Document and Entity Information - shares	9 Months Ended
Document and Entity Information - shares	Sep. 30, 2017	Nov. 01, 2017
Document and Entity Information
Entity Registrant Name	Kosmos Energy Ltd.
Entity Central Index Key	0001509991
Document Type	10-Q
Document Period End Date	Sep. 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		389,355,364
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3

CONSOLIDATED BALANCE SHEETS - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 164,162,000	$ 194,057,000
Restricted cash	55,852,000	24,506,000
Receivables:
Joint interest billings, net	75,373,000	63,249,000
Oil sales	51,726,000	54,195,000
Related party	6,446,000	0
Other	15,756,000	25,893,000
Inventories	74,275,000	74,380,000
Prepaid expenses and other	9,359,000	7,209,000
Derivatives	16,200,000	31,698,000
Total current assets	469,149,000	475,187,000
Property and equipment:
Oil and gas properties, net	2,251,977,000	2,700,889,000
Other property, net	6,424,000	8,003,000
Property and equipment, net	2,258,401,000	2,708,892,000
Other assets:
Equity method investment	122,664,000	0
Restricted cash	15,194,000	54,632,000
Long-term receivables - joint interest billings	47,525,000	45,663,000
Deferred financing costs, net of accumulated amortization of $13,267 and $11,213 at September 30, 2017 and December 31, 2016, respectively	3,194,000	5,248,000
Long-term deferred tax assets	34,546,000	37,827,000
Derivatives	2,412,000	3,808,000
Other	17,363,000	10,208,000
Total assets	2,970,448,000	3,341,465,000
Current liabilities:
Accounts payable	100,302,000	220,627,000
Accrued liabilities	173,804,000	129,706,000
Derivatives	9,016,000	19,692,000
Total current liabilities	283,122,000	370,025,000
Long-term liabilities:
Long-term debt, net	1,080,352,000	1,321,874,000
Derivatives	7,256,000	14,123,000
Asset retirement obligations	68,713,000	63,574,000
Deferred tax liabilities	511,891,000	482,221,000
Other long-term liabilities	9,871,000	8,449,000
Total long-term liabilities	1,678,083,000	1,890,241,000
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2017 and December 31, 2016	0	0
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 398,545,540 and 395,859,061 issued at September 30, 2017 and December 31, 2016, respectively	3,985,000	3,959,000
Additional paid-in capital	2,004,578,000	1,975,247,000
Accumulated deficit	(951,123,000)	(850,410,000)
Treasury stock, at cost, 9,188,819 and 9,101,395 shares at September 30, 2017 and December 31, 2016, respectively	(48,197,000)	(47,597,000)
Total shareholders’ equity	1,009,243,000	1,081,199,000
Total liabilities and shareholders’ equity	$ 2,970,448,000	$ 3,341,465,000

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Deferred financing costs, accumulated amortization	$ 13,267	$ 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	398,545,540	395,859,061
Treasury stock shares	9,188,819	9,101,395

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues and other income:
Oil and gas revenue	$ 151,240	$ 46,628	$ 391,035	$ 154,259
Other income, net	2	20,001	58,697	20,179
Total revenues and other income	151,242	66,629	449,732	174,438
Costs and expenses:
Oil and gas production	39,187	13,574	80,677	75,647
Facilities insurance modifications, net	(3,906)	5,946	(1,334)	5,946
Exploration expenses	36,983	66,238	162,679	126,498
General and administrative	20,029	21,914	50,555	59,672
Depletion and depreciation	73,490	17,838	180,909	66,031
Interest and other financing costs, net	18,478	11,066	54,729	30,268
Derivatives, net	26,864	(16,891)	(36,404)	33,752
Other expenses, net	5,037	(795)	14,233	13,768
Total costs and expenses	216,162	118,890	506,044	411,582
Loss before income taxes	(64,920)	(52,261)	(56,312)	(237,144)
Income tax expense (benefit)	(1,515)	7,502	44,401	(10,064)
Net loss	$ (63,405)	$ (59,763)	$ (100,713)	$ (227,080)
Net loss per share:
Basic (in dollars per share)	$ (0.16)	$ (0.15)	$ (0.26)	$ (0.59)
Diluted (in dollars per share)	$ (0.16)	$ (0.15)	$ (0.26)	$ (0.59)
Weighted average number of shares used to compute net loss per share:
Basic (in shares)	389,058,000	386,026,000	388,114,000	385,130,000
Diluted (in shares)	389,058,000	386,026,000	388,114,000	385,130,000

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - 9 months ended Sep. 30, 2017 - USD ($) shares in Thousands, $ in Thousands	Total	Common Shares	Additional Paid-in Capital	Accumulated Deficit	Treasury Stock
Balance at the beginning (in shares) at Dec. 31, 2016		395,859
Balance at the beginning at Dec. 31, 2016	$ 1,081,199	$ 3,959	$ 1,975,247	$ (850,410)	$ (47,597)
Increase (Decrease) in Shareholders' Equity
Equity-based compensation	30,873		30,873
Restricted stock awards and units (in shares)		2,686
Restricted stock awards and units	0	$ 26	(26)
Purchase of treasury stock	(2,116)		(1,516)		(600)
Net loss	(100,713)			(100,713)
Balance at the end (in shares) at Sep. 30, 2017		398,545
Balance at the end at Sep. 30, 2017	$ 1,009,243	$ 3,985	$ 2,004,578	$ (951,123)	$ (48,197)

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Operating activities
Net loss	$ (100,713)	$ (227,080)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	188,563	73,684
Deferred income taxes	32,820	(16,821)
Unsuccessful well costs	24,515	2,609
Change in fair value of derivatives	(25,924)	37,179
Cash settlements on derivatives, net (including $36.4 million and $146.5 million on commodity hedges during 2017 and 2016)	25,275	144,522
Equity-based compensation	29,945	30,391
Loss on equity method investment	11,230	0
Other	3,412	13,358
Changes in assets and liabilities:
Decrease in receivables	3,232	29,833
(Increase) decrease in inventories	58	(12,066)
(Increase) decrease in prepaid expenses and other	(19,327)	15,164
Decrease in accounts payable	(120,325)	(122,142)
Increase (decrease) in accrued liabilities	41,651	(34,254)
Net cash provided by (used in) operating activities	94,412	(65,623)
Investing activities
Oil and gas assets	(100,712)	(506,256)
Other property	(1,639)	(1,003)
Proceeds on sale of assets	222,068	210
Net cash provided by (used in) investing activities	119,717	(507,049)
Financing activities
Borrowings under long-term debt	0	450,000
Payments on long-term debt	(250,000)	0
Purchase of treasury stock	(2,116)	(1,930)
Net cash provided by (used in) financing activities	(252,116)	448,070
Net decrease in cash, cash equivalents and restricted cash	(37,987)	(124,602)
Cash, cash equivalents and restricted cash at beginning of period	273,195	310,862
Cash, cash equivalents and restricted cash at end of period	235,208	186,260
Cash paid for:
Interest	48,694	25,540
Income taxes	27,199	6,997
Non-cash activity:
Conversion of joint interest billings receivable to long-term note receivable	0	8,124
Contribution to equity method investment	$ 133,893	$ 0

Organization	9 Months Ended
Organization	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise. Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margins. Our assets include existing production and development projects offshore Ghana, 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 London Stock Exchange and is traded under the ticker symbol KOS. We have one reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are currently related to production located offshore Ghana.

Accounting Policies

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

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 September 30, 2017, the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2017, the consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, and the consolidated cash flows for the nine months ended September 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 held a 50.01% interest in Kosmos BP Senegal Limited (“KBSL”), which we exercised 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 of assets contributed and subsequently adjusted for the Company’s proportionate share of earnings, losses and distributions. During the three and nine month periods ended September 30, 2017 we recognized $4.8 million and $11.2 million, respectively, related to our share of losses in KBSL. As of September 30, 2017, our investment in KBSL was $122.7 million and is reported as an equity method investment in our consolidated balance sheets. We had related party receivables of $6.4 million as of September 30, 2017, which relate to amounts due from KBSL for costs incurred by Kosmos on behalf of KBSL.

In October 2017, upon approval, KBSL transferred a 30% working interest in the Cayar offshore Profond and Saint Louis Offshore Profond blocks offshore Senegal to BP Senegal Investments Limited in exchange for their outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and will no longer be accounted for under the equity method of accounting. After the transfer, KBSL has a 30% working interest in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") offshore Senegal.

