412,131 $ 410,113 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 5 5

Equity Method Investments (Tabl

Equity Method Investments (Tables)	3 Months Ended
	Mar. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Summary of financial information of KTIPI	Below is a summary of financial information for KTIPI presented on a 100% basis. March 31, December 31, 2018 2017 (In thousands) Assets Total current assets $ 238,567 $ 179,070 Property and equipment, net 338,096 345,611 Other assets 555 567 Total assets $ 577,218 $ 525,248 Liabilities and shareholders' equity Total current liabilities $ 177,807 $ 106,769 Total long term liabilities 552,727 565,591 Shareholders' equity: Total shareholders' equity (153,316 ) (147,112 ) Total liabilities and shareholders' equity $ 577,218 $ 525,248 Three Months Ended March 31, 2018 (In thousands) Revenues and other income: Oil and gas revenue $ 246,354 Other income 287 Total revenues and other income 246,641 Costs and expenses: Oil and gas production 51,700 Depletion and depreciation 54,070 Other expenses, net (79 ) Total costs and expenses 105,691 Income before income taxes 140,950 Income tax expense 49,632 Net income $ 91,318 Kosmos' share of net income $ 45,659 Basis difference amortization(1) 26,963 Equity in earnings - KTIPI $ 18,696 ______________________________________ (1) The basis difference, which is associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortize the basis difference using the unit-of-production method.

Debt (Tables)

Debt (Tables)	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Schedule of debt	March 31, December 31, (In thousands) Outstanding debt principal balances: Facility $ 800,000 $ 800,000 Senior Notes 525,000 525,000 Total 1,325,000 1,325,000 Unamortized deferred financing costs and discounts(1) (59,804 ) (42,203 ) Long-term debt, net $ 1,265,196 $ 1,282,797 __________________________________ (1) Includes $42.3 million and $23.6 million of unamortized deferred financing costs related to the Facility and $17.5 million and $18.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of March 31, 2018 and December 31, 2017 , respectively.
Schedule of estimated repayments of debt	At March 31, 2018 , the estimated repayments of debt during the five fiscal year periods and thereafter are as follows: Payments Due by Year Total 2018(2) 2019 2020 2021 2022 Thereafter (In thousands) Principal debt repayments(1) $ 1,325,000 $ — $ — $ — $ 525,000 $ — $ 800,000 __________________________________ (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on, as of March 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. As of March 31, 2018 , there were no borrowings under the Corporate Revolver. (2) Represents payments for the period April 1, 2018 through December 31, 2018 .
Schedule of interest and other financing costs, net	Interest and other financing costs, net incurred during the periods is comprised of the following: Three Months Ended March 31, 2018 2017 (In thousands) Interest expense $ 24,893 $ 23,181 Amortization—deferred financing costs 2,440 2,551 Loss on extinguishment of debt 4,056 — Capitalized interest (4,820 ) (9,559 ) Deferred interest (1,256 ) 315 Interest income (948 ) (980 ) Other, net 1,329 1,278 Interest and other financing costs, net $ 25,694 $ 16,786

