Kosmos Energy (KOS) 10-Q 7 Aug 17 2017 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2017	Aug. 01, 2017
Document and Entity Information
Entity Registrant Name	Kosmos Energy Ltd.
Entity Central Index Key	1,509,991
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
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		389,286,890
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q2

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 162,474	$ 194,057
Restricted cash	40,776	24,506
Receivables:
Joint interest billings, net current	56,606	63,249
Oil sales	43,152	54,195
Related party	26,208
Other	59,856	25,893
Inventories	79,871	74,380
Prepaid expenses and other	7,491	7,209
Derivatives	37,041	31,698
Total current assets	513,475	475,187
Property and equipment:
Oil and gas properties, net	2,290,338	2,700,889
Other property, net	7,087	8,003
Property and equipment, net	2,297,425	2,708,892
Other assets:
Equity method investment	127,467
Restricted cash	28,295	54,632
Long-term receivables - joint interest billings. noncurrent	45,671	45,663
Deferred financing costs, net of accumulated amortization of $12,582 and $11,213 at June 30, 2017 and December 31, 2016, respectively	3,879	5,248
Long-term deferred tax assets	32,427	37,827
Derivatives	10,427	3,808
Other	17,293	10,208
Total assets	3,076,359	3,341,465
Current liabilities:
Accounts payable	89,147	220,627
Accrued liabilities	190,261	129,706
Derivatives	2,932	19,692
Total current liabilities	282,340	370,025
Long-term liabilities:
Long-term debt, net	1,127,503	1,321,874
Derivatives	3,318	14,123
Asset retirement obligations	66,935	63,574
Deferred tax liabilities	517,970	482,221
Other long-term liabilities	15,440	8,449
Total long-term liabilities	1,731,166	1,890,241
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at June 30, 2017 and December 31, 2016
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 398,348,929 and 395,859,061 issued at June 30, 2017 and December 31, 2016, respectively	3,983	3,959
Additional paid-in capital	1,994,785	1,975,247
Accumulated deficit	(887,718)	(850,410)
Treasury stock, at cost, 9,188,819 and 9,101,395 shares at June 30, 2017 and December 31, 2016, respectively	(48,197)	(47,597)
Total shareholders’ equity	1,062,853	1,081,199
Total liabilities and shareholders’ equity	$ 3,076,359	$ 3,341,465

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
CONSOLIDATED BALANCE SHEETS
Deferred financing costs, accumulated amortization (in dollars)	$ 12,582	$ 11,213
Preference shares, par value (in dollars per share)	$ 0.01	$ 0.01
Preference shares, authorized shares	200,000,000	200,000,000
Preference shares, issued shares	0	0
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, authorized shares	2,000,000,000	2,000,000,000
Common shares, issued shares	398,348,929	395,859,061
Treasury stock shares	9,188,819	9,101,395

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Revenues and other income:
Oil and gas revenue	$ 136,363	$ 45,506	$ 239,795	$ 107,631
Other income, net	10,161	170	58,695	178
Total revenues and other income	146,524	45,676	298,490	107,809
Costs and expenses:
Oil and gas production	21,604	32,681	41,490	62,073
Facilities insurance modifications, net	(2)		2,572
Exploration expenses	19,982	36,402	125,696	60,260
General and administrative	14,739	19,838	30,526	37,758
Depletion and depreciation	72,441	16,927	107,419	48,193
Interest and other financing costs, net	19,465	8,878	36,251	19,202
Derivatives, net	(25,411)	54,988	(63,268)	50,643
Other expenses, net	8,434	(170)	9,196	14,563
Total costs and expenses	131,252	169,544	289,882	292,692
Income (loss) before income taxes	15,272	(123,868)	8,608	(184,883)
Income tax expense (benefit)	23,739	(15,544)	45,916	(17,566)
Net loss	$ (8,467)	$ (108,324)	$ (37,308)	$ (167,317)
Net loss per share:
Basic (in dollars per share)	$ (0.02)	$ (0.28)	$ (0.10)	$ (0.43)
Diluted (in dollars per share)	$ (0.02)	$ (0.28)	$ (0.10)	$ (0.43)
Weighted average number of shares used to compute net loss per share:
Basic (in shares)	387,952	384,918	387,634	384,676
Diluted (in shares)	387,952	384,918	387,634	384,676

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - 6 months ended Jun. 30, 2017 - USD ($) shares in Thousands, $ in Thousands	Common Shares	Additional Paid-in Capital	Accumulated Deficit	Treasury Stock	Total
Balance at Dec. 31, 2016	$ 3,959	$ 1,975,247	$ (850,410)	$ (47,597)	$ 1,081,199
Balance (in shares) at Dec. 31, 2016	395,859
Increase (Decrease) in Shareholders' Equity
Equity-based compensation		20,907			20,907
Restricted stock awards and units	$ 24	(24)
Restricted stock awards and units (in shares)	2,490
Purchase of treasury stock		(1,345)		(600)	(1,945)
Net loss			(37,308)		(37,308)
Balance at Jun. 30, 2017	$ 3,983	$ 1,994,785	$ (887,718)	$ (48,197)	$ 1,062,853
Balance (in shares) at Jun. 30, 2017	398,349

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Operating Activities
Net loss	$ (37,308)	$ (167,317)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and amortization	112,521	53,295
Deferred income taxes	41,017	(19,929)
Unsuccessful well costs	3,605	2,300
Change in fair value of derivatives	(58,944)	55,175
Cash settlements on derivatives, net (including $24.3 million and $101.8 million on commodity hedges during 2017 and 2016	19,417	99,815
Equity-based compensation	20,329	21,162
Loss on equity method investment	6,426
Other	2,514	15,069
Changes in assets and liabilities:
Increase in receivables	(28,251)	(11,225)
Increase in inventories	(6,038)	(1,082)
(Increase) decrease in prepaid expenses and other	(17,459)	18,985
Decrease in accounts payable	(131,480)	(80,359)
Increase (decrease) in accrued liabilities	56,137	(9,967)
Net cash used in operating activities	(17,514)	(24,078)
Investing activities
Oil and gas assets	(42,805)	(417,704)
Other property	(1,454)	(601)
Proceeds on sale of assets	222,068	196
Net cash provided by (used in) investing activities	177,809	(418,109)
Financing activities
Borrowings under long-term debt		325,000
Payments on long-term debt	(200,000)
Purchase of treasury stock	(1,945)	(1,798)
Net cash provided by (used in) financing activities	(201,945)	323,202
Net decrease in cash, cash equivalents and restricted cash	(41,650)	(118,985)
Cash, cash equivalents and restricted cash at beginning of period	273,195	310,862
Cash, cash equivalents and restricted cash at end of period	231,545	191,877
Cash, cash equivalents and restricted cash at end of period	231,545	191,877
Cash paid for:
Interest	24,944	8,200
Income taxes	27,199	6,978
Non-cash activity:
Conversion of joint interest billings receivable to long-term note receivable		$ 5,033
Contribution to equity method investment	$ 133,893

CONSOLIDATED STATEMENTS OF CAS7

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash settlements on derivatives, net (including $24.3 million and $101.8 million on commodity hedges during 2017 and 2016	$ 24.3	$ 101.8

Organization

Organization	6 Months Ended
	Jun. 30, 2017
Organization
Organization	1. Organization Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise. Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margins. Our assets include existing production and development projects offshore Ghana, large discoveries and significant further hydrocarbon exploration potential offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Sao Tome and Principe, Suriname, Morocco and Western Sahara. Kosmos is listed on the New York 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 currently related to production located offshore Ghana.

Accounting Policies

Accounting Policies	6 Months Ended
	Jun. 30, 2017
Accounting Policies
Accounting Policies	2. Accounting Policies General The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of June 30, 2017, the changes in the consolidated statements of shareholders’ equity for the six months ended June 30, 2017, the consolidated results of operations for the three and six months ended June 30, 2017 and 2016, and the consolidated cash flows for the six months ended June 30, 2017 and 2016. 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, 2016, included in our annual report on Form 10-K. Investment in Corporate Joint Venture Kosmos holds a 50.01% interest in Kosmos BP Senegal Limited (“KBSL”), which we exercise significant influence over. Our investment in KBSL is accounted for under the equity method of accounting. In applying the equity method of accounting, our investment in KBSL was initially recorded at carryover basis and subsequently adjusted for the Company’s proportionate share of earnings, losses and distributions. During the three and six month periods ended June 30, 2017 we recognized $6.4 million related to our share of losses in KBSL. As of June 30, 2017, our investment in KBSL was $127.5 million and is reported as an equity method investment in our consolidated balance sheets. We had related party receivables of $26.2 million as of June 30, 2017, which relate to amounts due from KBSL for costs incurred by Kosmos on behalf of KBSL. Reclassifications Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows. Cash, Cash Equivalents and Restricted Cash June 30, December 31, 2017 2016 (In thousands) Cash and cash equivalents $ 162,474 $ 194,057 Restricted cash - current 40,776 24,506 Restricted cash - long-term 28,295 54,632 Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ 231,545 $ 273,195 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 our commercial debt facility (the “Facility”), we are 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 June 30, 2017 and December 31, 2016, we had $24.6 million and $24.5 million, respectively, in current restricted cash to meet this requirement. In addition, in accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of June 30, 2017 and December 31, 2016, we had $16.2 million and zero, respectively, of current restricted cash and $28.3 million and $54.6 million, respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts. Inventories Inventories consisted of $74.0 million and $68.1 million of materials and supplies and $5.9 million and $6.3 million of hydrocarbons as of June 30, 2017 and December 31, 2016, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded write downs of $0.5 million and $15.2 million during the six months ended June 30, 2017 and 2016, respectively, for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.

