Kosmos Energy (KOS) 10-Q 7 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Nov. 01, 2016
Document and Entity Information
Entity Registrant Name	Kosmos Energy Ltd.
Entity Central Index Key	1,509,991
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
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		386,701,970
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 109,040	$ 275,004
Restricted cash	25,588	28,533
Receivables:
Joint interest billings	52,042	67,200
Oil sales		35,950
Other	39,833	34,882
Inventories	82,062	85,173
Prepaid expenses and other	9,602	24,766
Derivatives	68,434	182,640
Total current assets	386,601	734,148
Property and equipment:
Oil and gas properties, net	2,750,203	2,314,226
Other property, net	8,015	8,613
Property and equipment, net	2,758,218	2,322,839
Other assets:
Restricted cash	51,632	7,325
Long-term receivables - joint interest billings	45,998	37,687
Deferred financing costs, net of accumulated amortization of $10,528 and $8,475 at September 30, 2016 and December 31, 2015, respectively	5,933	7,986
Long-term deferred tax assets	32,605	33,209
Derivatives	12,493	59,856
Other	8,337
Total assets	3,301,817	3,203,050
Current liabilities:
Accounts payable	173,972	295,689
Accrued liabilities	100,430	159,897
Derivatives	8,055	1,155
Total current liabilities	282,457	456,741
Long-term liabilities:
Long-term debt	1,319,094	860,878
Derivatives	17,428	4,196
Asset retirement obligations	61,163	43,938
Deferred tax liabilities	483,740	502,189
Other long-term liabilities	9,689	9,595
Total long-term liabilities	1,891,114	1,420,796
Shareholders' equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2016 and December 31, 2015
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 395,743,005 and 393,902,643 issued at September 30, 2016 and December 31, 2015, respectively	3,957	3,939
Additional paid-in capital	1,965,596	1,933,189
Accumulated deficit	(793,710)	(564,686)
Treasury stock, at cost, 9,101,395 and 8,812,054 shares at September 30, 2016 and December 31, 2015, respectively	(47,597)	(46,929)
Total shareholders' equity	1,128,246	1,325,513
Total liabilities and shareholders' equity	$ 3,301,817	$ 3,203,050

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
CONSOLIDATED BALANCE SHEETS
Deferred financing costs, accumulated amortization (in dollars)	$ 10,528	$ 8,475
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	395,743,005	393,902,643
Treasury stock shares	9,101,395	8,812,054

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues and other income:
Oil and gas revenue	$ 46,628	$ 96,584	$ 154,259	$ 324,948
Gain on sale of assets				24,651
Other income	20,001	(1,266)	20,179	89
Total revenues and other income	66,629	95,318	174,438	349,688
Costs and expenses:
Oil and gas production	13,574	23,157	75,647	75,481
Facilities insurance modifications	5,946		5,946
Exploration expenses	66,238	18,904	126,498	132,384
General and administrative	21,914	26,692	59,672	106,538
Depletion and depreciation	17,838	35,995	66,031	110,534
Interest and other financing costs, net	11,066	9,926	30,268	29,675
Derivatives, net	(16,891)	(142,129)	33,752	(129,579)
Other expenses, net	(795)	290	13,768	5,184
Total costs and expenses	118,890	(27,165)	411,582	330,217
Income (Loss) before income taxes	(52,261)	122,483	(237,144)	19,471
Income tax expense (benefit)	7,502	62,218	(10,064)	113,307
Net income (loss)	$ (59,763)	$ 60,265	$ (227,080)	$ (93,836)
Net income (loss) per share:
Basic (in dollars per share)	$ (0.15)	$ 0.16	$ (0.59)	$ (0.25)
Diluted (in dollars per share)	$ (0.15)	$ 0.15	$ (0.59)	$ (0.25)
Weighted average number of shares used to compute net income (loss) per share:
Basic (in shares)	386,026	383,924	385,130	382,603
Diluted (in shares)	386,026	390,586	385,130	382,603

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Net income (loss)	$ (59,763)	$ 60,265	$ (227,080)	$ (93,836)
Other comprehensive loss:
Reclassification adjustments for derivative gains included in net income (loss)	0	(378)	0	(767)
Other comprehensive loss		(378)		(767)
Comprehensive income (loss)	$ (59,763)	$ 59,887	$ (227,080)	$ (94,603)

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - 9 months ended Sep. 30, 2016 - USD ($) shares in Thousands, $ in Thousands	Common Shares	Additional Paid-in Capital	Accumulated Deficit	Treasury Stock	Total
Balance at Dec. 31, 2015	$ 3,939	$ 1,933,189	$ (564,686)	$ (46,929)	$ 1,325,513
Balance (in shares) at Dec. 31, 2015	393,903
Increase (Decrease) in Shareholders' Equity
Equity-based compensation		33,687	(1,944)		31,743
Restricted stock awards and units	$ 18	(18)
Restricted stock awards and units (in shares)	1,840
Restricted stock forfeitures		2		(2)
Purchase of treasury stock		(1,264)		(666)	(1,930)
Net loss			(227,080)		(227,080)
Balance at Sep. 30, 2016	$ 3,957	$ 1,965,596	$ (793,710)	$ (47,597)	$ 1,128,246
Balance (in shares) at Sep. 30, 2016	395,743

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating activities
Net income (loss)	$ (227,080)	$ (93,836)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	73,684	118,307
Deferred income taxes	(16,821)	77,229
Unsuccessful well costs	2,609	87,379
Change in fair value of derivatives	37,179	(127,706)
Cash settlements on derivatives, net (including $146.5 million and $154.3 million on commodity hedges during 2016 and 2015)	144,522	153,065
Equity-based compensation	30,391	62,400
Gain on sale of assets		(24,651)
Loss on extinguishment of debt		165
Other	13,358	6,731
Changes in assets and liabilities:
Decrease in receivables	29,833	17,548
Increase in inventories	(12,066)	(21,059)
(Increase) decrease in prepaid expenses and other	15,164	(7,458)
Increase (decrease) in accounts payable	(122,142)	74,936
Decrease in accrued liabilities	(34,254)	(50,571)
Net cash provided by (used in) operating activities	(65,623)	272,479
Investing activities
Oil and gas assets	(506,256)	(559,342)
Other property	(1,003)	(793)
Proceeds on sale of assets	210	28,692
Restricted cash	(41,362)	(9,594)
Net cash used in investing activities	(548,411)	(541,037)
Financing activities
Borrowings under long-term debt	450,000	100,000
Payments on long-term debt		(200,000)
Net proceeds from issuance of senior secured notes		206,774
Purchase of treasury stock	(1,930)	(17,981)
Deferred financing costs		(9,031)
Net cash provided by financing activities	448,070	79,762
Net decrease in cash and cash equivalents	(165,964)	(188,796)
Cash and cash equivalents at beginning of period	275,004	554,831
Cash and cash equivalents at end of period	109,040	366,035
Cash paid for:
Interest	25,540	39,341
Income taxes	6,997	$ 28,744
Non-cash activities:
Conversion of joint interest billings receivable to long-term note receivable	$ 8,124

CONSOLIDATED STATEMENTS OF CAS8

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash settlements on derivatives, net (including $146.5 million and $154.3 million on commodity hedges during 2016 and 2015)	$ 146.5	$ 154.3

Organization

Organization	9 Months Ended
	Sep. 30, 2016
Organization
Organization	1. Organization Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise. Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margin. Our assets include existing production and development projects offshore Ghana, large discoveries offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Portugal, Sao Tome and Principe, Suriname, Morocco and Western Sahara. Kosmos is listed on the New York Stock Exchange and is traded under the ticker symbol KOS. We have one reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are currently related to production located offshore Ghana.