Derivative Financial Instrume29

Derivative Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of oil derivative contracts	The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of March 31, 2018 . Volumes and weighted average prices are net of any offsetting derivative contracts entered into. Weighted Average Dated Brent Price per Bbl Net Deferred Premium Term Type of Contract MBbl Payable/(Receivable) Swap Sold Put Floor Ceiling Call 2018: April — December Swap with puts 1,500 $ — $ 54.32 $ 40.00 $ — $ — $ — July — December Swap with puts 2,000 — 57.96 45.00 — — — April — June Swaps 500 — 57.25 — — — — April — December Three-way collars 2,193 0.74 — 41.57 56.57 65.90 — April — December Four-way collars 2,252 1.06 — 40.00 50.00 61.33 70.00 April — December Sold calls(1) 1,505 — — — — 65.00 — July — December Purchased Calls 1,000 — — — — — 70.00 2019: January — December Three-way collars 9,500 $ (0.06 ) $ — $ 43.16 $ 52.63 $ 65.01 $ — January — December Sold calls(1) 913 — — — — 80.00 — __________________________________ (1) Represents call option contracts sold to counterparties to enhance other derivative positions.
Schedule of interest rate derivative contracts	The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of March 31, 2018 : Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) April 2018 — December 2018 Capped swap 1-month LIBOR $ 200,000 1.23 % 3.00 %
Schedule of derivative instruments by balance sheet location	The following tables disclose the Company’s derivative instruments as of March 31, 2018 and December 31, 2017 and gain/(loss) from derivatives during the three months ended March 31, 2018 and 2017 , respectively: Estimated Fair Value Asset (Liability) Type of Contract Balance Sheet Location March 31, December 31, (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ 2,279 $ 665 Interest rate Derivatives assets—current 1,182 1,017 Commodity(2) Derivatives assets—long-term 1,093 39 Derivative liabilities: Commodity(3) Derivatives liabilities—current (84,015 ) (67,531 ) Commodity(4) Derivatives liabilities—long-term (35,127 ) (30,209 ) Total derivatives not designated as hedging instruments $ (114,588 ) $ (96,019 ) __________________________________ (1) Includes net deferred premiums payable of $0.4 million and net deferred premiums receivable of $0.8 million related to commodity derivative contracts as of March 31, 2018 and December 31, 2017 , respectively. (2) Includes net deferred premiums receivable of $4.0 million and $0.1 million related to commodity derivative contracts as of March 31, 2018 and December 31, 2017 , respectively. (3) Includes net deferred premiums payable of $5.3 million and $5.6 million related to commodity derivative contracts as of March 31, 2018 and December 31, 2017 , respectively. (4) Includes net deferred premiums payable of $3.5 million and $4.8 million related to commodity derivative contracts as of March 31, 2018 and December 31, 2017 , respectively.
Schedule of derivative instruments by location of gain/(loss)	Amount of Gain/(Loss) Three Months Ended March 31, Type of Contract Location of Gain/(Loss) 2018 2017 (In thousands) Derivatives not designated as hedging instruments: Commodity(1) Oil and gas revenue $ (841 ) $ (8 ) Commodity Derivatives, net (38,478 ) 37,857 Interest rate Interest expense 353 328 Total derivatives not designated as hedging instruments $ (38,966 ) $ 38,177 __________________________________ (1) Amounts represent the change in fair value of our provisional oil sales contracts.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 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 March 31, 2018 and December 31, 2017 , for each fair value hierarchy level: Fair Value Measurements Using: Quoted Prices in Active Markets for Significant Other Significant Identical Assets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) March 31, 2018 Assets: Commodity derivatives $ — $ 3,372 $ — $ 3,372 Interest rate derivatives — 1,182 — 1,182 Liabilities: Commodity derivatives — (119,142 ) — (119,142 ) Total $ — $ (114,588 ) $ — $ (114,588 ) December 31, 2017 Assets: Commodity derivatives $ — $ 704 $ — $ 704 Interest rate derivatives — 1,017 — 1,017 Liabilities: Commodity derivatives — (97,740 ) — (97,740 ) Total $ — $ (96,019 ) $ — $ (96,019 )
Schedule of carrying values and fair values of financial instruments that are not carried at fair value	The following table presents the carrying values and fair values at March 31, 2018 and December 31, 2017 : March 31, 2018 December 31, 2017 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 508,630 $ 537,773 $ 507,600 $ 542,472 Facility 800,000 800,000 800,000 800,000 Total $ 1,308,630 $ 1,337,773 $ 1,307,600 $ 1,342,472

Equity-based Compensation (Tabl

Equity-based Compensation (Tables)	3 Months Ended
	Mar. 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 March 31, 2018 : Weighted- Service Vesting Average Restricted Stock Grant-Date Awards Fair Value (In thousands) Outstanding at December 31, 2017 220 $ 8.64 Granted — — Forfeited — — Vested (220 ) 8.64 Outstanding at March 31, 2018 — — The following table reflects the outstanding restricted stock units as of March 31, 2018 : Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Units Fair Value Units Fair Value (In thousands) (In thousands) Outstanding at December 31, 2017 4,183 $ 6.39 8,452 $ 11.26 Granted(1) 1,893 6.99 7,259 12.42 Forfeited (23 ) 6.57 (25 ) 15.71 Vested (1,524 ) 5.88 (6,519 ) 12.99 Outstanding at March 31, 2018 4,529 6.76 9,167 10.94 __________________________________ (1) The restricted stock units with a combination of market and service vesting criteria include 4.9 million shares granted as a result of the 2014 and 2015 awards achieving 200% of their respective market performance conditions.