Acquisitions and Divestitures

Acquisitions and Divestitures	6 Months Ended
	Jun. 30, 2017
Acquisitions and Divestitures
Acquisitions and Divestitures	3. Acquisitions and Divestitures In December 2016, we announced transactions with affiliates of BP p.l.c. (‘‘BP’’) in Mauritania and Senegal following a competitive farm-out process for our interests in our blocks offshore Mauritania and Senegal. The Mauritania and Senegal transactions closed in January 2017 and February 2017, respectively. In Mauritania, BP acquired a 62% participating interest in our four Mauritania licenses (C6, C8, C12 and C13). In Senegal, BP acquired a 49.99% interest in KBSL, our majority owned affiliate company which holds a 60% participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks offshore Senegal. Previously we indicated that KBSL would hold a 65% participating interest upon the completion of our exercise in December 2016 of an option to increase our equity in each contract area by 5% in exchange for carrying Timis Corporation Limited’s (“Timis”) paying interest share of a third well in either contract area, subject to a maximum gross well cost of $120.0 million. However, we have agreed to withdraw the exercise of this call option upon completion of an agreement between BP and Timis by which BP acquired Timis’ entire 30% participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks. The transaction between BP and Timis has now been completed and KBSL’s participating interest in these blocks remains at 60%. In consideration for these transactions, Kosmos received $162 million in cash up front during the first quarter of 2017 and will receive a $221 million exploration and appraisal carry, up to $533 million in a development carry and variable consideration up to $2 per barrel for up to 1 billion barrels of liquids, structured as a production royalty, subject to future liquids discoveries and prevailing oil prices. The effective date of these transactions was July 1, 2016, with BP paying interim costs from the effective date to the closing dates. We reduced our unproved property balance by $221.9 million for the consideration received as a result of these transactions including the upfront cash and interim costs from the transaction date to the effective date. In November 2015, we entered into a line of credit agreement with Timis, whereby Timis had the right to draw up to $30.0 million on the line of credit to offset its joint interest billings arising from costs under the Senegal petroleum agreements. As of June 30, 2017, there was $16 million outstanding under the agreement, which is included in other receivables. We agreed with Timis to terminate this line of credit agreement when Timis’ transaction with BP for the transfer of Timis’ 30% participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks offshore Senegal was completed. As a result of termination of this credit agreement, Kosmos expects to receive this $16 million in early August. In June 2017, we entered into a farm-in agreement with Tullow Mauritania Limited, a subsidiary of Tullow Oil plc (“Tullow”), to acquire a 15% non-operated participating interest in Block C18 offshore Mauritania. Based on the terms of the agreement, we will reimburse a portion of past and interim period costs and partially carry Tullow’s share of a planned 3D seismic program (up to $2.1 million net to Kosmos). We will also pay Tullow $2.5 million by the end of the initial phase of the exploration period for additional carry of seismic and other joint account costs. Certain governmental approvals are still required to be completed before this agreement is effective.

Joint Interest Billings

Joint Interest Billings	6 Months Ended
	Jun. 30, 2017
Joint Interest Billings
Joint Interest Billings	4. 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 under the terms of the Deepwater Tano (“DT”) petroleum contract. As of June 30, 2017 and December 31, 2016, the joint interest billing receivables due from GNPC for the TEN development costs were $1.6 million and zero, respectively, which are classified as current and $45.7 million and $44.0 million, respectively, which are classified as long-term on the consolidated balance sheets.

Property and Equipment

Property and Equipment	6 Months Ended
	Jun. 30, 2017
Property and Equipment
Property and Equipment	5. Property and Equipment Property and equipment is stated at cost and consisted of the following: June 30, December 31, 2017 2016 (In thousands) Oil and gas properties: Proved properties $ 1,373,694 $ 1,385,331 Unproved properties 624,615 919,056 Support equipment and facilities 1,384,349 1,386,448 Total oil and gas properties 3,382,658 3,690,835 Accumulated depletion (1,092,320) (989,946) Oil and gas properties, net 2,290,338 2,700,889 Other property 37,952 37,186 Accumulated depreciation (30,865) (29,183) Other property, net 7,087 8,003 Property and equipment, net $ 2,297,425 $ 2,708,892 We recorded depletion expense of $69.9 million and $14.9 million for the three months ended June 30, 2017 and 2016, respectively, and $102.4 and $44.1 million for the six months ended June 30, 2017 and 2016, respectively.

Suspended Well Costs

Suspended Well Costs	6 Months Ended
	Jun. 30, 2017
Suspended Well Costs
Suspended Well Costs	6. Suspended Well Costs The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the six months ended June 30, 2017. The table excludes $3.6 million in costs that were capitalized and subsequently expensed during the same period. June 30, 2017 (In thousands) Beginning balance $ 734,463 Additions to capitalized exploratory well costs pending the determination of proved reserves 30,663 Reclassification due to determination of proved reserves — Divestitures(1) (206,400) Contribution of oil and gas property to equity method investment (131,764) Capitalized exploratory well costs charged to expense — Ending balance $ 426,962 (1) Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal transactions with BP. The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: June 30, 2017 December 31, 2016 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 29,663 $ 279,809 Exploratory well costs capitalized for a period of one to two years 183,623 244,804 Exploratory well costs capitalized for a period of three to eight years 213,676 209,850 Ending balance $ 426,962 $ 734,463 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 6 5 As of June 30, 2017, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Mahogany, Teak (formerly Teak-1 and Teak-2) and Akasa discoveries 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. Mahogany and Teak Discoveries — In November 2015, we signed the Jubilee Field Unit Expansion Agreement with our partners to allow for the development of the Mahogany and Teak discoveries through the Jubilee FPSO and infrastructure. The expansion of the Jubilee Unit becomes effective upon approval by Ghana’s Ministry of Petroleum of the Greater Jubilee Full Field Development Plan (“GJFFDP”). The initial plan was submitted to the government of Ghana in December 2015. The GJFFDP encompasses future development of the Jubilee Field, in addition to future development of the Mahogany and Teak discoveries, which were declared commercial during 2015. The partners remain on track to resubmit the GJFFDP, which was optimized given the current oil price environment to reduce overall capital costs, to the government of Ghana with approval expected later in the year. Upon approval of the GJFFDP by the Ministry of Energy, the Jubilee Unit will be expanded to include the Mahogany and Teak discoveries and revenues and expenses associated with these discoveries will be at the Jubilee Unit interests. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow after approval of the GJFFDP by Ghana’s Ministry of Energy. 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. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block, including the Akasa Discovery, to Tullow after approval of the GJFFDP by Ghana’s Ministry of Energy. Wawa Discovery — In February 2016, we requested the Ghana Ministry of Energy to approve the enlargement of the areal extent of the TEN fields and production area to capture the resource accumulation located in the Wawa Discovery Area for a potential future integrated development with the TEN fields. In April 2016, the Ghana Ministry of Energy approved our request to enlarge the TEN development and production area subject to continued subsurface and development concept evaluation, along with the requirement to integrate the Wawa Discovery into the TEN PoD. We are currently in discussions with the Ministry of Energy with respect to conducting further subsurface and development concept evaluation. Greater Tortue Discovery — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania which encountered hydrocarbon pay. Two additional wells have been drilled in the Greater Tortue Discovery area, Ahmeyim-2 in Mauritania and Guembeul-1 in Senegal. We are currently performing a drill stem test on the Tortue‑1 well to confirm the production capabilities of the Greater Tortue Discovery to further refine the Front End Engineering Design (FEED) in the second half of 2017. 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.