Accounting Policies

Accounting Policies	9 Months Ended
	Sep. 30, 2016
Accounting Policies
Accounting Policies	2. Accounting Policies General The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of September 30, 2016, the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2016, the consolidated results of operations for the three and nine months ended September 30, 2016 and 2015, and the consolidated cash flows for the nine months ended September 30, 2016 and 2015. 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, 2015, included in our annual report on Form 10-K. Reclassifications Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows. Restricted Cash 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, 2016 and December 31, 2015, we had $24.5 million and $24.4 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, 2016 and December 31, 2015, we had $1.1 million and $4.1 million, respectively, of current restricted cash and $51.6 million and $7.3 million, respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts. Inventories Inventories consisted of $65.0 million and $84.4 million of materials and supplies and $17.1 million and $0.8 million of hydrocarbons as of September 30, 2016 and December 31, 2015, 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 a write down of zero and $15.2 million during the three and nine months ended September 30, 2016 for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs. Recent Accounting Standards In July 2015, the FASB issued ASU 2015-11, “Inventory (Topic 330) — Simplifying the Measurement of Inventory.” ASU 2015-11 changes the measurement principle for entities that do not measure inventory using the last-in, first-out (LIFO) or retail inventory method from the lower of cost or market to lower of cost and net realizable value. The ASU also eliminates the requirement for these entities to consider replacement cost or net realizable value less an approximately normal profit margin when measuring inventory. The standard requires prospective application upon adoption. The Company has elected to early adopt ASU 2015-11 during the first quarter of 2016. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements. The Company adopted ASU 2016-09, “Improvements to Employee Share-based Payment Accounting” during the second quarter using an effective date of January 1, 2016. The change in accounting for forfeitures associated with share-based payment transactions was adopted using the modified retrospective method and resulted in a $1.9 million increase to opening accumulated deficit, a $3.0 million increase to opening additional paid-in capital and a $1.1 million increase to opening long-term deferred tax assets in the consolidated balance sheets. The changes in accounting for the recognition of excess tax benefits and tax shortfalls were adopted prospectively. In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230) — Classification of Certain Cash Receipts and Cash Payments.” ASU 2016-15 clarifies current GAAP or provides specific guidance on eight cash flow classification issues to reduce current and potential future diversity in practice. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements. In October 2016, the FASB issued ASU 2016-16, “Income Taxes (Topic 740) — Intra-Entity Transfers of Assets Other Than Inventory.” ASU 2016-16 requires the company to recognize income tax consequences, if any, on intercompany asset transfers, other than inventory, when the transfer occurs. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements.

Acquisitions and Divestitures

Acquisitions and Divestitures	9 Months Ended
	Sep. 30, 2016
Acquisitions and Divestitures
Acquisitions and Divestitures	3. Acquisitions and Divestitures In January and February 2016, we entered into farm-in agreements with Equator Exploration STP Block 5 Limited and Equator Exploration STP Block 12 Limited, affiliates of Oando Energy Resources, for Block 5 and Block 12, respectively, offshore Sao Tome and Principe, and whereby we acquired a 65% participating interest and operatorship in each block, effective as of February and March 2016, respectively. The national petroleum agency, Agencia Nacional do Petroleo de Sao Tome and Principe (“ANP STP”), has a 15% and 12.5% carried interest in Block 5 and Block 12, respectively. In April 2016, we entered into a farm-out agreement with Hess Suriname Exploration Limited, a wholly-owned subsidiary of the Hess Corporation (“Hess”), covering the Block 42 contract area offshore Suriname. Under the terms of the agreement, Hess acquired a one-third non-operated interest in Block 42 from both Chevron Corporation (“Chevron”) and Kosmos. As part of the agreement, Hess is funding the cost of acquiring and processing a 6,500 square kilometer 3D seismic survey, subject to a maximum spend. Additionally, Hess will disproportionately fund a portion of the first exploration well in the Block 42 contract area, subject to a maximum spend, contingent upon the partnership entering the next phase of the exploration period. The new participating interests are one-third to each of Kosmos, Chevron and Hess, respectively. Kosmos remains the operator. Staatsolie Maatschappij Suriname N.V. (“Staatsolie”), Suriname’s national oil company, has the option to back into the contract with an interest of not more than 10% upon approval of a development plan. In May 2016, Kosmos and Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”) executed a petroleum agreement with the Office National des Hydrocarbures et des Mines ("ONHYM"), the national oil company of the Kingdom of Morocco, for the Boujdour Maritime block. The Boujdour Maritime petroleum agreement largely replaces the acreage covered by the Cap Boujdour petroleum agreement which expired in March 2016. Under the terms of the petroleum agreement, Kosmos is the operator of the Boujdour Maritime block and has a 55% participating interest, Cairn has a 20% participating interest, and ONHYM holds a 25% carried interest in the block through the exploration period. The Boujdour Maritime block is currently in the initial exploration period, which is for four years from its effective date (July 18, 2016) ending in July 2020. The initial exploration period carries a 3D seismic obligation of 5,000 square kilometers. The exploration phase may be extended twice for two years each, for a total duration of eight years at our election and subject to our fulfilling specific work obligations, which includes drilling an exploration well in each of the subsequent periods. In the event of commercial success, the Company has the right to develop and produce oil and/or gas for a period of 25 years from the grant of an exploitation concession from the Government of Morocco, which may be extended for an additional period of 10 years under certain circumstances. In October 2016, we entered into a petroleum contract covering Block C6 with the Islamic Republic of Mauritania. We have a 90% interest and are the operator. The Mauritanian national oil company, Societe Mauritanienne des Hydrocarbures et de Patrimoine Minier (“SMHPM”), currently has a 10% carried participating interest during the exploration period. Should a commercial discovery be made, SMHPM’s 10% carried interest is extinguished and SMHPM will have an option to acquire a participating interest between 10% and 18%. SMHPM will pay its portion of development and production costs in a commercial development. Block C6 currently comprises approximately 1.1 million acres (4,300 square kilometers), with a first exploration period of four years from the effective date (October 28, 2016). The first exploration phase includes a 2,000 square kilometer 3D seismic requirement.