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of components of income (loss) before income taxes	Income (loss) before income taxes is composed of the following: Three Months Ended March 31, 2018 2017 (In thousands) Bermuda $ (16,071 ) $ (16,181 ) United States 1,633 1,412 Foreign—other (60,136 ) 8,105 Income (loss) before income taxes $ (74,574 ) $ (6,664 )

Net Loss Per Share (Tables)

Net Loss Per Share (Tables)	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Schedule of reconciliation between net income and amounts used to compute basic and diluted EPS	The following table is a reconciliation between net loss and the amounts used to compute basic and diluted net loss per share and the weighted average shares outstanding used to compute basic and diluted net loss per share: Three Months Ended March 31, 2018 2017 Numerator: Net loss $ (50,226 ) $ (28,841 ) Basic income allocable to participating securities(1) — — Basic net loss allocable to common shareholders (50,226 ) (28,841 ) Diluted adjustments to income allocable to participating securities(1) — — Diluted net loss allocable to common shareholders $ (50,226 ) $ (28,841 ) Denominator: Weighted average number of shares outstanding: Basic 395,600 387,312 Restricted stock awards and units(1)(2) — — Diluted 395,600 387,312 Net loss per share: Basic $ (0.13 ) $ (0.07 ) Diluted $ (0.13 ) $ (0.07 ) __________________________________ (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net loss per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net loss per common share calculation in periods we are in a net loss position. (2) We excluded outstanding restricted stock awards and units of 11.3 million and 14.6 million for the three months ended March 31, 2018 and 2017 , respectively, from the computations of diluted net loss per share because the effect would have been anti-dilutive .

Commitments and Contingencies (

Commitments and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of estimated future minimum commitments	Future minimum rental commitments under our leases at March 31, 2018 , are as follows: Payments Due By Year(1) Total 2018(2) 2019 2020 2021 2022 Thereafter (In thousands) Operating leases(3) $ 13,489 $ 4,080 $ 5,251 $ 1,366 $ 419 $ 419 $ 1,954 __________________________________ (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. (2) Represents payments for the period from April 1, 2018 through December 31, 2018 . (3) Primarily relates to corporate office and foreign office leases.

Additional Financial Informat35

Additional Financial Information (Tables)	3 Months Ended
	Mar. 31, 2018
Additional Financial Information
Schedule of accrued liabilities	Accrued liabilities consisted of the following: March 31, December 31, (In thousands) Accrued liabilities: Exploration, development and production $ 99,905 $ 144,717 General and administrative expenses 12,881 31,124 Interest 11,040 20,457 Income taxes 898 17,423 Taxes other than income 1,794 3,270 Derivatives 5,825 825 Deferred financing costs 1,492 — Other 2,425 1,596 $ 136,260 $ 219,412
Schedule of other expenses, net incurred	Other expenses, net incurred during the period is comprised of the following: Three Months Ended March 31, 2018 2017 (In thousands) Gain on insurance settlements $ — $ (461 ) Disputed charges and related costs 3,268 1,230 Other, net 437 (7 ) Other expenses, net $ 3,705 $ 762

Organization (Details)

Organization (Details)	3 Months Ended
	Mar. 31, 2018segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of reportable segments	1

Accounting Policies (Details)

Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016	Aug. 31, 2014
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents	$ 198,841	$ 233,412
Restricted cash - current	35,378	56,380
Restricted cash - long-term	21,509	15,194
Total cash, cash equivalents and restricted cash	255,728	304,986	$ 263,536	$ 273,195
Inventories
Materials and supplies inventory	67,000	63,500
Hydrocarbons inventory	$ 12,700	8,400
Senior Notes | 7.875% senior notes due 2021
Cash, Cash Equivalents and Restricted Cash
Interest rate	7.875%				7.875%
Restricted Cash | Facility interest or the Senior Notes plus the Corporate Revolver interest
Cash, Cash Equivalents and Restricted Cash
Restricted cash - current		24,800
Restricted cash period required as per commercial debt facility to meet interest and commitment fee payments	6 months
Restricted Cash | Petroleum agreements - performance guarantees
Cash, Cash Equivalents and Restricted Cash
Restricted cash - current	$ 35,400	31,600
Restricted cash - long-term	$ 21,500	$ 15,200

Accounting Policies Summary of

Accounting Policies Summary of Oil and Gas Revenue (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers - Ghana	$ 128,037	$ 103,441
Provisional oil sales contracts	(38,966)	38,177
Oil and gas revenue	127,196	103,432
Oil and Gas
Disaggregation of Revenue [Line Items]
Provisional oil sales contracts	$ (841)	$ (9)