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



	September 30, 2017		December 31, 2016
	(In thousands)
Cash and cash equivalents	$	164,162	$	194,057
Restricted cash - current	55,852		24,506
Restricted cash - long-term	15,194		54,632
Total cash, cash equivalents and restricted cash	$	235,208	$	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 September 30, 2017 and December 31, 2016, we had $24.7 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 September 30, 2017 and December 31, 2016, we had $31.1 million and zero, respectively, of current restricted cash and $15.2 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 $68.9 million and $68.1 million of materials and supplies and $5.4 million and $6.3 million of hydrocarbons as of September 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 nil and $15.2 million during the nine months ended September 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.

Recent Accounting Standards

Not Yet Adopted

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company completed its assessment of the new accounting standard and does not expect the adoption of this standard to have a material impact to our revenue recognition based on our existing contracts with customers. We will adopt the new standard during the first quarter of 2018 using the modified retrospective approach and there is no impact to our previously recorded revenue under the new standard.

Acquisitions and Divestitures	9 Months Ended
Acquisitions and Divestitures	Sep. 30, 2017
Acquisitions and Divestitures
Acquisitions and Divestitures	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 held a 60% participating interest in the Senegal Blocks. Previously we indicated that KBSL would hold a 65% participating interest upon the completion of our exercise in December 2016 of an option to increase our equity in each contract area by 5% in exchange for carrying Timis Corporation Limited’s (“Timis”) paying interest share of a third well in either contract area, subject to a maximum gross well cost of $120.0 million. However, we agreed to withdraw the exercise of this call option upon completion of an agreement between BP and Timis by which BP acquired Timis’ entire 30% participating interest in the Senegal Blocks. The transaction between BP and Timis was completed and KBSL’s participating interest in these blocks 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 $228 million exploration and appraisal carry (increased from $221 million upon completion of the transfer of a 30% working interest to BP Senegal Investments Limited), up to $533 million in a development carry and variable consideration up to $2 per barrel for up to 1 billion barrels of liquids, structured as a production royalty, subject to future liquids 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 Blocks petroleum agreements. The line of credit agreement was terminated in April 2017 when Timis entered into an agreement with BP to acquire Timis' 30% participating interest in the Senegal Blocks. As a result of the termination of this credit agreement, Kosmos received $16 million in August 2017 representing payment in full of outstanding amounts drawn on the line of credit. In September 2017, we closed a farm-in agreement with Tullow Mauritania Limited, a subsidiary of Tullow Oil plc (“Tullow”), to acquire a 15% non-operated participating interest in Block C18 offshore Mauritania. Based on the terms of the agreement, we will reimburse a portion of past and interim period costs and partially carry future costs. In October 2017, we entered into an agreement to acquire all of the equity interest of Hess International Petroleum Inc., a subsidiary of Hess Corporation ("Hess"), which holds an 85% paying interest (80.75% revenue interest) in the Ceiba Field and Okume Complex assets, through a joint venture with an affiliate of Trident Energy ("Trident"). Under the terms of the agreement, Kosmos and Trident will each own 50% of Hess International Petroleum Inc. Kosmos will be primarily responsible for exploration and subsurface evaluation while Trident will primarily be responsible for production operations and optimization. The transaction expands our position in the Gulf of Guinea and provides immediate cash flow through existing production with potential to increase existing production and also provides step-out exploration opportunities with potential tie-back through existing infrastructure. The gross acquisition price is $650 million effective as of January 1, 2017. Kosmos is expected to pay net cash consideration of approximately $240 million at close, subject to post-closing adjustments, with a combination of cash on hand and availability under the Facility. The transaction is expected to close by year end, subject to customary closing conditions, and will be accounted for as an equity method investment. In October 2017, we also entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. Ratification of the petroleum contracts by the President of Equatorial Guinea is expected by the end of the year. We presently have an 80% interest and are the operator in all three blocks, but pursuant to an agreement with Trident we expect to assign a 40% interest in the blocks to an affiliate of Trident after completion of the Hess transaction. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), currently has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration period of five years from the date of notification of ratification by the President of Equatorial Guinea. The first exploration period consists of two sub-periods of three and two years, respectively. The first exploration sub-period work program includes a 6,000 square kilometer 3D seismic acquisition requirement across the three blocks. Upon closing of the Hess transaction and the assignment of a 40% interest to the Trident affiliate noted above, interests in these three blocks will be 40% Kosmos, 40% Trident and 20% GEPetrol.

Joint Interest Billings	9 Months Ended
Joint Interest Billings	Sep. 30, 2017
Joint Interest Billings
Joint Interest Billings	Joint Interest Billings The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the 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 September 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 $47.5 million and $44.0 million, respectively, which are classified as long-term on the consolidated balance sheets.

Property and Equipment

9 Months Ended

Sep. 30, 2017

Property, Plant and Equipment [Abstract]

Property and Equipment

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



	September 30, 2017			December 31, 2016
	(In thousands)
Oil and gas properties:
Proved properties	$	1,371,641		$	1,385,331
Unproved properties	651,921			919,056
Support equipment and facilities	1,391,613			1,386,448
Total oil and gas properties	3,415,175			3,690,835
Accumulated depletion	(1,163,198		)	(989,946		)
Oil and gas properties, net	2,251,977			2,700,889

Other property	38,124			37,186
Accumulated depreciation	(31,700		)	(29,183		)
Other property, net	6,424			8,003

Property and equipment, net	$	2,258,401		$	2,708,892

We recorded depletion expense of $70.9 million and $15.6 million for the three months ended September 30, 2017 and 2016, respectively, and $173.3 million and $59.6 million for the nine months ended September 30, 2017 and 2016, respectively.

Suspended Well Costs

9 Months Ended

Sep. 30, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Suspended Well Costs

The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the nine months ended September 30, 2017. The table excludes $24.5 million in costs that were capitalized and subsequently expensed during the same period.



	September 30, 2017
	(In thousands)
Beginning balance	$	734,463
Additions to capitalized exploratory well costs pending the determination of proved reserves	67,543
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	$	463,842

__________________________________


(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:



	September 30, 2017		December 31, 2016
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	65,606	$	279,809
Exploratory well costs capitalized for a period of one to two years	184,486		244,804
Exploratory well costs capitalized for a period of three to eight years	213,750		209,850
Ending balance	$	463,842	$	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 September 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 October 2017, the Jubilee Unit was expanded to include the Mahogany and Teak discoveries. As part of the expansion of the Jubilee Unit, the capitalized exploratory well costs will be moved to proved property in the fourth quarter of 2017.

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 completed a drill stem test on the Tortue‑1 well in August 2017, which confirmed the production capabilities of the Greater Tortue Discovery. Data acquired from the drill stem test will be used to further optimize field development and to refine process design parameters critical to the Front End Engineering Design (FEED) process. Following additional technical and commercial 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

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Debt



	September 30, 2017			December 31, 2016
	(In thousands)
Outstanding debt principal balances:
Facility	$	600,000		$	850,000
Senior Notes	525,000			525,000
Total	1,125,000			1,375,000
Unamortized deferred financing costs and discounts(1)	(44,648		)	(53,126		)
Long-term debt, net	$	1,080,352		$	1,321,874

__________________________________


(1)	Includes $25.0 million and $30.3 million of unamortized deferred financing costs related to the Facility and $19.6 million and $22.8 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 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 August 2017, following the lender’s waiver of the September 30, 2017 semi-annual redetermination, the borrowing base under our Facility will remain at $1.3 billion. The borrowing base calculation includes value related to the Jubilee and TEN fields. As of September 30, 2017, borrowings under the Facility totaled $600.0 million and the undrawn availability under the Facility was $700.8 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 September 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 September 30, 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 September 30, 2017, we have $3.2 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 September 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 September 30, 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 September 30, 2017, there were eight outstanding letters of credit totaling $60.3 million under the LC Facility. The LC Facility contains customary cross default provisions.

7.875% Senior Secured Notes due 2021

During August 2014, the Company issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.

During April 2015, we issued an additional $225.0 million of Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million 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 September 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)	$	1,125,000	$	—	$	—	$	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 September 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 September 30, 2017, there were no borrowings under the Corporate Revolver.