Joint Interest Billings

Joint Interest Billings	9 Months Ended
	Sep. 30, 2016
Joint Interest Billings
Joint Interest Billings	4. Joint Interest Billings The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur. In 2014, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners that it would exercise its right for the contractor group to pay its 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, 2016 and December 31, 2015, the joint interest billing receivables due from GNPC for the TEN development costs were $44.0 million and $35.3 million, respectively, which are classified as long-term on the consolidated balance sheets.

Property and Equipment

Property and Equipment	9 Months Ended
	Sep. 30, 2016
Property and Equipment
Property and Equipment	5. Property and Equipment Property and equipment is stated at cost and consisted of the following: September 30, December 31, 2016 2015 (In thousands) Oil and gas properties: Proved properties $ $ Unproved properties Support equipment and facilities Total oil and gas properties Accumulated depletion Oil and gas properties, net Other property Accumulated depreciation Other property, net Property and equipment, net $ $ We recorded depletion expense of $15.6 million and $33.6 million for the three months ended September 30, 2016 and 2015, respectively, and $59.6 million and $103.4 million for the nine months ended September 30, 2016 and 2015, respectively.

Suspended Well Costs

Suspended Well Costs	9 Months Ended
	Sep. 30, 2016
Suspended Well Costs
Suspended Well Costs	6. Suspended Well Costs The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the nine months ended September 30, 2016. The table excludes $2.6 million in costs that were capitalized and subsequently expensed during the same period. September 30, 2016 (In thousands) Beginning balance $ Additions to capitalized exploratory well costs pending the determination of proved reserves Reclassification due to determination of proved reserves — Capitalized exploratory well costs charged to expense — Ending balance $ 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, 2016 December 31, 2015 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ $ Exploratory well costs capitalized for a period of one to two years Exploratory well costs capitalized for a period of three to seven years Ending balance $ $ Number of projects that have exploratory well costs that have been capitalized for a period greater than one year As of September 30, 2016, 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, and the Greater Tortue discovery which crosses the Mauritania and Senegal maritime border. Mahogany and Teak Discoveries — In November 2015, we signed the Jubilee Field Unit Expansion Agreement with our partners to allow for the development of the Mahogany and Teak discoveries through the Jubilee FPSO and infrastructure. The expansion of the Jubilee Unit becomes effective upon approval by Ghana’s Ministry of Petroleum of the Greater Jubilee Full Field Development Plan (“GJFFDP”), which was submitted to the government of Ghana in December 2015. The GJFFDP encompasses future development of the Jubilee Field, in addition to future development of the Mahogany and Teak discoveries, which were declared commercial during 2015. We are currently in discussions with the government of Ghana concerning the GJFFDP. Upon approval of the GJFFDP by the Ministry of Petroleum, the Jubilee Unit will be expanded to include the Mahogany and Teak discoveries and revenues and expenses associated with these discoveries will be at the Jubilee Unit interests. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow after approval of the GJFFDP by Ghana’s Ministry of Petroleum. 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 Petroleum, 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 Petroleum. Wawa Discovery — In February 2016, we requested the Ghana Ministry of Petroleum to approve the enlargement of the areal extent of the TEN development and production area to capture the resource accumulation located in the Wawa Discovery Area for a potential future integrated development with the TEN project. In April 2016, the Ghana Ministry of Petroleum 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. 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. Following additional evaluation, a decision regarding commerciality will be made.

Debt

Debt	9 Months Ended
	Sep. 30, 2016
Debt
Debt	7. Debt September 30, December 31, 2016 2015 (In thousands) Outstanding debt principal balances: Facility $ $ Senior Notes Total Unamortized deferred financing costs and discounts(1) Long-term debt $ $ (1) Includes $32.1 million and $37.5 million of unamortized deferred financing costs related to the Facility and $23.8 million and $26.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2016 and December 31, 2015, 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 September 2016, following the lender’s semi-annual redetermination, the borrowing base under our Facility was increased from the March 2016 redetermination by $40.4 million to $1.467 billion (effective October 1, 2016). The borrowing base calculation includes value related to the Jubilee and TEN fields. As of September 30, 2016, borrowings under the Facility totaled $850.0 million and the undrawn availability under the Facility was $576.5 million (as of October 1, 2016, the availability is $616.9 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, 2016, 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, 2016 (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, 2016, we have $5.9 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term. These deferred financing costs are included in the Other assets section of the consolidated balance sheet. As of September 30, 2016, 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, 2016 (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. The LC Facility size remains at $75.0 million, as amended in July 2015, with additional commitments up to $50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. Other amendments include increasing the margin from 0.5% to 0.8% per annum on amounts outstanding, adding a commitment fee payable quarterly in arrears at an annual rate equal to 0.65% on the available commitment amount and providing for issuance fees to be payable to the lender per new issuance of a letter of credit. As of September 30, 2016, there were 11 outstanding letters of credit totaling $70.3 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, 2016, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows: Payments Due by Year Total 2016(2) 2017 2018 2019 2020 Thereafter (In thousands) Principal debt repayments(1) $ $ — $ — $ — $ $ $ (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the estimated future available borrowing base as of September 30, 2016. 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, 2016, there were no borrowings under the Corporate Revolver. (2) Represents payments for the period October 1, 2016 through December 31, 2016. 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, 2016 2015 2016 2015 (In thousands) Interest expense $ $ $ $ Amortization—deferred financing costs Loss on extinguishment of debt — — — Capitalized interest Deferred interest Interest income Other, net Interest and other financing costs, net $ $ $ $