Debt

Debt	6 Months Ended
	Jun. 30, 2017
Debt
Debt	7. Debt June 30, December 31, 2017 2016 (In thousands) Outstanding debt principal balances: Facility $ 650,000 $ 850,000 Senior Notes 525,000 525,000 Total 1,175,000 1,375,000 Unamortized deferred financing costs and discounts(1) (47,497) (53,126) Long-term debt, net $ 1,127,503 $ 1,321,874 (1) Includes $26.8 million and $30.3 million of unamortized deferred financing costs related to the Facility and $20.7 million and $22.8 million of unamortized deferred financing costs and discounts related to the Senior Notes as of June 30, 2017 and December 31, 2016, respectively. Facility In March 2014, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. In March 2017, following the lender’s semi-annual redetermination, the borrowing base under our Facility was $1.3 billion (effective April 1, 2017). The borrowing base calculation includes value related to the Jubilee and TEN fields. As of June 30, 2017, borrowings under the Facility totaled $650.0 million and the undrawn availability under the Facility was $650.8 million. The Facility provides a revolving-credit and letter of credit facility. The availability period for the revolving-credit facility, as amended in March 2014, expires on March 31, 2018, however, the Facility has a revolving-credit sublimit, which will be the lesser of $500.0 million and the total available facility at that time, that will be available for drawing until the date falling 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, 2018, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2021. As of June 30, 2017, 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, 2017 (the most recent assessment date). The Facility contains customary cross default provisions. Corporate Revolver In June 2015, we amended and restated the Corporate Revolver from a number of financial institutions, increasing the borrowing capacity to $400.0 million, extending the maturity date to November 2018 and lowering the commitment fees on the undrawn portion of the total commitments to 30% per annum of the respective margin. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of June 30, 2017, we have $3.9 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term. These deferred financing costs are included in the Other assets section of the consolidated balance sheets. As of June 30, 2017, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400.0 million. We were in compliance with the financial covenants contained in the Corporate Revolver as of March 31, 2017 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions. Revolving Letter of Credit Facility In July 2016, we amended and restated the revolving letter of credit facility agreement (“LC Facility”), extending the maturity date to July 2019. During the first quarter of 2017, the LC Facility size was increased to $115.0 million. In April 2017, we reduced the size of our LC Facility to $70 million. As of June 30, 2017, there were seven outstanding letters of credit totaling $57.7 million under the LC Facility. The LC Facility contains customary cross default provisions. 7.875% Senior Secured Notes due 2021 During August 2014, the Company issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. During April 2015, we issued an additional $225.0 million of Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million of Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued. The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries. At June 30, 2017, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows: Payments Due by Year Total 2017(2) 2018 2019 2020 2021 Thereafter (In thousands) Principal debt repayments(1) $ 1,175,000 $ — $ — $ 50,377 $ 404,971 $ 719,652 $ — (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on, as of June 30, 2017, our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of June 30, 2017, there were no borrowings under the Corporate Revolver. (2) Represents payments for the period July 1, 2017 through December 31, 2017. Interest and other financing costs, net Interest and other financing costs, net incurred during the periods is comprised of the following: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (In thousands) Interest expense $ 22,792 $ 21,824 $ 45,973 $ 42,772 Amortization—deferred financing costs 2,551 2,551 5,102 5,102 Capitalized interest (7,376) (17,584) (16,935) (34,030) Deferred interest 634 149 949 (258) Interest income (760) (466) (1,740) (834) Other, net 1,624 2,404 2,902 6,450 Interest and other financing costs, net $ 19,465 $ 8,878 $ 36,251 $ 19,202

Derivative Financial Instrument

Derivative Financial Instruments	6 Months Ended
	Jun. 30, 2017
Derivative Instruments and Hedging Activities
Derivative Financial Instruments	8. Derivative Financial Instruments We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes. We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820 — Fair Value Measurements and Disclosures. Oil Derivative Contracts The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of June 30, 2017. Volumes and weighted average prices are net of any offsetting derivative contracts entered into. Weighted Average Dated Brent Price per Bbl Deferred Premium Term Type of Contract MBbl Payable, Net Swap Sold Put Floor Ceiling Call 2017: July — December Swap with puts/calls 1,006 $ 2.13 $ 72.50 $ 55.00 $ — $ — $ 90.00 July — December Swap with puts 1,006 — 64.95 50.00 — — — July — December Three-way collars 2,012 1.72 — 30.00 45.00 60.00 — July — December Sold calls(1) 1,000 — — — — 85.00 — 2018: January — December Three-way collars 2,913 $ 0.74 $ — $ 41.57 $ 56.57 $ 65.90 $ — January — December Four-way collars 3,000 1.06 — 40.00 50.00 61.33 70.00 January — December Sold calls(1) 2,000 — — — — 65.00 — 2019: January — December Sold calls(1) 913 $ — $ — $ — $ — $ 80.00 $ — (1) Represents call option contracts sold to counterparties to enhance other derivative positions. In July 2017, we entered into three-way collar contracts for 3.0 MMBbl from January 2019 through December 2019 with a weighted average floor price of $50.00 per barrel, a weighted average ceiling price of $61.67 per barrel and a weighted average sold put price of $40.00 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 June 30, 2017: Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) July 2017 — December 2018 Capped swap 1-month LIBOR $ 200,000 1.23 % 3.00 % The following tables disclose the Company’s derivative instruments as of June 30, 2017 and December 31, 2016 and gain/(loss) from derivatives during the three and six months ended June 30, 2017 and 2016, respectively: Estimated Fair Value Asset (Liability) June 30, December 31, Type of Contract Balance Sheet Location 2017 2016 (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ 36,825 $ 31,698 Interest rate Derivatives assets—current 216 — Commodity(2) Derivatives assets—long-term 10,015 3,226 Interest rate Derivatives assets—long-term 412 582 Derivative liabilities: Commodity(3) Derivatives liabilities—current (2,932) (19,163) Interest rate Derivatives liabilities—current — (529) Commodity(4) Derivatives liabilities—long-term (3,318) (14,123) Total derivatives not designated as hedging instruments $ 41,218 $ 1,691 (1) Includes net deferred premiums payable of $4.7 million and $3.9 million related to commodity derivative contracts as of June 30, 2017 and December 31, 2016, respectively. (2) Includes net deferred premiums payable of $3.5 million and $2.5 million related to commodity derivative contracts as of June 30, 2017 and December 31, 2016, respectively. (3) Includes zero and $30.9 thousand as of June 30, 2017 and December 31, 2016, respectively, which represents our provisional oil sales contract. Also includes net deferred premiums payable of $3.1 million and $6.2 million related to commodity derivative contracts as of June 30, 2017 and December 31, 2016, respectively. (4) Includes net deferred premiums receivable of $0.5 million and net deferred premiums payable of $0.6 million related to commodity derivative contracts as of June 30, 2017 and December 31, 2016, respectively. Amount of Gain/(Loss) Amount of Gain/(Loss) Three Months Ended Six Months Ended June 30, June 30, Type of Contract Location of Gain/(Loss) 2017 2016 2017 2016 (In thousands) Derivatives not designated as hedging instruments: Commodity(1) Oil and gas revenue $ (4,552) $ (1,665) $ (4,560) $ (1,055) Commodity Derivatives, net 25,411 (54,988) 63,268 (50,643) Interest rate Interest expense (92) (898) 236 (3,476) Total derivatives not designated as hedging instruments $ 20,767 $ (57,551) $ 58,944 $ (55,174) (1) Amounts represent the change in fair value of our provisional oil sales contracts. Offsetting of Derivative Assets and Derivative Liabilities Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of June 30, 2017 and December 31, 2016, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2017
Fair Value Measurements
Fair Value Measurements	9. Fair Value Measurements In accordance with ASC Topic 820 — Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy: · Level 1 — quoted prices for identical assets or liabilities in active markets. · Level 2 — quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means. · Level 3 — unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2017 and December 31, 2016, for each fair value hierarchy level: Fair Value Measurements Using: Quoted Prices in Active Markets for Significant Other Significant Identical Assets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) June 30, 2017 Assets: Commodity derivatives $ — $ 46,840 $ — $ 46,840 Interest rate derivatives — 628 — 628 Liabilities: Commodity derivatives — (6,250) — (6,250) Interest rate derivatives — — — — Total $ — $ 41,218 $ — $ 41,218 December 31, 2016 Assets: Commodity derivatives $ — $ 34,924 $ — $ 34,924 Interest rate derivatives — 582 — 582 Liabilities: Commodity derivatives — (33,286) — (33,286) Interest rate derivatives — (529) — (529) Total $ — $ 1,691 $ — $ 1,691 The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs. Commodity Derivatives Our commodity derivatives represent crude oil four-way collars, three-way 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 8 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments. Provisional Oil Sales The value attributable to the provisional oil sales derivative is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for Dated Brent over the term of the pricing period designated in the sales contract and the spot price on the lifting date. Interest Rate Derivatives We enter into interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate. We also enter into capped interest rate swaps, whereby the Company pays a fixed rate of interest if LIBOR is below the cap, and pays the market rate less the spread between the cap and the fixed rate of interest if LIBOR is above the cap. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) LIBOR yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market. Debt The following table presents the carrying values and fair values at June 30, 2017 and December 31, 2016: June 30, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 505,612 $ 536,356 $ $ Facility 650,000 650,000 Total $ 1,155,612 $ 1,186,356 $ 1,353,716 $ 1,378,938 The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.