(2)	Represents payments for the period October 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Interest expense	$	22,961		$	23,057		$	68,934		$	65,829
Amortization—deferred financing costs	2,551			2,551			7,653			7,653
Capitalized interest	(8,563		)	(15,545		)	(25,498		)	(49,575		)
Deferred interest	662			663			1,610			406
Interest income	(745		)	(485		)	(2,485		)	(1,319		)
Other, net	1,612			825			4,515			7,274
Interest and other financing costs, net	$	18,478		$	11,066		$	54,729		$	30,268

Derivative Financial Instruments

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

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

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

Oil Derivative Contracts

The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of September 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:
October — December	Swap with puts/calls	503	$	2.13	$	72.50	$	55.00	$	—	$	—	$	90.00
October — December	Swap with puts	503	—		64.95		50.00		—		—		—
October — December	Three-way collars	1,006	1.72		—		30.00		45.00		60.00		—
October — December	Sold calls(1)	500	—		—		—		—		85.00		—
2018:
January — December	Swap with puts	2,000	$	—	$	54.32	$	40.00	$	—	$	—	$	—
January — December	Three-way collars	2,913	0.74		—		41.57		56.57		65.90		—
January — December	Four-way collars	3,000	1.06		—		40.00		50.00		61.33		70.00
January — December	Sold calls(1)	2,000	—		—		—		—		65.00		—
2019:
January — December	Three-way collars	4,500	$	0.26	$	—	$	40.00	$	50.00	$	62.78	$	—
January — December	Sold calls(1)	913	—		—		—		—		80.00		—

__________________________________


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

In October 2017, we entered into costless swap contracts for 1.0 MMBbl from January 2018 through June 2018 with a fixed price of $57.25 per barrel, and costless swaps and sold put contracts for 2.0 MMBbl from July 2018 through December 2018 with a weighted average fixed price of $57.96 per barrel and a weighted average sold put price of $45.00 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 September 30, 2017:

Weighted Average

Term

Type of Contract

Floating Rate

Notional

Swap

Sold Call

(In thousands)

October 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 September 30, 2017 and December 31, 2016 and gain/(loss) from derivatives during the three and nine months ended September 30, 2017 and 2016, respectively:



		Estimated Fair Value
		Asset (Liability)
Type of Contract	Balance Sheet Location	September 30, 2017			December 31, 2016
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity(1)	Derivatives assets—current	$	15,811		$	31,698
Interest rate	Derivatives assets—current	389			—
Commodity(2)	Derivatives assets—long-term	2,107			3,226
Interest rate	Derivatives assets—long-term	305			582
Derivative liabilities:
Commodity(3)	Derivatives liabilities—current	(9,016		)	(19,163		)
Interest rate	Derivatives liabilities—current	—			(529		)
Commodity(4)	Derivatives liabilities—long-term	(7,256		)	(14,123		)
Total derivatives not designated as hedging instruments		$	2,340		$	1,691

__________________________________


(1)	Includes net deferred premiums payable of $2.0 million and $3.9 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016, respectively.


(2)	Includes net deferred premiums payable of $0.7 million and $2.5 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016, respectively.


(3)	Includes zero and $30.9 thousand as of September 30, 2017 and December 31, 2016, respectively, which represents our provisional oil sales contract. Also includes net deferred premiums payable of $4.4 million and $6.2 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016, respectively.


(4)	Includes net deferred premiums payable of $2.1 million and $0.6 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016, respectively.



		Amount of Gain/(Loss)					Amount of Gain/(Loss)
		Three Months Ended					Nine Months Ended
		September 30,					September 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	$	(6,221	)	$	344	$	(10,781	)	$	(712	)
Commodity	Derivatives, net	(26,864		)	16,891		36,404			(33,752		)
Interest rate	Interest expense	64			760		301			(2,715		)
Total derivatives not designated as hedging instruments		$	(33,021	)	$	17,995	$	25,924		$	(37,179	)

__________________________________


(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 September 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

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

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 September 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)
September 30,2017
Assets:
Commodity derivatives	$	—	$	17,918		$	—	$	17,918
Interest rate derivatives	—		694			—		694
Liabilities:
Commodity derivatives	—		(16,272		)	—		(16,272		)
Interest rate derivatives	—		—			—		—
Total	$	—	$	2,340		$	—	$	2,340
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 September 30, 2017 and December 31, 2016:



	September 30, 2017				December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Senior Notes	$	506,594	$	545,874	$	503,716	$	528,938
Facility	600,000		600,000		850,000		850,000
Total	$	1,106,594	$	1,145,874	$	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.

- Definition

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

+ References + Details

Equity-based Compensation

9 Months Ended

Sep. 30, 2017

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

Equity-based Compensation

Restricted Stock Awards and Restricted Stock Units

We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long-Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $9.6 million and $9.2 million during the three months ended September 30, 2017 and 2016, respectively, and $29.9 million and $30.4 million during the nine months ended September 30, 2017 and 2016, respectively. The total tax benefit for the three months ended September 30, 2017 and 2016 was $3.2 million and $3.0 million, respectively, and $9.9 million and $9.9 million during the nine months ended September 30, 2017 and 2016, respectively. Additionally, we recorded a net tax shortfall related to equity-based compensation of $0.2 million and $1.0 million for the three months ended September 30, 2017 and 2016, respectively, and $3.1 million and $5.3 million during the nine months ended September 30, 2017 and 2016, respectively. The fair value of awards vested during the three months ended September 30, 2017 and 2016 was approximately $1.4 million and $2.4 million, respectively, and $20.7 million and $13.4 million during the nine months ended September 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 September 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 September 30, 2017	220		8.64

The following table reflects the outstanding restricted stock units as of September 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	2,063		6.41		2,170		9.50
Forfeited	(123	)	7.03		(27	)	7.76
Vested	(1,864	)	7.50		(894	)	15.44
Outstanding at September 30, 2017	4,236		6.40		8,443		11.26

As of September 30, 2017, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $33.5 million over a weighted average period of 1.48 years. At September 30, 2017, the Company had approximately 3.4 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

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

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.

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Bermuda	$	(17,740	)	$	(15,989	)	$	(50,680	)	$	(47,212	)
United States	1,437			1,132			4,231			5,447
Foreign—other	(48,617		)	(37,404		)	(9,863		)	(195,379		)
Income (loss) before income taxes	$	(64,920	)	$	(52,261	)	$	(56,312	)	$	(237,144	)

Our effective tax rate for the three months ended September 30, 2017 and 2016 is 2% and 14%, respectively. For the nine months ended, September 30, 2017 and 2016, our effective tax rate was 79% and 4%, 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, due to the expected recovery 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 September 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 Loss Per Share

9 Months Ended

Sep. 30, 2017

Earnings Per Share [Abstract]

Net Loss Per Share

The following table is a reconciliation between net loss and the amounts used to compute basic and diluted net loss per share and the weighted average shares outstanding used to compute basic and diluted net loss per share:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Numerator:
Net loss	$	(63,405	)	$	(59,763	)	$	(100,713	)	$	(227,080	)
Basic income allocable to participating securities(1)	—			—			—			—
Basic net loss allocable to common shareholders	(63,405		)	(59,763		)	(100,713		)	(227,080		)
Diluted adjustments to income allocable to participating securities(1)	—			—			—			—
Diluted net loss allocable to common shareholders	$	(63,405	)	$	(59,763	)	$	(100,713	)	$	(227,080	)
Denominator:
Weighted average number of shares outstanding:
Basic	389,058			386,026			388,114			385,130
Restricted stock awards and units(1)(2)	—			—			—			—
Diluted	389,058			386,026			388,114			385,130
Net loss per share:
Basic	$	(0.16	)	$	(0.15	)	$	(0.26	)	$	(0.59	)
Diluted	$	(0.16	)	$	(0.15	)	$	(0.26	)	$	(0.59	)

__________________________________

(1)

Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net loss per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net loss per common share calculation in periods we are in a net loss position.


(2)	We excluded outstanding restricted stock awards and units of 12.9 million and 12.0 million for the three and nine months ended September 30, 2017 and 2016, respectively, from the computations of diluted net loss per share because the effect would have been anti-dilutive.

Commitments and Contingencies

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.

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 $228 million cumulative exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Equatorial Guinea, Mauritania and Western Sahara, we have 3D seismic requirements of 6,000 square kilometers, 7,600 square kilometers and 5,000 square kilometers, respectively. Additionally, in Morocco certain geological studies are also required. The Equatorial Guinea block commitments are subject to ratification by the President of Equatorial Guinea.

In January 2017, Kosmos Energy Ventures (“KEV”), a subsidiary of Kosmos Energy Ltd., elected to cancel the fourth year option of the ENSCO DS-12 (formerly 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 of 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 which was recorded as exploration expense.