Derivative Financial Instrument

Derivative Financial Instruments	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities
Derivative Financial Instruments	8. Derivative Financial Instruments We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes. We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820 — Fair Value Measurements and Disclosures. Oil Derivative Contracts The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of September 30, 2016. Volumes are net of any offsetting derivative contracts entered into. Weighted Average Dated Brent Price per Bbl Net Deferred Premium Term Type of Contract MBbl Payable Swap Sold Put Floor Ceiling Call 2016: October — December Purchased puts $ $ — $ — $ $ — $ — October — December Three-way collars — — — October — December Swaps with puts — — — — 2017: January — December Swap with puts/calls $ $ $ $ — $ — $ January — December Swap with puts — — — — January — December Three-way collars — — January — December Sold calls(1) — — — — — 2018: January — December Three-way collars $ $ — $ $ $ $ — January — December Sold calls(1) — — — — — 2019: January — December Sold calls(1) $ — $ — $ — $ — $ $ — (1) Represents call option contracts sold to counterparties to enhance other derivative positions. In October 2016, we entered into three-way costless collar contracts for 2.0 MMBbl from January 2018 through December 2018 with a floor price of $55.00 per barrel, and a ceiling price of $61.75 per barrel and a sold put price of $40.00 per barrel. The contracts are indexed to Dated Brent prices. Interest Rate Derivative Contracts The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of September 30, 2016: Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) October 2016 — December 2018 Capped swap 1-month LIBOR $ % % The following tables disclose the Company’s derivative instruments as of September 30, 2016 and December 31, 2015 and gain/(loss) from derivatives during the three and nine months ended September 30, 2016 and 2015, respectively: Estimated Fair Value Asset (Liability) September 30, December 31, Type of Contract Balance Sheet Location 2016 2015 (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ $ Commodity(2) Derivatives assets—long-term Interest rate Derivatives assets—long-term — Derivative liabilities: Commodity(3) Derivatives liabilities—current — Interest rate Derivatives liabilities—current Commodity(4) Derivatives liabilities—long-term Interest rate Derivatives liabilities—long-term — Total derivatives not designated as hedging instruments $ $ (1) Includes net deferred premiums payable of $4.5 million and $6.2 million related to commodity derivative contracts as of September 30, 2016 and December 31, 2015, respectively. (2) Includes net deferred premiums payable of $3.5 million and $6.9 million related to commodity derivative contracts as of September 30, 2016 and December 31, 2015, respectively. (3) Includes net deferred premiums payable of $4.6 million and zero related to commodity derivative contracts as of September 30, 2016 and December 31, 2015, respectively. (4) Includes net deferred premiums payable of $2.3 million and zero related to commodity derivative contracts as of September 30, 2016 and December 31, 2015, 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) 2016 2015 2016 2015 (In thousands) Derivatives in cash flow hedging relationships: Interest rate(1) Interest expense $ — $ $ — $ Total derivatives in cash flow hedging relationships $ — $ $ — $ Derivatives not designated as hedging instruments: Commodity(2) Oil and gas revenue $ $ $ $ Commodity Derivatives, net Interest rate Interest expense Total derivatives not designated as hedging instruments $ $ $ $ (1) Amounts were reclassified from accumulated other comprehensive income or loss (“AOCI”) into earnings upon settlement during 2015. (2) Amounts represent the change in fair value of our provisional oil sales contracts. Offsetting of Derivative Assets and Derivative Liabilities Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of September 30, 2016 and December 31, 2015, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2016
Fair Value Measurements
Fair Value Measurements	9. Fair Value Measurements In accordance with ASC Topic 820 — Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy: · Level 1 — quoted prices for identical assets or liabilities in active markets. · Level 2 — quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means. · Level 3 — unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2016 and December 31, 2015, 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, 2016 Assets: Commodity derivatives $ — $ $ — $ Interest rate derivatives — — — — Liabilities: Commodity derivatives — — Interest rate derivatives — — Total $ — $ $ — $ December 31, 2015 Assets: Commodity derivatives $ — $ $ — $ Interest rate derivatives — — Liabilities: Commodity derivatives — — Interest rate derivatives — — Total $ — $ $ — $ 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 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 The Company enters 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, 2016 and December 31, 2015: September 30, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ $ $ $ Facility Total $ $ $ $ The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.

Equity-based Compensation

Equity-based Compensation	9 Months Ended
	Sep. 30, 2016
Equity-based Compensation
Equity-based Compensation	10. Equity-based Compensation Restricted Stock Awards and Restricted Stock Units The Company adopted ASU 2016-09, “Improvements to Employee Share-based Payment Accounting” during the second quarter of 2016 using an effective date of January 1, 2016. Prior period compensation expense disclosed below includes estimated forfeitures and has not been adjusted. We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long-Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $9.2 million and $13.9 million during the three months ended September 30, 2016 and 2015, respectively, and $30.4 million and $62.4 million for the nine months ended September 30, 2016 and 2015, respectively. The total tax benefit for the three months ended September 30, 2016 and 2015 was $3.0 million and $4.7 million, respectively, and $9.9 million and $21.1 million for the nine months ended September 30, 2016 and 2015, respectively. Additionally, we expensed a tax shortfall related to equity-based compensation of $1.0 million and $0.1 million for the three months ended September 30, 2016 and 2015 respectively, and $5.3 million and $18.5 million for the nine months ended September 30, 2016 and 2015, respectively. The fair value of awards vested during the three months ended September 30, 2016 and 2015 was approximately $2.4 million and $1.0 million, respectively, and $13.4 million and $51.8 million for the nine months ended September 30, 2016 and 2015, respectively. The Company has 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 criteria under the LTIP. Substantially all these awards vest over either 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, 2016: Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Awards Fair Value Awards Fair Value (In thousands) (In thousands) Outstanding at December 31, 2015 $ $ Granted — — — — Forfeited — — Vested Outstanding at September 30, 2016 — — The following table reflects the outstanding restricted stock units as of September 30, 2016: 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, 2015 $ $ Granted Forfeited Vested Outstanding at September 30, 2016 As of September 30, 2016, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $41.0 million over a weighted average period of 1.47 years. At September 30, 2016, the Company had approximately 8.3 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 of these awards ranged from $6.70 to $13.57 per award for restricted stock awards and $4.83 to $15.81 per award for restricted stock units. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 41.3% to 56.7% for the restricted stock awards and 44.0% to 54.0% for restricted stock units. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.5% to 1.1% for restricted stock awards and 0.5% to 1.2% for restricted stock units.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2016
Income Taxes
Income Taxes	11. Income Taxes Income tax expense (benefit) was $7.5 million and $62.2 million for the three months ended September 30, 2016 and 2015, respectively, and $(10.1) million and $113.3 million for the nine months ended September 30, 2016 and 2015, respectively. The income tax provision consists of United States and Ghanaian income and Texas margin taxes. Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate or we have experienced losses in those countries and have a full valuation allowance reserved 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, 2016 2015 2016 2015 (In thousands) Bermuda $ $ $ $ United States Foreign—other Income (loss) before income taxes $ $ $ $ Our effective tax rate for the three months ended September 30, 2016 and 2015 is 14% and 51%, respectively. For the nine months ended September 30, 2016 and 2015, our effective tax rate is a tax benefit of 4% and tax expense of 582%, respectively. The effective tax rate for the United States is approximately 156% and 44% for the three months ended September 30, 2016 and 2015, respectively, and 152% and 202% for the nine months ended, September 30, 2016 and 2015, respectively. The effective tax rate in the United States is impacted by the effect of equity-based compensation tax shortfalls equal to the excess tax benefit recognized for financial statement purposes over the tax benefit realized for tax return purposes. The effective tax rate for Ghana is approximately 45% and 35% for the three months ended September 30, 2016 and 2015, respectively, and a tax benefit of 27% and tax expense of 35% for the nine months ended, September 30, 2016 and 2015, respectively. The effective tax rate in Ghana is impacted by non-deductible expenditures associated with the damage to the turret bearing which we expect to recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax. A subsidiary of the Company files a U.S. federal income tax return and a Texas margin tax return. In addition to the United States, the Company files income tax returns in the countries in which we operate. The Company is open to U.S. federal income tax examinations for tax years 2013 through 2015 and to Texas margin tax examinations for the tax years 2011 through 2015. In addition, the Company is open to income tax examinations for years 2011 through 2015 in its significant other foreign jurisdictions, primarily Ghana. As of September 30, 2016, the Company had no material uncertain tax positions. The Company’s policy is to recognize interest and penalties related to income tax matters in income tax expense.