Equity-based Compensation

Equity-based Compensation	6 Months Ended
	Jun. 30, 2017
Equity-based Compensation
Equity-based Compensation	10. 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 $10.5 million and $10.5 million during the three months ended June 30, 2017 and 2016, respectively, and $20.3 million and $21.2 million during the six months ended June 30, 2017 and 2016, respectively. The total tax benefit for the three months ended June 30, 2017 and 2016 was $3.5 million and $3.3 million, respectively, and $6.8 million and $6.9 million during the six months ended June 30, 2017 and 2016, respectively. Additionally, we recorded a net tax shortfall related to equity-based compensation of $3.0 million and $3.1 million for the three months ended June 30, 2017 and 2016, respectively, and $2.8 million and $4.3 million during the six months ended June 30, 2017 and 2016, respectively. The fair value of awards vested during the three months ended June 30, 2017 and 2016 was approximately $10.5 million and $7.7 million, respectively, and $19.3 million and $11.2 million during the six months ended June 30, 2017 and 2016, respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service vesting criteria under the LTIP. Substantially all these awards vest over three or four year periods. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock. The following table reflects the outstanding restricted stock awards as of June 30, 2017: Weighted- Service Vesting Average Restricted Stock Grant-Date Awards Fair Value (In thousands) Outstanding at December 31, 2016 488 $ 8.83 Granted — — Forfeited — — Vested (268) 8.97 Outstanding at June 30, 2017 220 8.64 The following table reflects the outstanding restricted stock units as of June 30, 2017: 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, 2016 4,160 $ 6.91 7,194 $ 12.29 Granted 1,898 6.40 2,153 9.50 Forfeited (64) 7.60 (20) 11.53 Vested (1,735) 7.48 (823) 15.44 Outstanding at June 30, 2017 4,259 6.44 8,504 11.28 As of June 30, 2017, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $42.7 million over a weighted average period of 1.58 years. At June 30, 2017, the Company had approximately 3.2 million shares that remain available for issuance under the LTIP. For restricted stock awards and restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 100% of the awards granted for restricted stock awards and up to 200% of the awards granted for restricted stock units. The grant date fair value was $9.45 per award for restricted stock awards and ranged from $4.83 to $15.81 per award for restricted stock units. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and was 55.0% for the restricted stock awards and ranged from 44.0% to 54.0% for restricted stock units. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and was 0.5% for restricted stock awards and ranged from 0.5% to 1.4% for restricted stock units.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2017
Income Taxes
Income Taxes	11. 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. Income tax expense (benefit) was $23.7 million and $(15.5) million for the three months ended June 30, 2017 and 2016, respectively, and $45.9 million and $(17.6) million for the six months ended June 30, 2017 and 2016, respectively. The income tax provision consists of United States and Ghanaian income and Texas margin taxes. Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets. Income (loss) before income taxes is composed of the following: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (In thousands) Bermuda $ (16,759) $ (15,427) $ (32,940) $ (31,223) United States 1,382 2,219 2,794 4,315 Foreign—other 30,649 (110,660) 38,754 (157,975) Income (loss) before income taxes $ 15,272 $ (123,868) $ 8,608 $ (184,883) Our effective tax rate for the three months ended June 30, 2017 and 2016 is 155% and 13%, respectively. For the six months ended, June 30, 2017 and 2016, our effective tax rate was 533% and 10%, respectively. The effective tax rate is impacted by the effect of equity-based compensation tax shortfalls and windfalls equal to the difference between the income tax benefit recognized for financial statement purposes and the income tax benefit realized for tax return purposes and by non-deductible expenditures associated with the damage to the turret bearing, which we expect to recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax. 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 2016 and in the United States, to federal income tax examinations for tax years 2013 through 2016. As of June 30, 2017, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense.

Net Income (Loss) Per Share

Net Income (Loss) Per Share	6 Months Ended
	Jun. 30, 2017
Net income (loss) per share
Net Income (Loss) Per Share	12. Net Income (Loss) Per Share The following table is a reconciliation between net income and the amounts used to compute basic and diluted net income per share and the weighted average shares outstanding used to compute basic and diluted net income (loss) per share: Three Months Ended Six Months Ended June 30, June 30, 2017 2016 2017 2016 Numerator: Net loss $ (8,467) $ (108,324) $ (37,308) $ (167,317) Basic income allocable to participating securities(1) — — — — Basic net loss allocable to common shareholders (8,467) (108,324) (37,308) (167,317) Diluted adjustments to income allocable to participating securities(1) — — — — Diluted net loss allocable to common shareholders $ (8,467) $ (108,324) $ (37,308) $ (167,317) Denominator: Weighted average number of shares outstanding: Basic 387,952 384,918 387,634 384,676 Restricted stock awards and units(1)(2) — — — — Diluted 387,952 384,918 387,634 384,676 Net loss per share: Basic $ (0.02) $ (0.28) $ (0.10) $ (0.43) Diluted $ (0.02) $ (0.28) $ (0.10) $ (0.43) (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income (loss) per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net income (loss) per common share calculation in periods we are in a net loss position. (2) We excluded outstanding restricted stock awards and units of 13.0 million and 12.3 million for the three and six months ended June 30, 2017 and 2016, respectively, from the computations of diluted net income per share because the effect would have been anti-dilutive .

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2017
Commitments and Contingencies
Commitments and Contingencies	13. 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 two exploration wells in Mauritania. In Mauritania, our partner is obligated to fund our share of the cost of the exploration wells, subject to their maximum $221 million cumulative exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Sao Tome and Principe and Western Sahara, we have 3D seismic requirements of 4,750 square kilometers and 5,000 square kilometers, respectively. Additionally, in Morocco certain geological studies are also required. In January 2017, Kosmos Energy Ventures (“KEV”), a subsidiary of Kosmos Energy Ltd., elected to cancel the fourth year option of the Atwood Achiever drilling rig contract and revert to the original day rate of approximately $0.6 million per day and original agreement end date in November 2017. During the first quarter of 2017, KEV made a rate recovery payment of $48.1 million representing the difference between the original day rate and the amended day rate multiplied by the number of days from the amendment effective date to the date the election was exercised plus certain administrative costs. Future minimum rental commitments under our leases at June 30, 2017, are as follows: Payments Due By Year(1) Total 2017(2) 2018 2019 2020 2021 Thereafter (In thousands) Operating leases(3) $ 10,883 $ 2,278 $ 4,600 $ 3,940 $ 65 $ — $ — Atwood Achiever drilling rig contract 80,325 80,325 — — — — — (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. (2) Represents payments for the period from July 1, 2017 through December 31, 2017. (3) Primarily relates to corporate office and foreign office leases.

Additional Financial Informatio

Additional Financial Information	6 Months Ended
	Jun. 30, 2017
Additional Financial Information
Additional Financial Information	14. Additional Financial Information Accrued Liabilities Accrued liabilities consisted of the following: June 30, December 31, 2017 2016 (In thousands) Accrued liabilities: Exploration, development and production $ 149,851 $ 76,194 General and administrative expenses 16,847 31,243 Interest 19,511 17,247 Income taxes — 2,579 Taxes other than income 2,815 1,914 Other 1,237 529 $ 190,261 $ 129,706 Other Income, Net Other income, net consisted of $10.2 million and zero of Loss of Production Income (“LOPI”) proceeds, net related to the turret bearing issue on the Jubilee FPSO for the three months ended June 30, 2017 and 2016, respectively and $58.7 million and zero for the six months ended June 30, 2017 and 2016, respectively. Our LOPI coverage for this incident ended in May 2017. Facilities Insurance Modifications, Net Facilities insurance modifications, net consists of costs associated with the conversion of the Jubilee FPSO to a permanently spread moored facility, net of related insurance proceeds. Other Expenses, Net Other expenses, net incurred during the period is comprised of the following: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (In thousands) Inventory write-off $ 547 $ (532) $ 547 $ 15,177 Gain on insurance settlements — — (461) (956) Disputed charges and related costs 1,209 — 2,439 — Loss on equity method investment 6,426 — 6,426 — Other, net 252 362 245 342 Other expenses, net $ 8,434 $ (170) $ 9,196 $ 14,563 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 properly 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. During the three and six month periods ended June 30, 2017, we recognized $6.4 million related to our share of losses related to our equity investment in KBSL.