Future minimum rental commitments under our leases at September 30, 2017, are as follows:



	Payments Due By Year(1)
	Total		2017(2)		2018		2019		2020		2021		Thereafter
	(In thousands)
Operating leases(3)	$	9,910	$	1,158	$	4,736	$	3,951	$	65	$	—	$	—
ENSCO DS-12 drilling rig contract	25,585		25,585		—		—		—		—		—

__________________________________


(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 October 1, 2017 through December 31, 2017.


(3)	Primarily relates to corporate office and foreign office leases.

Additional Financial Information

9 Months Ended

Sep. 30, 2017

Additional Financial Information

Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:



	September 30, 2017		December 31, 2016
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	130,543	$	76,194
General and administrative expenses	26,823		31,243
Interest	9,180		17,247
Income taxes	3,145		2,579
Taxes other than income	3,941		1,914
Other	172		529
	$	173,804	$	129,706

Other Income, Net

Other income, net consisted of zero Loss of Production Income (“LOPI”) proceeds, net related to the turret bearing issue on the Jubilee FPSO for the three months ended September 30, 2017 and 2016, and $58.7 million and $20.0 million for the nine months ended September 30, 2017 and 2016, respectively. Our LOPI coverage for this incident ended in May 2017.

Oil and gas production

Oil and gas production expense included insurance recoveries related to our increased cost of working covered by our LOPI policy of zero for the three months ended September 30, 2017 and 2016, and $17.1 million and zero, for the nine months ended September 30, 2017 and 2016, respectively.

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Inventory write-off	$	(500	)	$	—		$	47		$	15,177
(Gain) loss on insurance settlements	—			(3,047		)	(461		)	(4,003		)
Disputed charges and related costs	821			1,826			3,260			1,826
Loss on equity method investment	4,804			—			11,230			—
Other, net	(88		)	426			157			768
Other expenses, net	$	5,037		$	(795	)	$	14,233		$	13,768

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.

Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

General

Investment in Corporate Joint Venture

Reclassifications

Cash, Cash Equivalents and Restricted Cash



	September 30, 2017		December 31, 2016
	(In thousands)
Cash and cash equivalents	$	164,162	$	194,057
Restricted cash - current	55,852		24,506
Restricted cash - long-term	15,194		54,632
Total cash, cash equivalents and restricted cash	$	235,208	$	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.

Inventories

Recent Accounting Standards

Not Yet Adopted

Property and Equipment (Tables)

9 Months Ended

Sep. 30, 2017

Property, Plant and Equipment [Abstract]

Schedule of property and equipment

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



	September 30, 2017			December 31, 2016
	(In thousands)
Oil and gas properties:
Proved properties	$	1,371,641		$	1,385,331
Unproved properties	651,921			919,056
Support equipment and facilities	1,391,613			1,386,448
Total oil and gas properties	3,415,175			3,690,835
Accumulated depletion	(1,163,198		)	(989,946		)
Oil and gas properties, net	2,251,977			2,700,889

Other property	38,124			37,186
Accumulated depreciation	(31,700		)	(29,183		)
Other property, net	6,424			8,003

Property and equipment, net	$	2,258,401		$	2,708,892

Suspended Well Costs (Tables)

9 Months Ended

Sep. 30, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of capitalized exploratory well costs



	September 30, 2017
	(In thousands)
Beginning balance	$	734,463
Additions to capitalized exploratory well costs pending the determination of proved reserves	67,543
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	$	463,842

__________________________________


(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



	September 30, 2017		December 31, 2016
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	65,606	$	279,809
Exploratory well costs capitalized for a period of one to two years	184,486		244,804
Exploratory well costs capitalized for a period of three to eight years	213,750		209,850
Ending balance	$	463,842	$	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)

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Schedule of debt



	September 30, 2017			December 31, 2016
	(In thousands)
Outstanding debt principal balances:
Facility	$	600,000		$	850,000
Senior Notes	525,000			525,000
Total	1,125,000			1,375,000
Unamortized deferred financing costs and discounts(1)	(44,648		)	(53,126		)
Long-term debt, net	$	1,080,352		$	1,321,874

__________________________________


(1)	Includes $25.0 million and $30.3 million of unamortized deferred financing costs related to the Facility and $19.6 million and $22.8 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2017 and December 31, 2016, respectively.

Schedule of estimated repayments of debt

At September 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)	$	1,125,000	$	—	$	—	$	377	$	404,971	$	719,652	$	—

__________________________________

(1)


(2)	Represents payments for the period October 1, 2017 through December 31, 2017.

Schedule of interest and other financing costs, net

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Interest expense	$	22,961		$	23,057		$	68,934		$	65,829
Amortization—deferred financing costs	2,551			2,551			7,653			7,653
Capitalized interest	(8,563		)	(15,545		)	(25,498		)	(49,575		)
Deferred interest	662			663			1,610			406
Interest income	(745		)	(485		)	(2,485		)	(1,319		)
Other, net	1,612			825			4,515			7,274
Interest and other financing costs, net	$	18,478		$	11,066		$	54,729		$	30,268

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=64930739&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21521-112644

+ Details

Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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:
October — December	Swap with puts/calls	503	$	2.13	$	72.50	$	55.00	$	—	$	—	$	90.00
October — December	Swap with puts	503	—		64.95		50.00		—		—		—
October — December	Three-way collars	1,006	1.72		—		30.00		45.00		60.00		—
October — December	Sold calls(1)	500	—		—		—		—		85.00		—
2018:
January — December	Swap with puts	2,000	$	—	$	54.32	$	40.00	$	—	$	—	$	—
January — December	Three-way collars	2,913	0.74		—		41.57		56.57		65.90		—
January — December	Four-way collars	3,000	1.06		—		40.00		50.00		61.33		70.00
January — December	Sold calls(1)	2,000	—		—		—		—		65.00		—
2019:
January — December	Three-way collars	4,500	$	0.26	$	—	$	40.00	$	50.00	$	62.78	$	—
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)

October 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)
Type of Contract	Balance Sheet Location	September 30, 2017			December 31, 2016
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity(1)	Derivatives assets—current	$	15,811		$	31,698
Interest rate	Derivatives assets—current	389			—
Commodity(2)	Derivatives assets—long-term	2,107			3,226
Interest rate	Derivatives assets—long-term	305			582
Derivative liabilities:
Commodity(3)	Derivatives liabilities—current	(9,016		)	(19,163		)
Interest rate	Derivatives liabilities—current	—			(529		)
Commodity(4)	Derivatives liabilities—long-term	(7,256		)	(14,123		)
Total derivatives not designated as hedging instruments		$	2,340		$	1,691

__________________________________


(1)	Includes net deferred premiums payable of $2.0 million and $3.9 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016, respectively.


(2)	Includes net deferred premiums payable of $0.7 million and $2.5 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016, respectively.


(3)	Includes zero and $30.9 thousand as of September 30, 2017 and December 31, 2016, respectively, which represents our provisional oil sales contract. Also includes net deferred premiums payable of $4.4 million and $6.2 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016, respectively.


(4)	Includes net deferred premiums payable of $2.1 million and $0.6 million related to commodity derivative contracts as of September 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					Nine Months Ended
		September 30,					September 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	$	(6,221	)	$	344	$	(10,781	)	$	(712	)
Commodity	Derivatives, net	(26,864		)	16,891		36,404			(33,752		)
Interest rate	Interest expense	64			760		301			(2,715		)
Total derivatives not designated as hedging instruments		$	(33,021	)	$	17,995	$	25,924		$	(37,179	)

__________________________________


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

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

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)
September 30,2017
Assets:
Commodity derivatives	$	—	$	17,918		$	—	$	17,918
Interest rate derivatives	—		694			—		694
Liabilities:
Commodity derivatives	—		(16,272		)	—		(16,272		)
Interest rate derivatives	—		—			—		—
Total	$	—	$	2,340		$	—	$	2,340
December 31,2016
Assets:
Commodity derivatives	$	—	$	34,924		$	—	$	34,924
Interest rate derivatives	—		582			—		582
Liabilities:
Commodity derivatives	—		(33,286		)	—		(33,286		)
Interest rate derivatives	—		(529		)	—		(529		)
Total	$	—	$	1,691		$	—	$	1,691

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

The following table presents the carrying values and fair values at September 30, 2017 and December 31, 2016:



	September 30, 2017				December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Senior Notes	$	506,594	$	545,874	$	503,716	$	528,938
Facility	600,000		600,000		850,000		850,000
Total	$	1,106,594	$	1,145,874	$	1,353,716	$	1,378,938

Equity-based Compensation (Tables)