Acquisitions and Divestitures (

Acquisitions and Divestitures (Details) km² in Thousands, $ in Millions	1 Months Ended			3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017USD ($)km²block	Oct. 31, 2017km²sub_periodblock	Dec. 31, 2017USD ($)km²
Petroleum Agreement | Blocks 10 and 13
Acquisitions and Divestitures
Participating interests	35.00%
Petroleum Agreement | Blocks EG-21, S and W
Acquisitions and Divestitures
Participating interests			80.00%
Number of blocks | block			3
Area of petroleum exploration			6
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			6
Petroleum Agreement | Blocks CI-526, CI-602, CI-603, CI-707 and CI-708
Acquisitions and Divestitures
Participating interests		45.00%
Number of blocks | block		5
Area of petroleum exploration		17		17
Exploration period		3 years
3D seismic requirements		12
Farm-in agreement | Block EG-24
Acquisitions and Divestitures
Participation interest acquired	40.00%
Sales and purchase agreement | Ceiba Field and Okume Complex Assets | Hess
Acquisitions and Divestitures
Gross acquisition price | $				$ 650
Net cash consideration paid | $		$ 231		$ 231
Assignment Agreement | Blocks EG-21, S and W
Acquisitions and Divestitures
Participating interests			40.00%
BP | Petroleum Agreement | Blocks 10 and 13
Acquisitions and Divestitures
Participating interests	50.00%
BP | Petroleum Agreement | Blocks CI-526, CI-602, CI-603, CI-707 and CI-708
Acquisitions and Divestitures
Participating interests		45.00%
ANP STP | Petroleum Agreement | Blocks 10 and 13
Acquisitions and Divestitures
Carried participating interest percentage	15.00%
Hess | Ceiba Field and Okume Complex Assets
Acquisitions and Divestitures
Paying interest, percentage				85.00%
Revenue interest, percentage				80.75%
Trident | Assignment Agreement | Blocks EG-21, S and W
Acquisitions and Divestitures
Participating interests			40.00%
Participating interest to be assigned			40.00%
GEPetrol | Petroleum Agreement | Blocks EG-21, S and W
Acquisitions and Divestitures
Carried participating interest percentage			20.00%
Percentage converted from carried to participating			20.00%
PETROCI Holding | Petroleum Agreement | Blocks CI-526, CI-602, CI-603, CI-707 and CI-708
Acquisitions and Divestitures
Carried participating interest percentage		10.00%		10.00%
Hess | Sales and purchase agreement | Ceiba Field and Okume Complex Assets
Acquisitions and Divestitures
Ownership percentage	50.00%
Hess | Trident | Sales and purchase agreement | Ceiba Field and Okume Complex Assets
Acquisitions and Divestitures
Ownership percentage	50.00%

Joint Interest Billings (Detail

Joint Interest Billings (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Mar. 31, 2018	Dec. 31, 2017
Joint interest billings
Joint interest billings, net		$ 76,642	$ 134,565
Long-term receivables - joint interest billings		28,001	34,941
TEN Discoveries | GNPC
Joint interest billings
Joint interest billings, net		14,000	15,200
Long-term receivables - joint interest billings		$ 28,000	$ 31,600
TEN Discoveries | GNPC
Joint interest billings
GNPC's paying interest	5.00%

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Oil and gas properties:
Proved properties	$ 1,661,368		$ 1,653,616
Unproved properties	485,281		465,109
Support equipment and facilities	1,437,010		1,427,054
Total oil and gas properties	3,583,659		3,545,779
Accumulated depletion	(1,286,413)		(1,234,806)
Oil and gas properties, net	2,297,246		2,310,973
Other property	42,781		39,405
Accumulated depreciation	(33,490)		(32,550)
Other property, net	9,291		6,855
Property and equipment, net	2,306,537		$ 2,317,828
Depletion expense	$ 51,600	$ 32,500

Suspended Well Costs (Details)

Suspended Well Costs (Details)	3 Months Ended
	Mar. 31, 2018USD ($)	Mar. 31, 2018USD ($)project	Dec. 31, 2017USD ($)project	May 31, 2015project
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized exploratory well costs subsequently expensed in the same period	$ 42,700
Reconciliation of capitalized exploratory well costs on completed wells
Beginning balance	410,113,000
Additions to capitalized exploratory well costs pending the determination of proved reserves	2,018,000
Reclassification due to determination of proved reserves	0
Capitalized exploratory well costs charged to expense	0
Ending balance	412,131,000
Aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year
Exploratory well costs capitalized for a period of one year or less		$ 67,666,000	$ 67,159,000
Exploratory well costs capitalized for a period of one to two years		292,113,000	291,252,000
Exploratory well costs capitalized for a period of three to six years		52,352,000	51,702,000
Ending balance	$ 410,113,000	$ 412,131,000	$ 410,113,000
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | project		5	5
Greater Tortue Discovery
Projects with exploratory well costs capitalized for more than one year
Number of additional appraisal wells drilled | project				2