Net Income (Loss) Per Share

Net Income (Loss) Per Share	9 Months Ended
	Sep. 30, 2016
Net Income (Loss) Per Share
Net Income (Loss) Per Share	12. Net Income (Loss) Per Share The following table is a reconciliation between net income and the amounts used to compute basic and diluted net income per share and the weighted average shares outstanding used to compute basic and diluted net income (loss) per share: Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 (In thousands, except per share data) Numerator: Net income (loss) $ $ $ $ Basic income allocable to participating securities(1) — — — Basic net income (loss) allocable to common shareholders Diluted adjustments to income allocable to participating securities(1) — — — — Diluted net income (loss) allocable to common shareholders $ $ $ $ Denominator: Weighted average number of shares outstanding: Basic Restricted stock awards and units(1)(2) — — — Diluted Net income (loss) per share: Basic $ $ $ $ Diluted $ $ $ $ (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income (loss) per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net income (loss) per common share calculation in periods we are in a net loss position. (2) We excluded outstanding restricted stock awards and units of 12.0 million and 1.8 million for the three months ended September 30, 2016 and 2015, respectively, and $12.0 million and $11.5 million for the nine months ended September 30, 2016 and 2015, respectively, from the computations of diluted net income per share because the effect would have been anti-dilutive.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies
Commitments and Contingencies	13. Commitments and Contingencies From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year. As of September 30, 2016, we had a commitment to drill one exploration well in Morocco and two exploration wells in Mauritania. In Morocco, our partner is obligated to fund our share of the cost of the exploration well, subject to a maximum spend of $120.0 million. Additionally, in Sao Tome and Principe we have 2D and 3D seismic requirements of 1,200 square kilometers and 4,000 square kilometers, respectively, and we have 3D seismic requirements in Mauritania and Western Sahara of 1,000 square kilometers and 5,000 square kilometers, respectively. In October 2016, we entered into a new petroleum contract for Block C6 in Mauritania which includes a 3D seismic requirement of 2,000 square kilometers. In June 2013, Kosmos Energy Ventures (“KEV”), a subsidiary of Kosmos Energy Ltd., signed a long-term rig agreement with a subsidiary of Atwood Oceanics, Inc. for the new build 6th generation drillship “Atwood Achiever.” KEV took delivery of the Atwood Achiever in September 2014. The rig agreement originally covered an initial period of three years at a day rate of approximately $0.6 million, with an option to extend the agreement for an additional three year term. In September 2015, KEV amended the rig agreement effective October 1, 2015 to extend the contract end date by one year and reduce the rate to approximately $0.5 million per day. KEV has the option to revert to the original day rate of approximately $0.6 million per day and original agreement end date of November 2017. If KEV exercises the option, KEV would be required to make a rate recovery payment equal to 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 option is exercised plus certain administrative and tax costs. In November 2015, we entered into a line of credit agreement with one of our block partners, whereby our partner may draw up to $30 million on the line of credit to pay their portion of costs under the petroleum agreement. Interest accrues on drawn balances at 7.875%. The agreement matures on December 31, 2017, or earlier if certain conditions are met. As of September 30, 2016, there was $8.3 million outstanding under the agreement, which is included in other long-term assets. Future minimum rental commitments under our leases at September 30, 2016, are as follows: Payments Due By Year(1) Total 2016(2) 2017 2018 2019 2020 Thereafter (In thousands) Operating leases(3) $ $ $ $ $ $ — $ — Atwood Achiever drilling rig contract(4) — — — (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 and seismic obligations, in our petroleum contracts. (2) Represents payments for the period from October 1, 2016 through December 31, 2016. (3) Primarily relates to corporate office and foreign office leases. (4) Commitments calculated using the amended day rate of $0.5 million effective October 1, 2015, excluding applicable taxes.

Additional Financial Informatio

Additional Financial Information	9 Months Ended
	Sep. 30, 2016
Additional Financial Information
Additional Financial Information	14. Additional Financial Information Accrued Liabilities Accrued liabilities consisted of the following: September 30, December 31, 2016 2015 (In thousands) Accrued liabilities: Exploration, development and production $ $ General and administrative expenses Interest Income taxes Taxes other than income Other — $ $ Asset Retirement Obligations The following table summarizes the changes in the Company’s asset retirement obligations: September 30, 2016 (In thousands) Asset retirement obligations: Beginning asset retirement obligations $ Liabilities incurred during period Revisions in estimated retirement obligations — Accretion expense Ending asset retirement obligations $ The TEN Field commenced production during the quarter and an asset retirement obligation was recorded for the facilities and wells online as of September 30, 2016. Additional asset retirement obligations will be recorded in the period in which additional wells within our producing fields are commissioned. Other Income Other income consisted of $20.0 million of Loss of Production Income (“LOPI”) proceeds for the three and nine months ended September 30, 2016. Facilities Insurance Modifications Facilities insurance modifications consists of costs associated with the long-term solution to the turret bearing issue which we expect to be mitigated through proceeds received from our insurance policy. Insurance reimbursement of these costs, if any, will also be recorded to this line. 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, 2016 2015 2016 2015 (In thousands) Inventory write-off — — — (Gain) loss on insurance settlements — Other, net Other expenses, net $ $ $ $

Accounting Policies (Policies)

Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2016
Accounting Policies
General	General The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of September 30, 2016, the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2016, the consolidated results of operations for the three and nine months ended September 30, 2016 and 2015, and the consolidated cash flows for the nine months ended September 30, 2016 and 2015. 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, 2015, included in our annual report on Form 10-K.
Reclassifications	Reclassifications Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows.
Restricted Cash	Restricted Cash 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, 2016 and December 31, 2015, we had $24.5 million and $24.4 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, 2016 and December 31, 2015, we had $1.1 million and $4.1 million, respectively, of current restricted cash and $51.6 million and $7.3 million, respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts.
Inventories	Inventories Inventories consisted of $65.0 million and $84.4 million of materials and supplies and $17.1 million and $0.8 million of hydrocarbons as of September 30, 2016 and December 31, 2015, 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 a write down of zero and $15.2 million during the three and nine months ended September 30, 2016 for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.
Recent Accounting Standards	Recent Accounting Standards In July 2015, the FASB issued ASU 2015-11, “Inventory (Topic 330) — Simplifying the Measurement of Inventory.” ASU 2015-11 changes the measurement principle for entities that do not measure inventory using the last-in, first-out (LIFO) or retail inventory method from the lower of cost or market to lower of cost and net realizable value. The ASU also eliminates the requirement for these entities to consider replacement cost or net realizable value less an approximately normal profit margin when measuring inventory. The standard requires prospective application upon adoption. The Company has elected to early adopt ASU 2015-11 during the first quarter of 2016. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements. The Company adopted ASU 2016-09, “Improvements to Employee Share-based Payment Accounting” during the second quarter using an effective date of January 1, 2016. The change in accounting for forfeitures associated with share-based payment transactions was adopted using the modified retrospective method and resulted in a $1.9 million increase to opening accumulated deficit, a $3.0 million increase to opening additional paid-in capital and a $1.1 million increase to opening long-term deferred tax assets in the consolidated balance sheets. The changes in accounting for the recognition of excess tax benefits and tax shortfalls were adopted prospectively. In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230) — Classification of Certain Cash Receipts and Cash Payments.” ASU 2016-15 clarifies current GAAP or provides specific guidance on eight cash flow classification issues to reduce current and potential future diversity in practice. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements. In October 2016, the FASB issued ASU 2016-16, “Income Taxes (Topic 740) — Intra-Entity Transfers of Assets Other Than Inventory.” ASU 2016-16 requires the company to recognize income tax consequences, if any, on intercompany asset transfers, other than inventory, when the transfer occurs. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements.