9 Months Ended

Sep. 30, 2017

Restricted stock awards

Equity-based Compensation

Schedule of plan activity

The following table reflects the outstanding restricted stock awards as of September 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 September 30, 2017	220		8.64

Restricted stock units

Equity-based Compensation

Schedule of plan activity

The following table reflects the outstanding restricted stock units as of September 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	2,063		6.41		2,170		9.50
Forfeited	(123	)	7.03		(27	)	7.76
Vested	(1,864	)	7.50		(894	)	15.44
Outstanding at September 30, 2017	4,236		6.40		8,443		11.26

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Schedule of components of income (loss) before income taxes

Income (loss) before income taxes is composed of the following:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Bermuda	$	(17,740	)	$	(15,989	)	$	(50,680	)	$	(47,212	)
United States	1,437			1,132			4,231			5,447
Foreign—other	(48,617		)	(37,404		)	(9,863		)	(195,379		)
Income (loss) before income taxes	$	(64,920	)	$	(52,261	)	$	(56,312	)	$	(237,144	)

Net Loss Per Share (Tables)

9 Months Ended

Sep. 30, 2017

Earnings Per Share [Abstract]

Schedule of reconciliation between net income and amounts used to compute basic and diluted EPS



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Numerator:
Net loss	$	(63,405	)	$	(59,763	)	$	(100,713	)	$	(227,080	)
Basic income allocable to participating securities(1)	—			—			—			—
Basic net loss allocable to common shareholders	(63,405		)	(59,763		)	(100,713		)	(227,080		)
Diluted adjustments to income allocable to participating securities(1)	—			—			—			—
Diluted net loss allocable to common shareholders	$	(63,405	)	$	(59,763	)	$	(100,713	)	$	(227,080	)
Denominator:
Weighted average number of shares outstanding:
Basic	389,058			386,026			388,114			385,130
Restricted stock awards and units(1)(2)	—			—			—			—
Diluted	389,058			386,026			388,114			385,130
Net loss per share:
Basic	$	(0.16	)	$	(0.15	)	$	(0.26	)	$	(0.59	)
Diluted	$	(0.16	)	$	(0.15	)	$	(0.26	)	$	(0.59	)

__________________________________

(1)


(2)	We excluded outstanding restricted stock awards and units of 12.9 million and 12.0 million for the three and nine months ended September 30, 2017 and 2016, respectively, from the computations of diluted net loss per share because the effect would have been anti-dilutive.

Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Schedule of estimated future minimum commitments

Future minimum rental commitments under our leases at September 30, 2017, are as follows:



	Payments Due By Year(1)
	Total		2017(2)		2018		2019		2020		2021		Thereafter
	(In thousands)
Operating leases(3)	$	9,910	$	1,158	$	4,736	$	3,951	$	65	$	—	$	—
ENSCO DS-12 drilling rig contract	25,585		25,585		—		—		—		—		—

__________________________________


(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 October 1, 2017 through December 31, 2017.


(3)	Primarily relates to corporate office and foreign office leases.

Additional Financial Information (Tables)

9 Months Ended

Sep. 30, 2017

Additional Financial Information

Schedule of accrued liabilities

Accrued liabilities consisted of the following:



	September 30, 2017		December 31, 2016
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	130,543	$	76,194
General and administrative expenses	26,823		31,243
Interest	9,180		17,247
Income taxes	3,145		2,579
Taxes other than income	3,941		1,914
Other	172		529
	$	173,804	$	129,706

Schedule of Other expenses, net incurred

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Inventory write-off	$	(500	)	$	—		$	47		$	15,177
(Gain) loss on insurance settlements	—			(3,047		)	(461		)	(4,003		)
Disputed charges and related costs	821			1,826			3,260			1,826
Loss on equity method investment	4,804			—			11,230			—
Other, net	(88		)	426			157			768
Other expenses, net	$	5,037		$	(795	)	$	14,233		$	13,768

Accounting Policies (Details) - USD ($)	1 Months Ended	3 Months Ended		9 Months Ended
Accounting Policies (Details) - USD ($)	Oct. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
Investment in Corporate Joint Venture
Loss on equity method investment		$ 4,804,000	$ 0	$ 11,230,000	$ 0
Equity method investment		122,664,000		122,664,000		$ 0
Related party receivables		6,446,000		6,446,000		0
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents		164,162,000		164,162,000		194,057,000
Restricted cash - current		55,852,000		55,852,000		24,506,000
Restricted cash - long-term		15,194,000		15,194,000		54,632,000
Total cash, cash equivalents and restricted cash		235,208,000	186,260,000	235,208,000	186,260,000	273,195,000	$ 310,862,000
Inventories
Materials and supplies inventory		68,900,000		68,900,000		68,100,000
Hydrocarbons inventory		5,400,000		5,400,000		6,300,000
Write down of materials and supplies		$ (500,000)	$ 0	$ 47,000	$ 15,177,000
Senior Notes \| 7.875% senior notes due 2021
Cash, Cash Equivalents and Restricted Cash
Interest rate		7.875%		7.875%
Restricted Cash \| Facility interest or the Senior Notes plus the Corporate Revolver interest
Cash, Cash Equivalents and Restricted Cash
Restricted cash - current		$ 24,700,000		$ 24,700,000		24,500,000
Restricted cash period required as per commercial debt facility to meet interest and commitment fee payments				6 months
Restricted Cash \| Petroleum agreements - performance guarantees
Cash, Cash Equivalents and Restricted Cash
Restricted cash - current		31,100,000		$ 31,100,000		0
Restricted cash - long-term		$ 15,200,000		$ 15,200,000		$ 54,600,000
Kosmos BP Senegal Limited
Investment in Corporate Joint Venture
Ownership percentage		50.01%		50.01%
Loss on equity method investment		$ 4,800,000		$ 11,200,000
Equity method investment		122,700,000		122,700,000
Related party receivables		$ 6,400,000		$ 6,400,000
Subsequent Event \| Cayar Offshore Profond And Saint Louis Offshore Profond Blocks \| Kosmos BP Senegal Limited
Investment in Corporate Joint Venture
Working interest	30.00%
Subsequent Event \| Cayar Offshore Profond And Saint Louis Offshore Profond Blocks \| BP Senegal Investments Limited \| Kosmos BP Senegal Limited
Investment in Corporate Joint Venture
Working interest transferred	30.00%