Equity Method Investments - Nar

Equity Method Investments - Narrative (Details) - USD ($)	Sep. 30, 2017	Oct. 31, 2017	Mar. 31, 2018	Mar. 31, 2017	Feb. 28, 2017
Schedule of Equity Method Investments [Line Items]
Contribution to equity method investment			$ 0	$ 133,894,000
Kosmos BP Senegal Limited
Schedule of Equity Method Investments [Line Items]
Ownership percentage					50.01%
Contribution to equity method investment	$ 133,900,000
Kosmos-Trident International Petroleum Inc.
Schedule of Equity Method Investments [Line Items]
Ownership percentage			50.00%
Impairment of equity method investment			$ 0
Cash dividends from KTIPI			$ 65,000,000
Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Schedule of Equity Method Investments [Line Items]
Participating interests			30.00%
BP Senegal Investments Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | Kosmos BP Senegal Limited
Schedule of Equity Method Investments [Line Items]
Participating interest transferred		30.00%

Equity Method Investments - Sum

Equity Method Investments - Summary of Financial Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Basis presented	100.00%
Costs and expenses:
Equity in earnings - KTIPI	$ 18,696	$ 0
Kosmos-Trident International Petroleum Inc.
Assets
Total current assets	238,567		$ 179,070
Property and equipment, net	338,096		345,611
Other assets	555		567
Total assets	577,218		525,248
Liabilities and shareholders' equity
Total current liabilities	177,807		106,769
Total long term liabilities	552,727		565,591
Shareholders' equity:
Total shareholders' equity	(153,316)		(147,112)
Total liabilities and shareholders' equity	577,218		$ 525,248
Revenues and other income:
Oil and gas revenue	246,354
Other income	287
Total revenues and other income	246,641
Costs and expenses:
Oil and gas production	51,700
Depletion and depreciation	54,070
Other expenses, net	(79)
Total costs and expenses	105,691
Income before income taxes	140,950
Income tax expense	49,632
Net income	91,318
Kosmos' share of net income	45,659
Basis difference amortization	26,963
Equity in earnings - KTIPI	$ 18,696

Debt - Schedule of Instruments

Debt - Schedule of Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Debt
Outstanding debt principal	$ 1,325,000	$ 1,325,000
Unamortized issuance costs and discount	(59,804)	(42,203)
Long-term debt, net	1,265,196	1,282,797
Revolving Credit Facility
Debt
Outstanding debt principal	800,000	800,000
Senior Notes
Debt
Outstanding debt principal	525,000	525,000
Unamortized issuance costs and discount	(17,500)	(18,600)
The Facility | Revolving Credit Facility
Debt
Unamortized issuance costs and discount	$ (42,300)	$ (23,600)

Debt - Facility (Details)

Debt - Facility (Details) - USD ($)	May 07, 2018	Feb. 28, 2018	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Debt Instrument [Line Items]
Loss on extinguishment of debt			$ 4,056,000	$ 0
Net deferred financing costs			1,825,000		$ 2,510,000
The Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Total commitment		$ 1,500,000,000
Additional commitments		500,000,000
Loss on extinguishment of debt		$ 4,100,000
Net deferred financing costs			42,300,000
Availability period of revolving-credit		1 month
Amount outstanding under letters of credit			0
Amount outstanding			800,000,000
Undrawn availability			$ 700,000,000
Subsequent Event | The Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Amount outstanding	$ 725,000,000
Repayment of Facility	$ 75,000,000

Debt - Corporate Revolver (Deta

Debt - Corporate Revolver (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Net deferred financing costs	$ 1,825,000	$ 2,510,000
Corporate Revolver | Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity	400,000,000
Net deferred financing costs	1,800,000
Amount outstanding	$ 0

Debt - Revolving Letter of Cred

Debt - Revolving Letter of Credit Facility (Details) - Revolving Letter of Credit Facility	Mar. 31, 2018USD ($)letter_of_credit
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 73,000,000
Number of letters of credit | letter_of_credit	13
Amount outstanding	$ 72,800,000

Debt - 7.875% Senior Secured No

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

Debt - Maturities (Details)