Accounting Policies (Policies)

Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2017
Accounting Policies
General	General The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of June 30, 2017, the changes in the consolidated statements of shareholders’ equity for the six months ended June 30, 2017, the consolidated results of operations for the three and six months ended June 30, 2017 and 2016, and the consolidated cash flows for the six months ended June 30, 2017 and 2016. 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, 2016, included in our annual report on Form 10-K.
Investment in Corporate Joint Venture	Investment in Corporate Joint Venture Kosmos holds a 50.01% interest in Kosmos BP Senegal Limited (“KBSL”), which we exercise significant influence over. Our investment in KBSL is accounted for under the equity method of accounting. In applying the equity method of accounting, our investment in KBSL was initially recorded at carryover basis and subsequently adjusted for the Company’s proportionate share of earnings, losses and distributions. During the three and six month periods ended June 30, 2017 we recognized $6.4 million related to our share of losses in KBSL. As of June 30, 2017, our investment in KBSL was $127.5 million and is reported as an equity method investment in our consolidated balance sheets. We had related party receivables of $26.2 million as of June 30, 2017, which relate to amounts due from KBSL for costs incurred by Kosmos on behalf of KBSL.
Reclassifications	Reclassifications Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows.
Cash, Cash Equivalents and Restricted Cash	Cash, Cash Equivalents and Restricted Cash June 30, December 31, 2017 2016 (In thousands) Cash and cash equivalents $ 162,474 $ 194,057 Restricted cash - current 40,776 24,506 Restricted cash - long-term 28,295 54,632 Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ 231,545 $ 273,195 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 our commercial debt facility (the “Facility”), we are 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 June 30, 2017 and December 31, 2016, we had $24.6 million and $24.5 million, respectively, in current restricted cash to meet this requirement. In addition, in accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of June 30, 2017 and December 31, 2016, we had $16.2 million and zero, respectively, of current restricted cash and $28.3 million and $54.6 million, respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts.
Inventories	Inventories Inventories consisted of $74.0 million and $68.1 million of materials and supplies and $5.9 million and $6.3 million of hydrocarbons as of June 30, 2017 and December 31, 2016, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded write downs of $0.5 million and $15.2 million during the six months ended June 30, 2017 and 2016, respectively, for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.

Accounting Policies (Tables)

Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2017
Accounting Policies
Schedule of cash and cash equivalents	June 30, December 31, 2017 2016 (In thousands) Cash and cash equivalents $ 162,474 $ 194,057 Restricted cash - current 40,776 24,506 Restricted cash - long-term 28,295 54,632 Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows $ 231,545 $ 273,195

Property and Equipment (Tables)

Property and Equipment (Tables)	6 Months Ended
	Jun. 30, 2017
Property and Equipment
Schedule of property and equipment	June 30, December 31, 2017 2016 (In thousands) Oil and gas properties: Proved properties $ 1,373,694 $ 1,385,331 Unproved properties 624,615 919,056 Support equipment and facilities 1,384,349 1,386,448 Total oil and gas properties 3,382,658 3,690,835 Accumulated depletion (1,092,320) (989,946) Oil and gas properties, net 2,290,338 2,700,889 Other property 37,952 37,186 Accumulated depreciation (30,865) (29,183) Other property, net 7,087 8,003 Property and equipment, net $ 2,297,425 $ 2,708,892

Suspended Well Costs (Tables)

Suspended Well Costs (Tables)	6 Months Ended
	Jun. 30, 2017
Suspended Well Costs
Schedule of capitalized exploratory well costs	June 30, 2017 (In thousands) Beginning balance $ 734,463 Additions to capitalized exploratory well costs pending the determination of proved reserves 30,663 Reclassification due to determination of proved reserves — Divestitures(1) (206,400) Contribution of oil and gas property to equity method investment (131,764) Capitalized exploratory well costs charged to expense — Ending balance $ 426,962 (1) Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal transactions with BP.
Schedule of aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year	June 30, 2017 December 31, 2016 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 29,663 $ 279,809 Exploratory well costs capitalized for a period of one to two years 183,623 244,804 Exploratory well costs capitalized for a period of three to eight years 213,676 209,850 Ending balance $ 426,962 $ 734,463 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 6 5

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2017
Debt
Schedule of debt	June 30, December 31, 2017 2016 (In thousands) Outstanding debt principal balances: Facility $ 650,000 $ 850,000 Senior Notes 525,000 525,000 Total 1,175,000 1,375,000 Unamortized deferred financing costs and discounts(1) (47,497) (53,126) Long-term debt, net $ 1,127,503 $ 1,321,874 (1) Includes $26.8 million and $30.3 million of unamortized deferred financing costs related to the Facility and $20.7 million and $22.8 million of unamortized deferred financing costs and discounts related to the Senior Notes as of June 30, 2017 and December 31, 2016, respectively.
Schedule of estimated repayments of debt	Payments Due by Year Total 2017(2) 2018 2019 2020 2021 Thereafter (In thousands) Principal debt repayments(1) $ 1,175,000 $ — $ — $ 50,377 $ 404,971 $ 719,652 $ — (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on, as of June 30, 2017, our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of June 30, 2017, there were no borrowings under the Corporate Revolver. (2) Represents payments for the period July 1, 2017 through December 31, 2017.
Schedule of interest and other financing costs, net	Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (In thousands) Interest expense $ 22,792 $ 21,824 $ 45,973 $ 42,772 Amortization—deferred financing costs 2,551 2,551 5,102 5,102 Capitalized interest (7,376) (17,584) (16,935) (34,030) Deferred interest 634 149 949 (258) Interest income (760) (466) (1,740) (834) Other, net 1,624 2,404 2,902 6,450 Interest and other financing costs, net $ 19,465 $ 8,878 $ 36,251 $ 19,202

Derivative Financial Instrume27

Derivative Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2017
Derivative Instruments and Hedging Activities
Schedule of oil derivative contracts	Weighted Average Dated Brent Price per Bbl Deferred Premium Term Type of Contract MBbl Payable, Net Swap Sold Put Floor Ceiling Call 2017: July — December Swap with puts/calls 1,006 $ 2.13 $ 72.50 $ 55.00 $ — $ — $ 90.00 July — December Swap with puts 1,006 — 64.95 50.00 — — — July — December Three-way collars 2,012 1.72 — 30.00 45.00 60.00 — July — December Sold calls(1) 1,000 — — — — 85.00 — 2018: January — December Three-way collars 2,913 $ 0.74 $ — $ 41.57 $ 56.57 $ 65.90 $ — January — December Four-way collars 3,000 1.06 — 40.00 50.00 61.33 70.00 January — December Sold calls(1) 2,000 — — — — 65.00 — 2019: January — December 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	Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) July 2017 — December 2018 Capped swap 1-month LIBOR $ 200,000 1.23 % 3.00 %
Schedule of derivative instruments by balance sheet location	Estimated Fair Value Asset (Liability) June 30, December 31, Type of Contract Balance Sheet Location 2017 2016 (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ 36,825 $ 31,698 Interest rate Derivatives assets—current 216 — Commodity(2) Derivatives assets—long-term 10,015 3,226 Interest rate Derivatives assets—long-term 412 582 Derivative liabilities: Commodity(3) Derivatives liabilities—current (2,932) (19,163) Interest rate Derivatives liabilities—current — (529) Commodity(4) Derivatives liabilities—long-term (3,318) (14,123) Total derivatives not designated as hedging instruments $ 41,218 $ 1,691 (1) Includes net deferred premiums payable of $4.7 million and $3.9 million related to commodity derivative contracts as of June 30, 2017 and December 31, 2016, respectively. (2) Includes net deferred premiums payable of $3.5 million and $2.5 million related to commodity derivative contracts as of June 30, 2017 and December 31, 2016, respectively. (3) Includes zero and $30.9 thousand as of June 30, 2017 and December 31, 2016, respectively, which represents our provisional oil sales contract. Also includes net deferred premiums payable of $3.1 million and $6.2 million related to commodity derivative contracts as of June 30, 2017 and December 31, 2016, respectively. (4) Includes net deferred premiums receivable of $0.5 million and net deferred premiums payable of $0.6 million related to commodity derivative contracts as of June 30, 2017 and December 31, 2016, respectively.
Schedule of derivative instruments by location of gain/(loss)	Amount of Gain/(Loss) Amount of Gain/(Loss) Three Months Ended Six Months Ended June 30, June 30, Type of Contract Location of Gain/(Loss) 2017 2016 2017 2016 (In thousands) Derivatives not designated as hedging instruments: Commodity(1) Oil and gas revenue $ (4,552) $ (1,665) $ (4,560) $ (1,055) Commodity Derivatives, net 25,411 (54,988) 63,268 (50,643) Interest rate Interest expense (92) (898) 236 (3,476) Total derivatives not designated as hedging instruments $ 20,767 $ (57,551) $ 58,944 $ (55,174) (1) Amounts represent the change in fair value of our provisional oil sales contracts.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2017
Fair Value Measurements
Schedule of Company's assets and liabilities that are measured at fair value on a recurring basis	Fair Value Measurements Using: Quoted Prices in Active Markets for Significant Other Significant Identical Assets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) June 30, 2017 Assets: Commodity derivatives $ — $ 46,840 $ — $ 46,840 Interest rate derivatives — 628 — 628 Liabilities: Commodity derivatives — (6,250) — (6,250) Interest rate derivatives — — — — Total $ — $ 41,218 $ — $ 41,218 December 31, 2016 Assets: Commodity derivatives $ — $ 34,924 $ — $ 34,924 Interest rate derivatives — 582 — 582 Liabilities: Commodity derivatives — (33,286) — (33,286) Interest rate derivatives — (529) — (529) Total $ — $ 1,691 $ — $ 1,691
Schedule of carrying values and fair values of financial instruments that are not carried at fair value	June 30, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 505,612 $ 536,356 $ $ Facility 650,000 650,000 Total $ 1,155,612 $ 1,186,356 $ 1,353,716 $ 1,378,938