Property and Equipment (Tables)

Property and Equipment (Tables)	9 Months Ended
	Sep. 30, 2016
Property and Equipment
Schedule of property and equipment	September 30, December 31, 2016 2015 (In thousands) Oil and gas properties: Proved properties $ $ Unproved properties Support equipment and facilities Total oil and gas properties Accumulated depletion Oil and gas properties, net Other property Accumulated depreciation Other property, net Property and equipment, net $ $

Suspended Well Costs (Tables)

Suspended Well Costs (Tables)	9 Months Ended
	Sep. 30, 2016
Suspended Well Costs
Schedule of capitalized exploratory well costs	September 30, 2016 (In thousands) Beginning balance $ Additions to capitalized exploratory well costs pending the determination of proved reserves Reclassification due to determination of proved reserves — Capitalized exploratory well costs charged to expense — Ending balance $
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, 2016 December 31, 2015 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ $ Exploratory well costs capitalized for a period of one to two years Exploratory well costs capitalized for a period of three to seven years Ending balance $ $ Number of projects that have exploratory well costs that have been capitalized for a period greater than one year

Debt (Tables)

Debt (Tables)	9 Months Ended
	Sep. 30, 2016
Debt
Schedule of debt	September 30, December 31, 2016 2015 (In thousands) Outstanding debt principal balances: Facility $ $ Senior Notes Total Unamortized deferred financing costs and discounts(1) Long-term debt $ $ (1) Includes $32.1 million and $37.5 million of unamortized deferred financing costs related to the Facility and $23.8 million and $26.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2016 and December 31, 2015, respectively.
Schedule of estimated repayments of debt	Payments Due by Year Total 2016(2) 2017 2018 2019 2020 Thereafter (In thousands) Principal debt repayments(1) $ $ — $ — $ — $ $ $ (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the estimated future available borrowing base as of September 30, 2016. 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, 2016, there were no borrowings under the Corporate Revolver. (2) Represents payments for the period October 1, 2016 through December 31, 2016.
Schedule of interest and other financing costs, net	Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (In thousands) Interest expense $ $ $ $ Amortization—deferred financing costs Loss on extinguishment of debt — — — Capitalized interest Deferred interest Interest income Other, net Interest and other financing costs, net $ $ $ $

Derivative Financial Instrume27

Derivative Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities
Schedule of oil derivative contracts	Weighted Average Dated Brent Price per Bbl Net Deferred Premium Term Type of Contract MBbl Payable Swap Sold Put Floor Ceiling Call 2016: October — December Purchased puts $ $ — $ — $ $ — $ — October — December Three-way collars — — — October — December Swaps with puts — — — — 2017: January — December Swap with puts/calls $ $ $ $ — $ — $ January — December Swap with puts — — — — January — December Three-way collars — — January — December Sold calls(1) — — — — — 2018: January — December Three-way collars $ $ — $ $ $ $ — January — December Sold calls(1) — — — — — 2019: January — December Sold calls(1) $ — $ — $ — $ — $ $ — (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 2016 — December 2018 Capped swap 1-month LIBOR $ % %
Schedule of derivative instruments by balance sheet location	Estimated Fair Value Asset (Liability) September 30, December 31, Type of Contract Balance Sheet Location 2016 2015 (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ $ Commodity(2) Derivatives assets—long-term Interest rate Derivatives assets—long-term — Derivative liabilities: Commodity(3) Derivatives liabilities—current — Interest rate Derivatives liabilities—current Commodity(4) Derivatives liabilities—long-term Interest rate Derivatives liabilities—long-term — Total derivatives not designated as hedging instruments $ $ (1) Includes net deferred premiums payable of $4.5 million and $6.2 million related to commodity derivative contracts as of September 30, 2016 and December 31, 2015, respectively. (2) Includes net deferred premiums payable of $3.5 million and $6.9 million related to commodity derivative contracts as of September 30, 2016 and December 31, 2015, respectively. (3) Includes net deferred premiums payable of $4.6 million and zero related to commodity derivative contracts as of September 30, 2016 and December 31, 2015, respectively. (4) Includes net deferred premiums payable of $2.3 million and zero related to commodity derivative contracts as of September 30, 2016 and December 31, 2015, 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) 2016 2015 2016 2015 (In thousands) Derivatives in cash flow hedging relationships: Interest rate(1) Interest expense $ — $ $ — $ Total derivatives in cash flow hedging relationships $ — $ $ — $ Derivatives not designated as hedging instruments: Commodity(2) Oil and gas revenue $ $ $ $ Commodity Derivatives, net Interest rate Interest expense Total derivatives not designated as hedging instruments $ $ $ $ (1) Amounts were reclassified from accumulated other comprehensive income or loss (“AOCI”) into earnings upon settlement during 2015. (2) Amounts represent the change in fair value of our provisional oil sales contracts.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2016
Fair Value Measurements
Schedule of Company's assets and liabilities that are measured at fair value on a recurring basis	Fair Value Measurements Using: Quoted Prices in Active Markets for Significant Other Significant Identical Assets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) September 30, 2016 Assets: Commodity derivatives $ — $ $ — $ Interest rate derivatives — — — — Liabilities: Commodity derivatives — — Interest rate derivatives — — Total $ — $ $ — $ December 31, 2015 Assets: Commodity derivatives $ — $ $ — $ Interest rate derivatives — — Liabilities: Commodity derivatives — — Interest rate derivatives — — Total $ — $ $ — $
Schedule of carrying values and fair values of financial instruments that are not carried at fair value	September 30, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ $ $ $ Facility Total $ $ $ $

Equity-based Compensation (Tabl

Equity-based Compensation (Tables)	9 Months Ended
	Sep. 30, 2016
Restricted stock awards
Equity-based Compensation
Schedule of plan activity	Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Awards Fair Value Awards Fair Value (In thousands) (In thousands) Outstanding at December 31, 2015 $ $ Granted — — — — Forfeited — — Vested Outstanding at September 30, 2016 — —
Restricted stock units
Equity-based Compensation
Schedule of plan activity	Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Units Fair Value Units Fair Value (In thousands) (In thousands) Outstanding at December 31, 2015 $ $ Granted Forfeited Vested Outstanding at September 30, 2016

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2016
Income Taxes
Schedule of components of income (loss) before income taxes	Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (In thousands) Bermuda $ $ $ $ United States Foreign—other Income (loss) before income taxes $ $ $ $