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

Debt - Interest and other finan

Debt - Interest and other financing costs, net (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Debt Disclosure [Abstract]
Interest expense	$ 24,893	$ 23,181
Amortization—deferred financing costs	2,440	2,551
Loss on extinguishment of debt	4,056	0
Capitalized interest	(4,820)	(9,559)
Deferred interest	(1,256)	315
Interest income	(948)	(980)
Other, net	1,329	1,278
Interest and other financing costs, net	$ 25,694	$ 16,786

Derivative Financial Instrume52

Derivative Financial Instruments - Schedule of oil derivative contracts (Details)	1 Months Ended	3 Months Ended
	Apr. 30, 2018$ / bblMBbls	Mar. 31, 2018$ / bblMBbls
April 2018 — December 2018 | Swap with puts
Derivative Financial Instruments
Volume (mbbls) | MBbls		1,500
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0
Swap (usd per bbl)		54.32
Sold Put (usd per bbl)		40
Floor (usd per bbl)		0
Ceiling (usd per bbl)		0
Call (usd per bbl)		0
April 2018 — December 2018 | Three-way collars
Derivative Financial Instruments
Volume (mbbls) | MBbls		2,193
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0.74
Swap (usd per bbl)		0
Sold Put (usd per bbl)		41.57
Floor (usd per bbl)		56.57
Ceiling (usd per bbl)		65.90
Call (usd per bbl)		0
April 2018 — December 2018 | Four-way collars
Derivative Financial Instruments
Volume (mbbls) | MBbls		2,252
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		1.06
Swap (usd per bbl)		0
Sold Put (usd per bbl)		40
Floor (usd per bbl)		50
Ceiling (usd per bbl)		61.33
Call (usd per bbl)		70
April 2018 — December 2018 | Sold calls
Derivative Financial Instruments
Volume (mbbls) | MBbls		1,505
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0
Swap (usd per bbl)		0
Sold Put (usd per bbl)		0
Floor (usd per bbl)		0
Ceiling (usd per bbl)		65
Call (usd per bbl)		0
Term July 2018 to December 2018 | Swap with puts
Derivative Financial Instruments
Volume (mbbls) | MBbls		2,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0
Swap (usd per bbl)		57.96
Sold Put (usd per bbl)		45
Floor (usd per bbl)		0
Ceiling (usd per bbl)		0
Call (usd per bbl)		0
Term July 2018 to December 2018 | Purchased Calls
Derivative Financial Instruments
Volume (mbbls) | MBbls		1,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0
Swap (usd per bbl)		0
Sold Put (usd per bbl)		0
Floor (usd per bbl)		0
Ceiling (usd per bbl)		0
Call (usd per bbl)		70
Term April 2018 To June 2018 [Member] | Swaps
Derivative Financial Instruments
Volume (mbbls) | MBbls		500
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0
Swap (usd per bbl)		57.25
Sold Put (usd per bbl)		0
Floor (usd per bbl)		0
Ceiling (usd per bbl)		0
Call (usd per bbl)		0
Term January 2019 to December 2019 | Three-way collars
Derivative Financial Instruments
Volume (mbbls) | MBbls		9,500
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		(0.06)
Swap (usd per bbl)		0
Sold Put (usd per bbl)		43.16
Floor (usd per bbl)		52.63
Ceiling (usd per bbl)		65.01
Call (usd per bbl)		0
Term January 2019 to December 2019 | Sold calls
Derivative Financial Instruments
Volume (mbbls) | MBbls		913
Weighted Average Dated Brent Price Per Bbl [Abstract]
Net Deferred Premium Payable/ (Receivable) (usd per bbl)		0
Swap (usd per bbl)		0
Sold Put (usd per bbl)		0
Floor (usd per bbl)		0
Ceiling (usd per bbl)		80
Call (usd per bbl)		0
Subsequent Event | Term January 2019 to December 2019 | Three-way collars
Derivative Financial Instruments
Volume (mbbls) | MBbls	1,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Sold Put (usd per bbl)	50
Floor (usd per bbl)	60
Ceiling (usd per bbl)	75

Derivative Financial Instrume53

Derivative Financial Instruments - Schedule of interest rate derivative contracts (Details) - 1-month LIBOR - Interest Rate Cap Swap - April 2018 — December 2018 $ in Thousands	Mar. 31, 2018USD ($)
Derivative Financial Instruments
Weighted average notional amount	$ 200,000
Weighted average swap	1.23%
Weighted average sold call	3.00%