Equity-based Compensation (Tabl

Equity-based Compensation (Tables)	6 Months Ended
	Jun. 30, 2017
Restricted stock awards
Equity-based Compensation
Schedule of plan activity	Weighted- Service Vesting Average Restricted Stock Grant-Date Awards Fair Value (In thousands) Outstanding at December 31, 2016 488 $ 8.83 Granted — — Forfeited — — Vested (268) 8.97 Outstanding at June 30, 2017 220 8.64
Restricted stock units
Equity-based Compensation
Schedule of plan activity	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, 2016 4,160 $ 6.91 7,194 $ 12.29 Granted 1,898 6.40 2,153 9.50 Forfeited (64) 7.60 (20) 11.53 Vested (1,735) 7.48 (823) 15.44 Outstanding at June 30, 2017 4,259 6.44 8,504 11.28

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2017
Income Taxes
Schedule of components of income (loss) before income taxes	Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (In thousands) Bermuda $ (16,759) $ (15,427) $ (32,940) $ (31,223) United States 1,382 2,219 2,794 4,315 Foreign—other 30,649 (110,660) 38,754 (157,975) Income (loss) before income taxes $ 15,272 $ (123,868) $ 8,608 $ (184,883)
Schedule of reconciliation of income tax expense and the reported effective tax rate	Three Months Ended Six Months Ended June 30, June 30, 2017 2016 2017 2016 Numerator: Net loss $ (8,467) $ (108,324) $ (37,308) $ (167,317) Basic income allocable to participating securities(1) — — — — Basic net loss allocable to common shareholders (8,467) (108,324) (37,308) (167,317) Diluted adjustments to income allocable to participating securities(1) — — — — Diluted net loss allocable to common shareholders $ (8,467) $ (108,324) $ (37,308) $ (167,317) Denominator: Weighted average number of shares outstanding: Basic 387,952 384,918 387,634 384,676 Restricted stock awards and units(1)(2) — — — — Diluted 387,952 384,918 387,634 384,676 Net loss per share: Basic $ (0.02) $ (0.28) $ (0.10) $ (0.43) Diluted $ (0.02) $ (0.28) $ (0.10) $ (0.43)

Commitments and Contingencies (

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2017
Commitments and Contingencies
Schedule of estimated future minimum commitments	Payments Due By Year(1) Total 2017(2) 2018 2019 2020 2021 Thereafter (In thousands) Operating leases(3) $ 10,883 $ 2,278 $ 4,600 $ 3,940 $ 65 $ — $ — Atwood Achiever drilling rig contract 80,325 80,325 — — — — — (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. (2) Represents payments for the period from July 1, 2017 through December 31, 2017. (3) Primarily relates to corporate office and foreign office leases.

Additional Financial Informat32

Additional Financial Information (Tables)	6 Months Ended
	Jun. 30, 2017
Additional Financial Information
Schedule of accrued liabilities	June 30, December 31, 2017 2016 (In thousands) Accrued liabilities: Exploration, development and production $ 149,851 $ 76,194 General and administrative expenses 16,847 31,243 Interest 19,511 17,247 Income taxes — 2,579 Taxes other than income 2,815 1,914 Other 1,237 529 $ 190,261 $ 129,706
Schedule of Other expenses, net incurred	Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (In thousands) Inventory write-off $ 547 $ (532) $ 547 $ 15,177 Gain on insurance settlements — — (461) (956) Disputed charges and related costs 1,209 — 2,439 — Loss on equity method investment 6,426 — 6,426 — Other, net 252 362 245 342 Other expenses, net $ 8,434 $ (170) $ 9,196 $ 14,563

Organization (Details)

Organization (Details)	6 Months Ended
	Jun. 30, 2017segment
Organization
Number of reportable segments	1

Accounting Policies (Details)

Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
Investment in Corporate Joint Venture
Equity method investment	$ 127,467		$ 127,467
Related party	26,208		26,208
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents	162,474		162,474		$ 194,057
Restricted cash - current	40,776		40,776		24,506
Restricted cash - long-term	28,295		28,295		54,632
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	231,545	$ 191,877	231,545	$ 191,877	273,195	$ 310,862
Inventories
Materials and supplies inventory	74,000		74,000		68,100
Hydrocarbons inventory	5,900		5,900		6,300
Write down of materials and supplies	547	$ (532)	547	$ 15,177
Restricted Cash | Petroleum agreements - performance guarantees
Cash, Cash Equivalents and Restricted Cash
Restricted cash - current	16,200		16,200		0
Restricted cash - long-term	28,300		28,300		54,600
Restricted Cash | Facility interest or the Senior Notes plus the Corporate Revolver interest
Cash, Cash Equivalents and Restricted Cash
Restricted cash - current	$ 24,600		$ 24,600		$ 24,500
Restricted cash period required as per commercial debt facility to meet interest and commitment fee payments			6 months
Kosmos BP Senegal Limited
Investment in Corporate Joint Venture
Ownership percentage	50.01%		50.01%
Senior Notes | 7.875% senior notes due 2021
Cash, Cash Equivalents and Restricted Cash
Interest rate	7.875%		7.875%

Acquisitions and Divestitures (

Acquisitions and Divestitures (Details) bbl in Billions	1 Months Ended				3 Months Ended		6 Months Ended
	Jun. 30, 2017USD ($)	Feb. 28, 2017	Jan. 31, 2017item	Dec. 31, 2016USD ($)bbl	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Nov. 30, 2015USD ($)
Acquisitions and Divestitures
Proceeds on sale of assets							$ 222,068,000	$ 196,000
Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | Timis Corporation
Acquisitions and Divestitures
Participating interests (as a percent)							30.00%
Mauritania And Senegal Offshore Block | Maximum
Acquisitions and Divestitures
Spending by third party for exploration and appraisal costs							$ 221,000,000
Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Acquisitions and Divestitures
Participating interests (as a percent)					60.00%
Sales and purchase agreement | Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Acquisitions and Divestitures
Participating interests (as a percent)		60.00%		65.00%
Percentage increase in equity in each contract area				5.00%
Sales and purchase agreement and farm-out agreements | Mauritania And Senegal Offshore Block
Acquisitions and Divestitures
Reduction in unproved property	$ 221,900,000				$ 221,900,000		221,900,000
Timis Corporation Limited
Acquisitions and Divestitures
Line of credit receivable									$ 30,000,000
Amount expected to be received	16,000,000				16,000,000		16,000,000
Timis Corporation Limited | Other receivables
Acquisitions and Divestitures
Line of credit receivable amount outstanding	16,000,000				16,000,000		$ 16,000,000
Timis Corporation Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Acquisitions and Divestitures
Participating interests (as a percent)							30.00%
Timis Corporation Limited | Farm-in agreement | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Acquisitions and Divestitures
Maximum cost per contingent exploration well				$ 120,000,000
BP | Farm-out agreements | Block C6 Block C8 Block C12 and Block C13 Mauritania
Acquisitions and Divestitures
Number of blocks covered by farm-out agreements | item			4
Participation interest acquired (as a percent)			62.00%
BP | Farm-out agreements | Mauritania And Senegal Offshore Block | Maximum
Acquisitions and Divestitures
Amount of potential and variable consideration per barrel				$ 2
Number of barrels | bbl				1
BP | Sales and purchase agreement | Kosmos BP Senegal Limited
Acquisitions and Divestitures
Participation interest acquired (as a percent)		49.99%
BP | Sales and purchase agreement and farm-out agreements | Mauritania And Senegal Offshore Block
Acquisitions and Divestitures
Upfront amount of cash received						$ 162,000,000
Spending by third party for exploration and appraisal costs				$ 221,000,000
Spending by third party for Kosmos' development costs				$ 533,000,000
Tullow | Farm-in agreement | Block C18 offshore Mauritania
Acquisitions and Divestitures
Interim costs and partial carry to be paid	2,100,000
Participation interest to be acquired (as a percent)							15.00%
Amount payable at the end of initial phase of exploration	$ 2,500,000				$ 2,500,000		$ 2,500,000

Joint Interest Billings (Detail

Joint Interest Billings (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Joint interest billings
Joint interest billings, net current	$ 56,606	$ 63,249
Long-term receivables - joint interest billings. noncurrent	45,671	45,663
TEN Discoveries | GNPC
Joint interest billings
Joint interest billings, net current	1,600	0
Long-term receivables - joint interest billings. noncurrent	$ 45,700	$ 44,000
TEN Discoveries | GNPC
Joint interest billings
GNPC's paying interest (as a percent)	5.00%

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Oil and gas properties:
Proved properties	$ 1,373,694		$ 1,373,694		$ 1,385,331
Unproved properties	624,615		624,615		919,056
Support equipment and facilities	1,384,349		1,384,349		1,386,448
Total oil and gas properties	3,382,658		3,382,658		3,690,835
Less: accumulated depletion	(1,092,320)		(1,092,320)		(989,946)
Oil and gas properties, net	2,290,338		2,290,338		2,700,889
Other property	37,952		37,952		37,186
Less: accumulated depreciation	(30,865)		(30,865)		(29,183)
Other property, net	7,087		7,087		8,003
Property and equipment, net	2,297,425		2,297,425		$ 2,708,892
Depletion expense	$ 69,900	$ 14,900	$ 102,400	$ 44,100

Suspended Well Costs (Details).