Acquisitions and Divestitures (Details) bbl in Billions	1 Months Ended							3 Months Ended	9 Months Ended
Acquisitions and Divestitures (Details) bbl in Billions	Oct. 31, 2017 USD ($) km² block	Sep. 30, 2017 USD ($) $ / bbl bbl	Aug. 31, 2017 USD ($)	Jun. 30, 2017	Feb. 28, 2017	Jan. 31, 2017 instrument	Dec. 31, 2016 USD ($)	Mar. 31, 2017 USD ($)	Sep. 30, 2017 USD ($) $ / bbl bbl	Nov. 30, 2015 USD ($)
Mauritania And Senegal Offshore Block \| Maximum
Acquisitions and Divestitures
Spending by third party for exploration and appraisal costs									$ 228,000,000
Kosmos BP Senegal Limited \| Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Acquisitions and Divestitures
Participating interests									60.00%
Sales and purchase agreement \| Ceiba Field and Okume Complex Assets \| Hess \| Subsequent Event
Acquisitions and Divestitures
Gross acquisition price	$ 650,000,000
Net cash consideration, to be paid	$ 240,000,000
Sales and purchase agreement \| Kosmos BP Senegal Limited \| Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Acquisitions and Divestitures
Participating interests					60.00%		65.00%
Percentage increase in equity in each contract area							5.00%
Sales and purchase agreement \| Hess \| Ceiba Field and Okume Complex Assets \| Subsequent Event
Acquisitions and Divestitures
Ownership percentage	50.00%
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
Timis \| Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Acquisitions and Divestitures
Participating interests				30.00%
Petroleum Agreement \| Blocks EG-21, S and W \| Subsequent Event
Acquisitions and Divestitures
Participating interests	80.00%
Number of blocks \| block	3
Area of petroleum exploration \| km²	6,000
3D seismic requirements \| km²	6,000
Assignment Agreement \| Blocks EG-21, S and W \| Subsequent Event
Acquisitions and Divestitures
Participating interests	40.00%
BP \| Farm-out agreements \| Block C6 Block C8 Block C12 and Block C13 Mauritania
Acquisitions and Divestitures
Participation interest acquired						62.00%
Number of blocks covered by farm-out agreements \| instrument						4
BP \| Farm-out agreements \| Mauritania And Senegal Offshore Block \| Maximum
Acquisitions and Divestitures
Amount of potential and variable consideration per barrel \| $ / bbl		2							2
Number of barrels \| bbl		1							1
BP \| Sales and purchase agreement \| Kosmos BP Senegal Limited
Acquisitions and Divestitures
Participation interest acquired							49.99%
BP \| Sales and purchase agreement and farm-out agreements \| Mauritania And Senegal Offshore Block
Acquisitions and Divestitures
Upfront amount of cash received								$ 162,000,000
Spending by third party for exploration and appraisal costs									$ 228,000,000
Spending by third party for exploration and appraisal costs, initial estimate									221,000,000
Spending by third party for Kosmos' development costs									$ 533,000,000
BP Senegal Investments Limited \| Kosmos BP Senegal Limited \| Cayar Offshore Profond And Saint Louis Offshore Profond Blocks \| Subsequent Event
Acquisitions and Divestitures
Working interest transferred	30.00%
Timis
Acquisitions and Divestitures
Line of credit receivable										$ 30,000,000
Amount received from contract termination			$ 16,000,000
Timis \| Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Acquisitions and Divestitures
Participating interests									30.00%
Timis \| Farm-in agreement \| Cayar Offshore Profond And Saint Louis Offshore Profond Blocks
Acquisitions and Divestitures
Maximum cost per contingent exploration well							$ 120,000,000
Tullow \| Farm-in agreement \| Block C18 offshore Mauritania
Acquisitions and Divestitures
Participating interests		15.00%
Hess \| Ceiba Field and Okume Complex Assets \| Subsequent Event
Acquisitions and Divestitures
Paying interest, percentage	85.00%
Revenue interest, percentage	80.75%
Trident \| Sales and purchase agreement \| Hess \| Ceiba Field and Okume Complex Assets \| Subsequent Event
Acquisitions and Divestitures
Ownership percentage	50.00%
Trident \| Assignment Agreement \| Blocks EG-21, S and W \| Subsequent Event
Acquisitions and Divestitures
Participating interests	40.00%
Participating interest to be assigned	40.00%
GEPetrol \| Petroleum Agreement \| Blocks EG-21, S and W \| Subsequent Event
Acquisitions and Divestitures
Carried participating interest percentage	20.00%
Percentage Converted From Carried To Participating	20.00%

Joint Interest Billings (Details) - USD ($)	12 Months Ended
Joint Interest Billings (Details) - USD ($)	Dec. 31, 2014	Sep. 30, 2017	Dec. 31, 2016
Joint interest billings
Joint interest billings, net		$ 75,373,000	$ 63,249,000
Long-term receivables - joint interest billings		47,525,000	45,663,000
TEN Discoveries \| GNPC
Joint interest billings
Joint interest billings, net		1,600,000	0
Long-term receivables - joint interest billings		$ 47,500,000	$ 44,000,000
TEN Discoveries \| GNPC
Joint interest billings
GNPC's paying interest	5.00%

Property and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
Property and Equipment (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Oil and gas properties:
Proved properties	$ 1,371,641		$ 1,371,641		$ 1,385,331
Unproved properties	651,921		651,921		919,056
Support equipment and facilities	1,391,613		1,391,613		1,386,448
Total oil and gas properties	3,415,175		3,415,175		3,690,835
Accumulated depletion	(1,163,198)		(1,163,198)		(989,946)
Oil and gas properties, net	2,251,977		2,251,977		2,700,889
Other property	38,124		38,124		37,186
Accumulated depreciation	(31,700)		(31,700)		(29,183)
Other property, net	6,424		6,424		8,003
Property and equipment, net	2,258,401		2,258,401		$ 2,708,892
Depletion expense	$ 70,900	$ 15,600	$ 173,300	$ 59,600

Suspended Well Costs (Details) $ in Thousands	9 Months Ended
Suspended Well Costs (Details) $ in Thousands	Sep. 30, 2017 USD ($)	Sep. 30, 2017 USD ($) project	Dec. 31, 2016 USD ($) project	May 31, 2015 project
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized exploratory well costs subsequently expensed in the same period	$ 24,500
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	67,543
Reclassification due to determination of proved reserves	0
Divestitures	(206,400)
Contribution of oil and gas property to equity method investment	(131,764)
Capitalized exploratory well costs charged to expense	0
Ending balance	463,842
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		$ 65,606	$ 279,809
Exploratory well costs capitalized for a period of one to two years		184,486	244,804
Exploratory well costs capitalized for a period of three to eight years		213,750	209,850
Ending balance	$ 734,463	$ 463,842	$ 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
Projects with exploratory well costs capitalized for more than one year
Number of additional appraisal wells drilled \| project				2

Debt - Schedule of Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Debt
Outstanding debt principal	$ 1,125,000	$ 1,375,000
Unamortized issuance costs and discount	(44,648)	(53,126)
Long-term debt, net	1,080,352	1,321,874
Facility
Debt
Outstanding debt principal	600,000	850,000
Unamortized issuance costs and discount	(25,000)	(30,300)
Senior Notes
Debt
Outstanding debt principal	525,000	525,000
Unamortized issuance costs and discount	$ (19,600)	$ (22,800)

Debt - Facility (Details) - Facility - USD ($)	9 Months Ended
Debt - Facility (Details) - Facility - USD ($)	Sep. 30, 2017	Mar. 31, 2014
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 1,500,000,000
Current borrowing capacity	$ 1,300,000,000
Amount outstanding	600,000,000
Undrawn availability	700,800,000
Revolving-credit sublimit amount after March 31, 2018	$ 500,000,000
Availability period of revolving-credit sublimit	1 month
Amount outstanding under letters of credit	$ 0

- Definition

The carrying value as of the balance sheet date of the current and noncurrent portions of long-term obligations drawn from a line of credit, which is a bank's commitment to make loans up to a specific amount. Examples of items that might be included in the application of this element may consist of letters of credit, standby letters of credit, and revolving credit arrangements, under which borrowings can be made up to a maximum amount as of any point in time conditional on satisfaction of specified terms before, as of and after the date of drawdowns on the line. Includes short-term obligations that would normally be classified as current liabilities but for which (a) postbalance sheet date issuance of a long term obligation to refinance the short term obligation on a long term basis, or (b) the enterprise has entered into a financing agreement that clearly permits the enterprise to refinance the short-term obligation on a long term basis and the following conditions are met (1) the agreement does not expire within 1 year and is not cancelable by the lender except for violation of an objectively determinable provision, (2) no violation exists at the BS date, and (3) the lender has entered into the financing agreement is expected to be financially capable of honoring the agreement.

+ References + Details

Debt - Corporate Revolver (Details) - USD ($)	1 Months Ended
Debt - Corporate Revolver (Details) - USD ($)	Jun. 30, 2015	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Net deferred financing costs		$ 3,194,000	$ 5,248,000
Corporate Revolver
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 400,000,000
Percentage of the margin used to calculate commitment fees	30.00%
Net deferred financing costs		3,200,000
Amount outstanding		0
Undrawn availability		$ 400,000,000

- Definition

+ References + Details

Debt - Revolving Letter of Credit Facility (Details) - Revolving Letter of Credit Facility	Sep. 30, 2017 USD ($) instrument	Apr. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 70,000,000	$ 115,000,000
Number of letters of credit \| instrument	8
Amount outstanding	$ 60,300,000

- Definition

+ References + Details

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

Debt - Maturities (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Scheduled maturities of debt during the five year period and thereafter
Total	$ 1,125,000,000	$ 1,375,000,000
2017	0
2018	0
2019	377,000
2020	404,971,000
2021	719,652,000
Thereafter	0
Senior Notes
Scheduled maturities of debt during the five year period and thereafter
Total	525,000,000	$ 525,000,000
Corporate Revolver
Scheduled maturities of debt during the five year period and thereafter
Amount outstanding	0
7.875% senior notes due 2021 \| Senior Notes
Scheduled maturities of debt during the five year period and thereafter
Total	$ 525,000,000

Debt - Interest and other financing costs, net (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Debt Disclosure [Abstract]
Interest expense	$ 22,961	$ 23,057	$ 68,934	$ 65,829
Amortization—deferred financing costs	2,551	2,551	7,653	7,653
Capitalized interest	(8,563)	(15,545)	(25,498)	(49,575)
Deferred interest	662	663	1,610	406
Interest income	(745)	(485)	(2,485)	(1,319)
Other, net	1,612	825	4,515	7,274
Interest and other financing costs, net	$ 18,478	$ 11,066	$ 54,729	$ 30,268