Derivative Financial Instrume54

Derivative Financial Instruments - Derivatives instrument and gain/loss from derivatives (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivative instruments, Balance Sheet Location
Derivatives assets—current	$ 3,461	$ 1,682
Derivatives assets—long-term	1,093	39
Derivatives liabilities—current	(84,015)	(67,531)
Derivatives liabilities—long-term	(35,127)	(30,209)
Derivatives not designated as hedging instruments:
Derivative instruments, Balance Sheet Location
Total derivatives not designated as hedging instruments	(114,588)	(96,019)
Derivatives not designated as hedging instruments: | Commodity
Derivative instruments, Balance Sheet Location
Derivatives assets—current	2,279	665
Derivatives assets—long-term	1,093	39
Derivatives liabilities—current	(84,015)	(67,531)
Derivatives liabilities—long-term	(35,127)	(30,209)
Net deferred premiums payable related to commodity derivative contracts - current assets	400
Net deferred premiums receivable related to commodity derivative contracts - current assets		800
Net deferred premiums receivable related to commodity derivative contracts - non-current assets	4,000	100
Net deferred premiums payable related to commodity derivative contracts - current liabilities	5,300	5,600
Net deferred premiums payable related to commodity derivative contracts - non-current liabilities	3,500	4,800
Derivatives not designated as hedging instruments: | Interest rate
Derivative instruments, Balance Sheet Location
Derivatives assets—current	$ 1,182	$ 1,017

Derivative Financial Instrume55

Derivative Financial Instruments - Schedule of derivative instruments by location of gain/(loss) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	$ (38,966)	$ 38,177
Commodity | Oil and gas revenue
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	(841)	(8)
Commodity | Derivatives, net
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	(38,478)	37,857
Interest rate | Interest expense
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	$ 353	$ 328

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Carrying Value
Liabilities:
Long-term debt	$ 1,308,630	$ 1,307,600
Fair Value
Liabilities:
Long-term debt	1,337,773	1,342,472
Senior Notes | Carrying Value
Liabilities:
Long-term debt	508,630	507,600
Senior Notes | Fair Value
Liabilities:
Long-term debt	537,773	542,472
Facility | Carrying Value
Liabilities:
Long-term debt	800,000	800,000
Facility | Fair Value
Liabilities:
Long-term debt	800,000	800,000
Recurring basis
Liabilities:
Total fair value, net	(114,588)	(96,019)
Recurring basis | Commodity
Assets:
Derivative asset, fair value	3,372	704
Liabilities:
Derivative liability, fair value	(119,142)	(97,740)
Recurring basis | Interest rate
Assets:
Derivative asset, fair value	1,182	1,017
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Total fair value, net	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate
Assets:
Derivative asset, fair value	0	0
Recurring basis | Significant Other Observable Inputs (Level 2)
Liabilities:
Total fair value, net	(114,588)	(96,019)
Recurring basis | Significant Other Observable Inputs (Level 2) | Commodity
Assets:
Derivative asset, fair value	3,372	704
Liabilities:
Derivative liability, fair value	(119,142)	(97,740)
Recurring basis | Significant Other Observable Inputs (Level 2) | Interest rate
Assets:
Derivative asset, fair value	1,182	1,017
Recurring basis | Significant Unobservable Inputs (Level 3)
Liabilities:
Total fair value, net	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Commodity
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Interest rate
Assets:
Derivative asset, fair value	$ 0	$ 0

Equity-based Compensation - Add

Equity-based Compensation - Additional Information (Details) - LTIP - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recognized	$ 8	$ 9.8
Tax benefit	0.9	3.3
Net tax shortfall related to equity-based compensation	0.2	0.5
Fair value of awards vested	$ 56.6	$ 8.8
Number of shares remaining available for grant	4.6
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	4 years
Restricted Stock Awards and Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense not yet recognized	$ 50.3
Weighted average period over which compensation expense is to be recognized	2 years 4 months 17 days
Market/Service Vesting Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant date fair value of awards granted (in dollars per share)	$ 12.42
Market/Service Vesting Restricted Stock Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant date fair value of awards granted (in dollars per share)	$ 4.83
Expected volatility	44.00%
Risk-free interest rate	0.70%
Market/Service Vesting Restricted Stock Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the awards granted (up to)	200.00%
Grant date fair value of awards granted (in dollars per share)	$ 15.71
Expected volatility	53.00%
Risk-free interest rate	2.20%