Suspended Well Costs (Details). $ in Thousands	6 Months Ended
	Jun. 30, 2017USD ($)	Jun. 30, 2017USD ($)project	Dec. 31, 2016USD ($)project	May 31, 2015project
Projects with exploratory well costs capitalized for more than one year
Capitalized exploratory well costs subsequently expensed in the same period	$ 3,600
Reconciliation of capitalized exploratory well costs on completed wells
Beginning balance	734,463
Additions to capitalized exploratory well costs pending the determination of proved reserves	30,663
Divestitures (1)	(206,400)
Contribution of oil and gas property to equity method investment	(131,764)
Ending balance	426,962
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		$ 29,663	$ 279,809
Exploratory well costs capitalized for a period one to two years		183,623	244,804
Exploratory well costs capitalized for a period of three to eight years		213,676	209,850
Ending balance	$ 734,463	$ 426,962	$ 734,463
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | project		6	5
Greater Tortue Discovery
Aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year
Number of additional appraisal wells drilled | project				2

Debt (Details)

Debt (Details) $ in Thousands	1 Months Ended			6 Months Ended
	Jun. 30, 2015USD ($)	Apr. 30, 2015USD ($)	Aug. 31, 2014USD ($)	Jun. 30, 2017USD ($)item	Apr. 30, 2017USD ($)	Apr. 01, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Mar. 31, 2014USD ($)
Debt
Outstanding debt principal				$ 1,175,000				$ 1,375,000
Unamortized issuance costs and discount (1)				(47,497)				(53,126)
Long-term debt, net				1,127,503				1,321,874
Net deferred financing costs				3,879				5,248
Scheduled maturities of debt during the five year period and thereafter
2,019				50,377
2,020				404,971
2,021				719,652
Facility
Debt
Outstanding debt principal				650,000				850,000
Unamortized issuance costs and discount (1)				(26,800)				(30,300)
Total commitment									$ 1,500,000
Current borrowing capacity						$ 1,300,000
Amount outstanding				650,000
Undrawn availability				650,800
Revolving-credit sublimit amount after March 31, 2018				$ 500,000
Availability period of revolving-credit sublimit				1 month
Amount outstanding under letters of credit				$ 0
Corporate Revolver
Debt
Total commitment	$ 400,000
Percentage of the margin used to calculate commitment fees	30.00%
Net deferred financing costs				3,900
Amount outstanding				0
Undrawn availability				400,000
Revolving Letter of Credit Facility
Debt
Total commitment					$ 70,000		$ 115,000
Amount outstanding				$ 57,700
Number of letters of credit | item				7
Senior Notes
Debt
Outstanding debt principal				$ 525,000				525,000
Unamortized issuance costs and discount (1)				$ (20,700)				$ (22,800)
Senior Notes | 7.875% senior notes due 2021
Debt
Senior notes offering face amount		$ 225,000	$ 300,000
Proceeds, net of offering discounts and deferred financing costs		$ 206,800	$ 292,500

Debt Interest (Details)

Debt Interest (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Debt
Interest expense	$ 22,792	$ 21,824	$ 45,973	$ 42,772
Amortization-deferred financing costs	2,551	2,551	5,102	5,102
Capitalized interest	(7,376)	(17,584)	(16,935)	(34,030)
Deferred interest	634	149	949	(258)
Interest income	(760)	(466)	(1,740)	(834)
Other, net	1,624	2,404	2,902	6,450
Interest and other financing costs, net	$ 19,465	$ 8,878	$ 36,251	$ 19,202

Derivative Financial Instrume41

Derivative Financial Instruments (Details)	1 Months Ended	6 Months Ended
	Jul. 31, 2017$ / bblMBbls	Jun. 30, 2017$ / bblMBbls
Term July 2017 To December 2017 | Three-way Collars
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		2,012
Weighted average deferred premium payable per Bbl		1.72
Weighted average sold put price per Bbl		30
Weighted average floor price per Bbl		45
Weighted average ceiling price per Bbl		60
Term July 2017 To December 2017 | Swaps with puts
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		1,006
Weighted average swap price per Bbl		64.95
Weighted average sold put price per Bbl		50
Term July 2017 To December 2017 | Sold calls
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		1,000
Weighted average ceiling price per Bbl		85
Term July 2017 To December 2017 | Swap with puts/calls
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		1,006
Weighted average deferred premium payable per Bbl		2.13
Weighted average swap price per Bbl		72.50
Weighted average sold put price per Bbl		55
Weighted average purchased call price per Bbl		90
Term January 2018 to December 2018 | Three-way Collars
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		2,913
Weighted average deferred premium payable per Bbl		0.74
Weighted average sold put price per Bbl		41.57
Weighted average floor price per Bbl		56.57
Weighted average ceiling price per Bbl		65.90
Term January 2018 to December 2018 | Four-way Collars
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		3,000
Weighted average deferred premium payable per Bbl		1.06
Weighted average sold put price per Bbl		40
Weighted average floor price per Bbl		50
Weighted average ceiling price per Bbl		61.33
Weighted average purchased call price per Bbl		70
Term January 2018 to December 2018 | Sold calls
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		2,000
Weighted average ceiling price per Bbl		65
Term January 2019 to December 2019 | Three-way Collars
Derivative Financial Instruments
Volumes (in MBbl) | MBbls	3,000
Weighted average sold put price per Bbl	40
Weighted average floor price per Bbl	50
Weighted average ceiling price per Bbl	61.67
Term January 2019 to December 2019 | Sold calls
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		913
Weighted average ceiling price per Bbl		80

Derivative Financial Instrume42

Derivative Financial Instruments - Swaps (Details) - 1-month LIBOR - Interest Rate Cap Swap - Term July 2017 To December 2018 $ in Thousands	Jun. 30, 2017USD ($)
Derivative Financial Instruments
Weighted Average Notional Amount	$ 200,000
Weighted Average Fixed Rate (as a percent)	1.23%
Interest rate cap	3.00%

Derivative Financial Instrume43

Derivative Financial Instruments - Derivatives (Details) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Derivative instruments, Balance Sheet Location
Derivatives assets - current	$ 37,041,000	$ 31,698,000
Derivatives assets-long-term	10,427,000	3,808,000
Derivatives liabilities - current	(2,932,000)	(19,692,000)
Derivatives liabilities - long-term	(3,318,000)	(14,123,000)
Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Total	41,218,000	1,691,000
Commodity derivatives | Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Derivatives assets - current	36,825,000	31,698,000
Derivatives assets-long-term	10,015,000	3,226,000
Derivatives liabilities - current	(2,932,000)	(19,163,000)
Derivatives liabilities - long-term	(3,318,000)	(14,123,000)
Net deferred premiums receivable related to commodity derivative contracts - non current liabilities	500,000
Net deferred premiums payable related to commodity derivative contracts - current assets	4,700,000	3,900,000
Net deferred premiums payable related to commodity derivative contracts - non current assets	3,500,000	2,500,000
Net deferred premiums payable related to commodity derivative contracts - current liabilities	3,100,000	6,200,000
Net deferred premiums payable related to commodity derivative contracts - non current liabilities		600,000
Commodity derivatives | Not designated as hedging instruments | Oil and gas revenue
Derivative instruments, Balance Sheet Location
Derivatives liabilities - current	0	(30,900)
Interest rate contracts | Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Derivatives assets - current	216,000
Derivatives assets-long-term	$ 412,000	582,000
Derivatives liabilities - current		$ (529,000)

Derivative Financial Instrume44

Derivative Financial Instruments- Location of Gain (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives not designated as hedging instruments	$ 20,767	$ (57,551)	$ 58,944	$ (55,174)
Commodity derivatives | Oil and gas revenue
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives not designated as hedging instruments	(4,552)	(1,665)	(4,560)	(1,055)
Commodity derivatives | Derivatives, net
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives not designated as hedging instruments	25,411	(54,988)	63,268	(50,643)
Interest rate contracts | Interest expense
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives not designated as hedging instruments	$ (92)	$ (898)	$ 236	$ (3,476)