Derivative Financial Instruments - Schedule of oil derivative contracts (Details)	1 Months Ended	9 Months Ended
	Oct. 31, 2017 $ / bbl bbl	Sep. 30, 2017 $ / bbl bbl
Term Oct 2017 To December 2017 \| Swap with puts/calls
Derivative Financial Instruments
Volume (mbbls) \| bbl		503,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Deferred Premium Payable, Net (usd per bbl)		2.13
Swap (usd per bbl)		72.50
Sold Put (usd per bbl)		55.00
Floor (usd per bbl)		0.00
Ceiling (usd per bbl)		0.00
Call (usd per bbl)		90.00
Term Oct 2017 To December 2017 \| Swap with puts
Derivative Financial Instruments
Volume (mbbls) \| bbl		503,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Deferred Premium Payable, Net (usd per bbl)		0.00
Swap (usd per bbl)		64.95
Sold Put (usd per bbl)		50.00
Floor (usd per bbl)		0.00
Ceiling (usd per bbl)		0.00
Call (usd per bbl)		0.00
Term Oct 2017 To December 2017 \| Three-way collars
Derivative Financial Instruments
Volume (mbbls) \| bbl		1,006,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Deferred Premium Payable, Net (usd per bbl)		1.72
Swap (usd per bbl)		0.00
Sold Put (usd per bbl)		30.00
Floor (usd per bbl)		45.00
Ceiling (usd per bbl)		60.00
Call (usd per bbl)		0.00
Term Oct 2017 To December 2017 \| Sold calls
Derivative Financial Instruments
Volume (mbbls) \| bbl		500,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Deferred Premium Payable, Net (usd per bbl)		0.00
Swap (usd per bbl)		0.00
Sold Put (usd per bbl)		0.00
Floor (usd per bbl)		0.00
Ceiling (usd per bbl)		85.00
Call (usd per bbl)		0.00
Term January 2018 to December 2018 \| Swap with puts
Derivative Financial Instruments
Volume (mbbls) \| bbl		2,000,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Deferred Premium Payable, Net (usd per bbl)		0.00
Swap (usd per bbl)		54.32
Sold Put (usd per bbl)		40.00
Floor (usd per bbl)		0.00
Ceiling (usd per bbl)		0.00
Call (usd per bbl)		0.00
Term January 2018 to December 2018 \| Three-way collars
Derivative Financial Instruments
Volume (mbbls) \| bbl		2,913,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Deferred Premium Payable, Net (usd per bbl)		0.74
Swap (usd per bbl)		0.00
Sold Put (usd per bbl)		41.57
Floor (usd per bbl)		56.57
Ceiling (usd per bbl)		65.90
Call (usd per bbl)		0.00
Term January 2018 to December 2018 \| Four-way collars
Derivative Financial Instruments
Volume (mbbls) \| bbl		3,000,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Deferred Premium Payable, Net (usd per bbl)		1.06
Swap (usd per bbl)		0.00
Sold Put (usd per bbl)		40.00
Floor (usd per bbl)		50.00
Ceiling (usd per bbl)		61.33
Call (usd per bbl)		70.00
Term January 2018 to December 2018 \| Sold calls
Derivative Financial Instruments
Volume (mbbls) \| bbl		2,000,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Deferred Premium Payable, Net (usd per bbl)		0.00
Swap (usd per bbl)		0.00
Sold Put (usd per bbl)		0.00
Floor (usd per bbl)		0.00
Ceiling (usd per bbl)		65.00
Call (usd per bbl)		0.00
Term January 2019 to December 2019 \| Three-way collars
Derivative Financial Instruments
Volume (mbbls) \| bbl		4,500,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Deferred Premium Payable, Net (usd per bbl)		0.26
Swap (usd per bbl)		0.00
Sold Put (usd per bbl)		40.00
Floor (usd per bbl)		50.00
Ceiling (usd per bbl)		62.78
Call (usd per bbl)		0.00
Term January 2019 to December 2019 \| Sold calls
Derivative Financial Instruments
Volume (mbbls) \| bbl		913,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Deferred Premium Payable, Net (usd per bbl)		0.00
Swap (usd per bbl)		0.00
Sold Put (usd per bbl)		0.00
Floor (usd per bbl)		0.00
Ceiling (usd per bbl)		80.00
Call (usd per bbl)		0.00
Term January 2018 o June 2018 \| Costless swap \| Subsequent Event
Derivative Financial Instruments
Volume (mbbls) \| bbl	1,000,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Swap (usd per bbl)	57.25
Term July 2018 to December 2018 \| Swap with puts \| Subsequent Event
Derivative Financial Instruments
Volume (mbbls) \| bbl	2,000,000
Weighted Average Dated Brent Price Per Bbl [Abstract]
Sold Put (usd per bbl)	45.00
Swap (usd per bbl)	57.96

Derivative Financial Instruments - Schedule of interest rate derivative contracts (Details) - 1-month LIBOR - Interest Rate Cap Swap - October 2017 — December 2018 $ in Thousands	Sep. 30, 2017 USD ($)
Derivative Financial Instruments
Notional	$ 200,000
Swap	1.23%
Sold Call	3.00%

Derivative Financial Instruments - Derivatives instrument and gain/loss from derivatives (Details) - USD ($)	Sep. 30, 2017	Dec. 31, 2016
Derivative instruments, Balance Sheet Location
Derivatives assets—current	$ 16,200,000	$ 31,698,000
Derivatives assets—long-term	2,412,000	3,808,000
Derivatives liabilities—current	(9,016,000)	(19,692,000)
Derivatives liabilities—long-term	(7,256,000)	(14,123,000)
Derivatives not designated as hedging instruments:
Derivative instruments, Balance Sheet Location
Total derivatives not designated as hedging instruments	2,340,000	1,691,000
Derivatives not designated as hedging instruments: \| Commodity
Derivative instruments, Balance Sheet Location
Derivatives assets—current	15,811,000	31,698,000
Derivatives assets—long-term	2,107,000	3,226,000
Derivatives liabilities—current	(9,016,000)	(19,163,000)
Derivatives liabilities—long-term	(7,256,000)	(14,123,000)
Net deferred premiums payable related to commodity derivative contracts - current assets	2,000,000	3,900,000
Net deferred premiums payable related to commodity derivative contracts - non current assets	700,000	2,500,000
Net deferred premiums payable related to commodity derivative contracts - current liabilities	4,400,000	6,200,000
Net deferred premiums payable related to commodity derivative contracts - non current liabilities	2,100,000	600,000
Derivatives not designated as hedging instruments: \| Commodity \| Oil and gas revenue
Derivative instruments, Balance Sheet Location
Derivatives liabilities—current	0	(30,900)
Derivatives not designated as hedging instruments: \| Interest rate
Derivative instruments, Balance Sheet Location
Derivatives assets—current	389,000	0
Derivatives assets—long-term	305,000	582,000
Derivatives liabilities—current	$ 0	$ (529,000)

Derivative Financial Instruments - Schedule of derivative instruments by location of gain/(loss) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	$ (33,021)	$ 17,995	$ 25,924	$ (37,179)
Commodity \| Oil and gas revenue
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	(6,221)	344	(10,781)	(712)
Commodity \| Derivatives, net
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	(26,864)	16,891	36,404	(33,752)
Interest rate \| Interest expense
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss)	$ 64	$ 760	$ 301	$ (2,715)

Fair Value Measurements (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Carrying Value
Liabilities:
Long-term debt	$ 1,106,594	$ 1,353,716
Fair Value
Liabilities:
Long-term debt	1,145,874	1,378,938
Senior Notes \| Carrying Value
Liabilities:
Long-term debt	506,594	503,716
Senior Notes \| Fair Value
Liabilities:
Long-term debt	545,874	528,938
Facility \| Carrying Value
Liabilities:
Long-term debt	600,000	850,000
Facility \| Fair Value
Liabilities:
Long-term debt	600,000	850,000
Recurring basis
Liabilities:
Total fair value, net	2,340	1,691
Recurring basis \| Commodity
Assets:
Derivative asset, fair value	17,918	34,924
Liabilities:
Derivative liability, fair value	(16,272)	(33,286)
Recurring basis \| Interest rate
Assets:
Derivative asset, fair value	694	582
Liabilities:
Derivative liability, fair value	0	(529)
Recurring basis \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Total fair value, net	0	0
Recurring basis \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Commodity
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Interest rate
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis \| Significant Other Observable Inputs (Level 2)
Liabilities:
Total fair value, net	2,340	1,691
Recurring basis \| Significant Other Observable Inputs (Level 2) \| Commodity
Assets:
Derivative asset, fair value	17,918	34,924
Liabilities:
Derivative liability, fair value	(16,272)	(33,286)
Recurring basis \| Significant Other Observable Inputs (Level 2) \| Interest rate
Assets:
Derivative asset, fair value	694	582
Liabilities:
Derivative liability, fair value	0	(529)
Recurring basis \| Significant Unobservable Inputs (Level 3)
Liabilities:
Total fair value, net	0	0
Recurring basis \| Significant Unobservable Inputs (Level 3) \| Commodity
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	0	0
Recurring basis \| Significant Unobservable Inputs (Level 3) \| Interest rate
Assets:
Derivative asset, fair value	0	0
Liabilities:
Derivative liability, fair value	$ 0	$ 0