Equity-based Compensation - Sch

Equity-based Compensation - Schedule of awards (Details) - LTIP shares in Thousands	3 Months Ended
	Mar. 31, 2018$ / sharesshares
Service Vesting Restricted Stock Awards
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	220
Granted (in shares)	0
Forfeited (in shares)	0
Vested (in shares)	(220)
Outstanding at the end of the period (in shares)	0
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share) | $ / shares	$ 8.64
Granted (in dollars per share) | $ / shares	0
Forfeited (in dollars per share) | $ / shares	0
Vested (in dollars per share) | $ / shares	8.64
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 0
Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	4,183
Granted (in shares)	1,893
Forfeited (in shares)	(23)
Vested (in shares)	(1,524)
Outstanding at the end of the period (in shares)	4,529
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share) | $ / shares	$ 6.39
Granted (in dollars per share) | $ / shares	6.99
Forfeited (in dollars per share) | $ / shares	6.57
Vested (in dollars per share) | $ / shares	5.88
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 6.76
Market/Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)	8,452
Granted (in shares)	7,259
Forfeited (in shares)	(25)
Vested (in shares)	(6,519)
Outstanding at the end of the period (in shares)	9,167
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share) | $ / shares	$ 11.26
Granted (in dollars per share) | $ / shares	12.42
Forfeited (in dollars per share) | $ / shares	15.71
Vested (in dollars per share) | $ / shares	12.99
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 10.94
2014 and 2015 | Market/Service Vesting Restricted Stock Units
Equity-based Compensation
Vesting percentage of the awards granted	200.00%
Outstanding unvested awards activity
Granted (in shares)	4,900

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Taxes
Effective tax rate (as a percent)	33.00%	333.00%
Income (loss) before income taxes	$ (74,574)	$ (6,664)
Uncertain tax positions	0
Bermuda
Income Taxes
Income (loss) before income taxes	(16,071)	(16,181)
United States
Income Taxes
Income (loss) before income taxes	$ 1,633	1,412
Foreign—other
Income Taxes
Effective tax rate (as a percent)	0.00%
Statutory tax rate (as a percent)	0.00%
Income (loss) before income taxes	$ (60,136)	$ 8,105

Net Loss Per Share (Details)

Net Loss Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Numerator:
Net loss	$ (50,226)	$ (28,841)
Basic income allocable to participating securities	0	0
Basic net loss allocable to common shareholders	(50,226)	(28,841)
Diluted adjustments to income allocable to participating securities	0	0
Diluted net loss allocable to common shareholders	$ (50,226)	$ (28,841)
Weighted average number of shares outstanding:
Basic (in shares)	395,600	387,312
Restricted stock awards and units (in shares)	0	0
Diluted (in shares)	395,600	387,312
Net loss per share:
Basic (in dollars per share)	$ (0.13)	$ (0.07)
Diluted (in dollars per share)	$ (0.13)	$ (0.07)
Outstanding restricted stock awards and units excluded from the computations of diluted net income per share (in shares)	11,300	14,600

Commitments and Contingencies61

Commitments and Contingencies (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)km²exploration_well
Future minimum rental commitments
Total	$ 13,489
2,018	4,080
2,019	5,251
2,020	1,366
2,021	419
2,022	419
Thereafter	$ 1,954
Cote d'Ivoire
Commitments and contingencies
3D seismic requirements | km²	12,000
Equatorial Guinea
Commitments and contingencies
3D seismic requirements | km²	9,000
Mauritania
Commitments and contingencies
Number of exploration wells | exploration_well	1
3D seismic requirements | km²	7,600
Sao Tome and Principe
Commitments and contingencies
3D seismic requirements | km²	13,500

Additional Financial Informat62

Additional Financial Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Accrued liabilities:
Exploration, development and production	$ 99,905,000		$ 144,717,000
General and administrative expenses	12,881,000		31,124,000
Interest	11,040,000		20,457,000
Income taxes	898,000		17,423,000
Taxes other than income	1,794,000		3,270,000
Derivatives	5,825,000		825,000
Deferred financing costs	1,492,000		0
Other	2,425,000		1,596,000
Accrued liabilities	136,260,000		$ 219,412,000
Other income, net	0	$ 48,500,000
Other Expenses, Net
Gain on insurance settlements	0	(461,000)
Disputed charges and related costs	3,268,000	1,230,000
Other, net	437,000	(7,000)
Other expenses, net	3,705,000	762,000
Oil and gas production expense
Accrued liabilities:
Insurance recoveries	$ 0	$ 3,400,000