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Carrying Value
Liabilities:
Long-term debt	$ 1,155,612	$ 1,353,716
Total Fair Value
Liabilities:
Long-term debt	1,186,356	1,378,938
Recurring basis
Liabilities:
Total fair value, net	41,218	1,691
Recurring basis | Commodity derivatives
Assets:
Derivative asset, fair value	46,840	34,924
Liabilities:
Derivative liability, fair value	(6,250)	(33,286)
Recurring basis | Interest rate contracts
Assets:
Derivative asset, fair value	628	582
Liabilities:
Derivative liability, fair value		(529)
Recurring basis | Level 2
Liabilities:
Total fair value, net	41,218	1,691
Recurring basis | Level 2 | Commodity derivatives
Assets:
Derivative asset, fair value	46,840	34,924
Liabilities:
Derivative liability, fair value	(6,250)	(33,286)
Recurring basis | Level 2 | Interest rate contracts
Assets:
Derivative asset, fair value	628	582
Liabilities:
Derivative liability, fair value		(529)
Facility | Carrying Value
Liabilities:
Long-term debt	650,000	850,000
Facility | Total Fair Value
Liabilities:
Long-term debt	650,000	850,000
Senior Notes | Carrying Value
Liabilities:
Long-term debt	505,612	503,716
Senior Notes | Total Fair Value
Liabilities:
Long-term debt	$ 536,356	$ 528,938

Equity-based Compensation (Deta

Equity-based Compensation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
LTIP
Compensation agreement
Compensation expense recognized	$ 10.5	$ 10.5	$ 20.3	$ 21.2
Tax benefit	3.5	3.3	6.8	6.9
Net tax shortfall related to equity-based compensation	3	3.1	2.8	4.3
Fair value of awards vested	$ 10.5	$ 7.7	$ 19.3	$ 11.2
Other disclosures
Number of shares remaining available for grant	3,200		3,200
Minimum | LTIP
Equity-based Compensation
Vesting period			3 years
Maximum | LTIP
Equity-based Compensation
Vesting period			4 years
Service Vesting Restricted Stock Awards | LTIP
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)			488
Vested (in shares)			(268)
Outstanding at the end of the period (in shares)	220		220
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)			$ 8.83
Vested (in dollars per share)			8.97
Outstanding at the end of the period (in dollars per share)	$ 8.64		8.64
Market/Service Vesting Restricted Stock Awards | Minimum | LTIP
Weighted-Average Grant-Date Fair Value for awards
Granted (in dollars per share)			9.45
Weighted-Average Grant-Date Fair Value
Granted (in dollars per share)			$ 9.45
Significant assumptions used to calculate fair values
Expected volatility (as a percent)			55.00%
Risk-free interest rate (as a percent)			0.50%
Market/Service Vesting Restricted Stock Awards | Maximum | LTIP
Other disclosures
Vesting percentage of the awards granted			100.00%
Service Vesting Restricted Stock Units | LTIP
Weighted-Average Grant-Date Fair Value for awards
Granted (in dollars per share)			$ 6.40
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)			4,160
Granted (in shares)			1,898
Forfeited (in shares)			(64)
Vested (in shares)			(1,735)
Outstanding at the end of the period (in shares)	4,259		4,259
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)			$ 6.91
Granted (in dollars per share)			6.40
Forfeited (in dollars per share)			7.60
Vested (in dollars per share)			7.48
Outstanding at the end of the period (in dollars per share)	$ 6.44		6.44
Market/Service Vesting Restricted Stock Units | LTIP
Weighted-Average Grant-Date Fair Value for awards
Granted (in dollars per share)			$ 9.50
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)			7,194
Granted (in shares)			2,153
Forfeited (in shares)			(20)
Vested (in shares)			(823)
Outstanding at the end of the period (in shares)	8,504		8,504
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)			$ 12.29
Granted (in dollars per share)			9.50
Forfeited (in dollars per share)			11.53
Vested (in dollars per share)			15.44
Outstanding at the end of the period (in dollars per share)	$ 11.28		11.28
Market/Service Vesting Restricted Stock Units | Minimum | LTIP
Weighted-Average Grant-Date Fair Value for awards
Granted (in dollars per share)			4.83
Weighted-Average Grant-Date Fair Value
Granted (in dollars per share)			$ 4.83
Significant assumptions used to calculate fair values
Expected volatility (as a percent)			44.00%
Risk-free interest rate (as a percent)			0.50%
Market/Service Vesting Restricted Stock Units | Maximum | LTIP
Weighted-Average Grant-Date Fair Value for awards
Granted (in dollars per share)			$ 15.81
Weighted-Average Grant-Date Fair Value
Granted (in dollars per share)			$ 15.81
Significant assumptions used to calculate fair values
Expected volatility (as a percent)			54.00%
Risk-free interest rate (as a percent)			1.40%
Other disclosures
Vesting percentage of the awards granted			200.00%
Restricted Stock Awards and Restricted Stock Units
Weighted-Average Grant-Date Fair Value
Compensation expense not yet recognized	$ 42.7		$ 42.7
Weighted average period over which compensation expense is to be recognized			1 year 6 months 29 days

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Taxes
Income tax expense (benefit)	$ 23,739	$ (15,544)	$ 45,916	$ (17,566)
Effective tax rate (as a percent)	155.00%	13.00%	533.00%	10.00%
Income (loss) before income taxes	$ 15,272	$ (123,868)	$ 8,608	$ (184,883)
Bermuda
Income Taxes
Income (loss) before income taxes	(16,759)	(15,427)	(32,940)	(31,223)
United States
Income Taxes
Income (loss) before income taxes	1,382	2,219	$ 2,794	4,315
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	$ 30,649	$ (110,660)	$ 38,754	$ (157,975)

Net Income (Loss) Per Share (De

Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Numerator:
Net loss	$ (8,467)	$ (108,324)	$ (37,308)	$ (167,317)
Basic net loss allocable to common shareholders	(8,467)	(108,324)	(37,308)	(167,317)
Diluted net loss allocable to common shareholders	$ (8,467)	$ (108,324)	$ (37,308)	$ (167,317)
Weighted average number of shares used to compute net loss per share:
Basic (in shares)	387,952	384,918	387,634	384,676
Diluted (in shares)	387,952	384,918	387,634	384,676
Net income (loss) per share:
Basic (in dollars per share)	$ (0.02)	$ (0.28)	$ (0.10)	$ (0.43)
Diluted (in dollars per share)	$ (0.02)	$ (0.28)	$ (0.10)	$ (0.43)
Outstanding restricted stock awards and units excluded from the computations of diluted net income per share (in shares)	13,000	12,300	13,000	12,300

Commitments and Contingencies49

Commitments and Contingencies (Details) $ in Thousands	1 Months Ended	3 Months Ended	6 Months Ended
	Jan. 31, 2017USD ($)	Mar. 31, 2017USD ($)	Jun. 30, 2017USD ($)km²item
Mauritania
Offshore drilling rig contract commitments
Number of exploration wells | item			2
Sao Tome and Principe
Commitments and contingencies
3 D seismic requirements (in square kilometers) | km²			4,750
Western Sahara
Commitments and contingencies
3 D seismic requirements (in square kilometers) | km²			5,000
Mauritania And Senegal Offshore Block | Maximum
Commitments and contingencies
Spending by third party for exploration and appraisal costs			$ 221,000
Operating leases
Future minimum rental commitments
2,017			2,278
2,018			4,600
2,019			3,940
2,020			65
Total			10,883
Atwood Achiever drilling rig contract
Future minimum rental commitments
2,017			80,325
Total			$ 80,325
Atwood Achiever drilling rig contract | Kosmos Energy Ventures
Future minimum rental commitments
Recovery payment for reverting the rig rate back to original day rate		$ 48,100
Rig rate per day - subsidiary's revert option	$ 600

Additional Financial Informat50

Additional Financial Information - Accrued Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Accrued liabilities:
Exploration, development and production	$ 149,851		$ 149,851		$ 76,194
General and administrative expenses	16,847		16,847		31,243
Interest	19,511		19,511		17,247
Income taxes					2,579
Taxes other than income	2,815		2,815		1,914
Other	1,237		1,237		529
Accrued liabilities	190,261		190,261		$ 129,706
Other Income
Other Income, net	10,200	$ 0	58,700	$ 0
Other Expenses, Net
Inventory write-off	547	(532)	547	15,177
Gain on insurance settlements			(461)	(956)
Disputed charges and related costs	1,209		2,439
Loss on equity method investment	(6,426)		(6,426)
Other, net	252	362	245	342
Other expenses, net	$ 8,434	$ (170)	$ 9,196	$ 14,563