Equity-based Compensation - Additional Information (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			3 years
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			4 years
Restricted Stock Awards and Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense not yet recognized	$ 33.5		$ 33.5
Weighted average period over which compensation expense is to be recognized			1 year 5 months 23 days
LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recognized	9.6	$ 9.2	$ 29.9	$ 30.4
Tax benefit	3.2	3.0	9.9	9.9
Net tax shortfall related to equity-based compensation	0.2	1.0	3.1	5.3
Fair value of awards vested	$ 1.4	$ 2.4	$ 20.7	$ 13.4
Number of shares remaining available for grant	3.4		3.4
LTIP \| Market/Service Vesting Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant date fair value of awards granted (in dollars per share)			$ 9.50
LTIP \| Market/Service Vesting Restricted Stock Units \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant date fair value of awards granted (in dollars per share)			$ 4.83
Expected volatility			44.00%
Risk-free interest rate			0.50%
LTIP \| Market/Service Vesting Restricted Stock Units \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the awards granted (up to)			200.00%
Grant date fair value of awards granted (in dollars per share)			$ 15.81
Expected volatility			54.00%
Risk-free interest rate			1.40%
LTIP \| Market/Service Vesting Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant date fair value of awards granted (in dollars per share)			$ 9.45
Expected volatility			55.00%
Risk-free interest rate			0.50%
LTIP \| Market/Service Vesting Restricted Stock Awards \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage of the awards granted (up to)			100.00%

Equity-based Compensation - Schedule of awards (Details) - LTIP shares in Thousands	9 Months Ended
	Sep. 30, 2017 $ / shares shares
Service Vesting Restricted Stock Awards
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares) \| shares	488
Granted (in shares) \| shares	0
Forfeited (in shares) \| shares	0
Vested (in shares) \| shares	(268)
Outstanding at the end of the period (in shares) \| shares	220
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 8.83
Granted (in dollars per share)	0.00
Forfeited (in dollars per share)	0.00
Vested (in dollars per share)	8.97
Outstanding at the end of the period (in dollars per share)	$ 8.64
Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares) \| shares	4,160
Granted (in shares) \| shares	2,063
Forfeited (in shares) \| shares	(123)
Vested (in shares) \| shares	(1,864)
Outstanding at the end of the period (in shares) \| shares	4,236
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)	$ 6.91
Granted (in dollars per share)	6.41
Forfeited (in dollars per share)	7.03
Vested (in dollars per share)	7.50
Outstanding at the end of the period (in dollars per share)	$ 6.40
Market/Service Vesting Restricted Stock Units
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares) \| shares	7,194
Granted (in shares) \| shares	2,170
Forfeited (in shares) \| shares	(27)
Vested (in shares) \| shares	(894)
Outstanding at the end of the period (in shares) \| shares	8,443
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)	7.76
Vested (in dollars per share)	15.44
Outstanding at the end of the period (in dollars per share)	11.26
Market/Service Vesting Restricted Stock Units \| Maximum
Weighted-Average Grant-Date Fair Value
Granted (in dollars per share)	$ 15.81

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
Income Taxes (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Taxes
Effective tax rate (as a percent)	2.00%	14.00%	79.00%	4.00%
Income (loss) before income taxes	$ (64,920)	$ (52,261)	$ (56,312)	$ (237,144)
Bermuda
Income Taxes
Income (loss) before income taxes	(17,740)	(15,989)	(50,680)	(47,212)
United States
Income Taxes
Income (loss) before income taxes	1,437	1,132	$ 4,231	5,447
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	$ (48,617)	$ (37,404)	$ (9,863)	$ (195,379)

Net Loss Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Numerator:
Net loss	$ (63,405)	$ (59,763)	$ (100,713)	$ (227,080)
Basic income allocable to participating securities	0	0	0	0
Basic net loss allocable to common shareholders	(63,405)	(59,763)	(100,713)	(227,080)
Diluted adjustments to income allocable to participating securities	0	0	0	0
Diluted net loss allocable to common shareholders	$ (63,405)	$ (59,763)	$ (100,713)	$ (227,080)
Weighted average number of shares outstanding:
Basic (in shares)	389,058,000	386,026,000	388,114,000	385,130,000
Restricted stock awards and units (in shares)	0	0	0	0
Diluted (in shares)	389,058,000	386,026,000	388,114,000	385,130,000
Net loss per share:
Basic (in dollars per share)	$ (0.16)	$ (0.15)	$ (0.26)	$ (0.59)
Diluted (in dollars per share)	$ (0.16)	$ (0.15)	$ (0.26)	$ (0.59)
Outstanding restricted stock awards and units excluded from the computations of diluted net income per share (in shares)	12,900,000	12,000,000	12,900,000	12,000,000

Commitments and Contingencies (Details) $ in Thousands	1 Months Ended	3 Months Ended	9 Months Ended
Commitments and Contingencies (Details) $ in Thousands	Jan. 31, 2017 USD ($)	Mar. 31, 2017 USD ($)	Sep. 30, 2017 USD ($) km² exploration_well
Operating leases
Future minimum rental commitments
Total			$ 9,910
2017			1,158
2018			4,736
2019			3,951
2020			65
2021			0
Thereafter			0
ENSCO DS-12 drilling rig contract
Future minimum rental commitments
Total			25,585
2017			25,585
2018			0
2019			0
2020			0
2021			0
Thereafter			0
Kosmos Energy Ventures \| ENSCO DS-12 drilling rig contract
Commitments and contingencies
Rig rate per day - subsidiary's revert option	$ 600
Recovery payment for reverting the rig rate back to original day rate		$ 48,100
Mauritania And Senegal Offshore Block \| Maximum
Commitments and contingencies
Spending by third party for exploration and appraisal costs			$ 228,000
Equatorial Guinea
Commitments and contingencies
3 D seismic requirements (in square kilometers) \| km²			6,000
Mauritania
Commitments and contingencies
Number of exploration wells \| exploration_well			2
3 D seismic requirements (in square kilometers) \| km²			7,600
Western Sahara
Commitments and contingencies
3 D seismic requirements (in square kilometers) \| km²			5,000

Additional Financial Information (Details) - USD ($)	3 Months Ended		9 Months Ended
Additional Financial Information (Details) - USD ($)	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Accrued liabilities:
Exploration, development and production	$ 130,543,000		$ 130,543,000		$ 76,194,000
General and administrative expenses	26,823,000		26,823,000		31,243,000
Interest	9,180,000		9,180,000		17,247,000
Income taxes	3,145,000		3,145,000		2,579,000
Taxes other than income	3,941,000		3,941,000		1,914,000
Other	172,000		172,000		529,000
Accrued liabilities	173,804,000		173,804,000		$ 129,706,000
Other income, net	0	$ 0	58,700,000	$ 20,000,000
Other Expenses, Net
Inventory write-off	(500,000)	0	47,000	15,177,000
(Gain) loss on insurance settlements	0	(3,047,000)	(461,000)	(4,003,000)
Disputed charges and related costs	821,000	1,826,000	3,260,000	1,826,000
Loss on equity method investment	4,804,000	0	11,230,000	0
Other, net	(88,000)	426,000	157,000	768,000
Other expenses, net	5,037,000	(795,000)	14,233,000	13,768,000
Oil and gas production expense
Accrued liabilities:
Insurance recoveries	$ 0	$ 0	$ 17,100,000	$ 0

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Statement of Cash Flows [Abstract]
Cash settlements on derivatives, net (commodity hedges)	$ 36.4	$ 146.5

Organization (Details)	9 Months Ended
Organization (Details)	Sep. 30, 2017 segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of reportable segments	1