Net Income (Loss) Per Share (Ta

Net Income (Loss) Per Share (Tables)	9 Months Ended
	Sep. 30, 2016
Net Income (Loss) Per Share
Schedule of reconciliation between net income and the amounts used to compute basic and diluted net income per share and the weighted average shares outstanding used to compute basic and diluted net income per share	Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 (In thousands, except per share data) Numerator: Net income (loss) $ $ $ $ Basic income allocable to participating securities(1) — — — Basic net income (loss) allocable to common shareholders Diluted adjustments to income allocable to participating securities(1) — — — — Diluted net income (loss) allocable to common shareholders $ $ $ $ Denominator: Weighted average number of shares outstanding: Basic Restricted stock awards and units(1)(2) — — — Diluted Net income (loss) per share: Basic $ $ $ $ Diluted $ $ $ $ (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income (loss) per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net income (loss) per common share calculation in periods we are in a net loss position. We excluded outstanding restricted stock awards and units of 12.0 million and 1.8 million for the three months ended September 30, 2016 and 2015, respectively, and $12.0 million and $11.5 million for the nine months ended September 30, 2016 and 2015, respectively, from the computations of diluted net income per share because the effect would have been anti-dilutive.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies
Schedule of estimated future minimum commitments	Payments Due By Year(1) Total 2016(2) 2017 2018 2019 2020 Thereafter (In thousands) Operating leases(3) $ $ $ $ $ $ — $ — Atwood Achiever drilling rig contract(4) — — — (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 and seismic obligations, in our petroleum contracts. (2) Represents payments for the period from October 1, 2016 through December 31, 2016. (3) Primarily relates to corporate office and foreign office leases. (4) Commitments calculated using the amended day rate of $0.5 million effective October 1, 2015, excluding applicable taxes.

Additional Financial Informat33

Additional Financial Information (Tables)	9 Months Ended
	Sep. 30, 2016
Additional Financial Information
Schedule of accrued liabilities	September 30, December 31, 2016 2015 (In thousands) Accrued liabilities: Exploration, development and production $ $ General and administrative expenses Interest Income taxes Taxes other than income Other — $ $
Schedule of changes in asset retirement obligations	September 30, 2016 (In thousands) Asset retirement obligations: Beginning asset retirement obligations $ Liabilities incurred during period Revisions in estimated retirement obligations — Accretion expense Ending asset retirement obligations $
Schedule of Other expenses, net incurred	Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (In thousands) Inventory write-off — — — (Gain) loss on insurance settlements — Other, net Other expenses, net $ $ $ $

Organization (Details)

Organization (Details)	9 Months Ended
	Sep. 30, 2016segment
Organization
Number of reportable segments	1

Accounting Policies (Details)

Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Dec. 31, 2015
Restricted Cash
Current restricted cash	$ 25,588	$ 25,588	$ 28,533
Long-term restricted cash	51,632	51,632	7,325
Inventories
Materials and supplies inventory	65,000	65,000	84,400
Hydrocarbons inventory	17,100	17,100	800
Write down of materials and supplies	0	15,177
Stockholders' Equity Attributable to Parent [Abstract]
Accumulated deficit	(793,710)	(793,710)	(564,686)
Additional paid-in capital	1,965,596	1,965,596	1,933,189
Long-term deferred tax assets	32,605	32,605	33,209
Accounting Standards Update 2016-09 | Adjustment member
Stockholders' Equity Attributable to Parent [Abstract]
Accumulated deficit	(1,900)	(1,900)
Additional paid-in capital	3,000	3,000
Long-term deferred tax assets	1,100	1,100
Restricted Cash | Petroleum agreements - performance guarantees
Restricted Cash
Current restricted cash	1,100	1,100	4,100
Long-term restricted cash	51,600	$ 51,600	7,300
Restricted Cash | Facility interest or the Senior Notes plus the Corporate Revolver interest
Restricted Cash
Restricted cash period required as per commercial debt facility to meet interest and commitment fee payments		6 months
Current restricted cash	$ 24,500	$ 24,500	$ 24,400
Senior Notes | 7.875% senior notes due 2021
Restricted Cash
Interest rate	7.875%	7.875%

Acquisitions and Divestitures (

Acquisitions and Divestitures (Details) a in Millions	1 Months Ended
	Oct. 31, 2016km²	May 31, 2016km²	Apr. 30, 2016km²	Mar. 31, 2016	Feb. 29, 2016	Oct. 31, 2016a
Petroleum agreement | Block C6
Acquisitions and Divestitures
3 D seismic requirements (in square kilometers)	2,000
Initial exploration period	4 years
Area of petroleum exploration	4,300					1.1
Petroleum agreement | Boujdour Maritime block
Acquisitions and Divestitures
3 D seismic requirements (in square kilometers)		5,000
Initial exploration period		4 years
Term of each of the two extensions		2 years
Total extended exploration period		8 years
Period of right to develop and produce oil and gas		25 years
Extended period of right to develop and produce oil and gas		10 years
Chevron | Farm-out agreements | Block 42
Acquisitions and Divestitures
Participating interests (as a percent)			33.33%
Hess Corporation | Farm-out agreements | Block 42
Acquisitions and Divestitures
Non operated interest			33.33%
3 D seismic requirements (in square kilometers)			6,500
Participating interests (as a percent)			33.33%
ANP STP | Farm-in agreement | Block 5
Acquisitions and Divestitures
Carried interest held by third party as a percent					15.00%
ANP STP | Farm-in agreement | Block 12
Acquisitions and Divestitures
Carried interest held by third party as a percent				12.50%
Staatsolie | Farm-out agreements | Block 42
Acquisitions and Divestitures
Maximum percentage interest available upon approval (as a percent)			10.00%
Parent company | Farm-in agreement | Block 5
Acquisitions and Divestitures
Participation interest acquired (as a percent)					65.00%
Parent company | Farm-in agreement | Block 12
Acquisitions and Divestitures
Participation interest acquired (as a percent)				65.00%
Parent company | Farm-out agreements | Block 42
Acquisitions and Divestitures
Participating interests (as a percent)			33.33%
Parent company | Petroleum agreement | Block C6
Acquisitions and Divestitures
Participation interest acquired (as a percent)	90.00%
Parent company | Petroleum agreement | Boujdour Maritime block
Acquisitions and Divestitures
Participation interest acquired (as a percent)		55.00%
Cairn | Petroleum agreement | Boujdour Maritime block
Acquisitions and Divestitures
Participating interests (as a percent)		20.00%
ONHYM | Petroleum agreement | Boujdour Maritime block
Acquisitions and Divestitures
Carried interest held by third party as a percent		25.00%
SMHPM | Petroleum agreement | Block C6
Acquisitions and Divestitures
Carried interest held by third party as a percent	10.00%
Carried interest extinguished (as a percent)	10.00%
SMHPM | Petroleum agreement | Block C6 | Forecast | Minimum
Acquisitions and Divestitures
Participation interest acquired (as a percent)	10.00%
SMHPM | Petroleum agreement | Block C6 | Forecast | Maximum
Acquisitions and Divestitures
Participation interest acquired (as a percent)	18.00%

Joint Interest Billings (Detail

Joint Interest Billings (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Sep. 30, 2016	Dec. 31, 2015
Joint interest billings
Long-term receivables - joint interest billings		$ 45,998	$ 37,687
TEN Discoveries | GNPC
Joint interest billings
Long-term receivables - joint interest billings		$ 44,000	$ 35,300
TEN Discoveries | GNPC
Joint interest billings
GNPC's paying interest (as a percent)	5.00%

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Oil and gas properties:
Proved properties	$ 1,435,068		$ 1,435,068		$ 1,337,215
Unproved properties	828,556		828,556		593,510
Support equipment and facilities	1,404,664		1,404,664		1,241,943
Total oil and gas properties	3,668,288		3,668,288		3,172,668
Less: accumulated depletion	(918,085)		(918,085)		(858,442)
Oil and gas properties, net	2,750,203		2,750,203		2,314,226
Other property	36,325		36,325		34,807
Less: accumulated depreciation	(28,310)		(28,310)		(26,194)
Other property, net	8,015		8,015		8,613
Property and equipment, net	2,758,218		2,758,218		$ 2,322,839
Depletion expense	$ 15,600	$ 33,600	$ 59,600	$ 103,400

Suspended Well Costs (Details)

Suspended Well Costs (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2016USD ($)	Sep. 30, 2016USD ($)project	Dec. 31, 2015USD ($)project	May 31, 2015project
Reconciliation of capitalized exploratory well costs on completed wells
Beginning balance	$ 426,881
Additions to capitalized exploratory well costs pending the determination of proved reserves	301,228
Ending balance	728,109
Capitalized exploratory well costs subsequently expensed in the same period	2,600
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		$ 366,130	$ 199,486
Exploratory well costs capitalized for a period one to two years		152,144	17,702
Exploratory well costs capitalized for a period of three to seven years		209,835	209,693
Ending balance	$ 426,881	$ 728,109	$ 426,881
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | project		4	3
Greater Tortue Discovery
Aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year
Number of additional appraisal wells drilled | project				2

Debt (Details)

Debt (Details) $ in Thousands	Jun. 30, 2016	Sep. 30, 2016USD ($)item	Jul. 31, 2016	Jun. 30, 2015USD ($)	Apr. 30, 2015USD ($)	Aug. 31, 2014USD ($)	Sep. 30, 2016USD ($)item	Sep. 30, 2015USD ($)	Oct. 01, 2016USD ($)	Dec. 31, 2015USD ($)	Jul. 31, 2015USD ($)	Mar. 31, 2014USD ($)
Debt
Outstanding debt principal		$ 1,375,000					$ 1,375,000			$ 925,000
Unamortized issuance costs and discount		(55,906)					(55,906)			(64,122)
Long-term debt		1,319,094					1,319,094			860,878
Loss on extinguishment of debt								$ 165
Net deferred financing costs		5,933					5,933			7,986
Scheduled maturities of debt during the five year period and thereafter
2,019		268,823					268,823
2,020		395,166					395,166
Thereafter		711,011					711,011
Facility
Debt
Outstanding debt principal		850,000					850,000			400,000
Unamortized issuance costs and discount		(32,100)					(32,100)			(37,500)
Total commitment												$ 1,500,000
Increased in borrowing capacity		40,400
Current borrowing capacity									$ 1,467,000
Amount outstanding		850,000					850,000
Undrawn availability		576,500					576,500		$ 616,900
Revolving-credit sublimit amount after March 31, 2018		500,000					$ 500,000
Availability period of revolving-credit sublimit							1 month
Amount outstanding under letters of credit		0					$ 0
Corporate Revolver
Debt
Total commitment				$ 400,000
Percentage of the margin used to calculate commitment fees				30.00%
Net deferred financing costs		5,900					5,900
Amount outstanding		0					0
Undrawn availability		400,000					400,000
Revolving Letter of Credit Facility
Debt
Total commitment											$ 75,000
Amount outstanding		$ 70,300					$ 70,300
Number of letters of credit | item		11					11
Applicable margin (as a percent)	0.50%		0.80%
Commitment fee payable			0.65%
Revolving Letter of Credit Facility | Maximum
Debt
Additional commitments											$ 50,000
Senior Notes
Debt
Outstanding debt principal		$ 525,000					$ 525,000			525,000
Unamortized issuance costs and discount		$ (23,800)					$ (23,800)			$ (26,600)
Senior Notes | 7.875% senior notes due 2021
Debt
Interest rate		7.875%					7.875%
Senior notes offering face amount					$ 225,000	$ 300,000
Proceeds, net of offering discounts and deferred financing costs					$ 206,800	$ 292,500

Debt Interest (Details)

Debt Interest (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Debt
Interest expense	$ 23,057	$ 20,031	$ 65,829	$ 54,687
Amortization-deferred financing costs	2,551	2,554	7,653	7,773
Loss on extinguishment of debt				165
Capitalized interest	(15,545)	(15,152)	(49,575)	(37,146)
Deferred interest	663	129	406	1,421
Interest income	(485)	(168)	(1,319)	(508)
Other, net	825	2,532	7,274	3,283
Interest and other financing costs, net	$ 11,066	$ 9,926	$ 30,268	$ 29,675

Derivative Financial Instrume42

Derivative Financial Instruments (Details)	1 Months Ended	9 Months Ended
	Oct. 31, 2016$ / bblMBbls	Sep. 30, 2016$ / bblMBbls
Term October 2016 to December 2016 | Purchased puts
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		501
Weighted average deferred premium payable per Bbl		3.41
Weighted average floor price per Bbl		85
Term October 2016 to December 2016 | Three-way Collars
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		503
Weighted average floor price per Bbl		85
Weighted average ceiling price per Bbl		110
Weighted average purchased call price per Bbl		135
Term October 2016 to December 2016 | Swaps with puts
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		500
Weighted average swap price per Bbl		75
Weighted average sold put price per Bbl		60
Term January 2017 to December 2017 | Three-way Collars
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		3,002
Weighted average deferred premium payable per Bbl		2.29
Weighted average sold put price per Bbl		30
Weighted average floor price per Bbl		45
Weighted average ceiling price per Bbl		57.50
Term January 2017 to December 2017 | Swaps with puts
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		2,000
Weighted average swap price per Bbl		64.95
Weighted average sold put price per Bbl		50
Term January 2017 to December 2017 | Sold calls
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		2,000
Weighted average ceiling price per Bbl		85
Term January 2017 to December 2017 | Swap with puts/calls
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		2,000
Weighted average deferred premium payable per Bbl		2.13
Weighted average swap price per Bbl		72.50
Weighted average sold put price per Bbl		55
Weighted average purchased call price per Bbl		90
Term January 2018 to December 2018 | Three-way Collars
Derivative Financial Instruments
Volumes (in MBbl) | MBbls	2,000	913
Weighted average deferred premium payable per Bbl		2.37
Weighted average sold put price per Bbl	40	45
Weighted average floor price per Bbl	55	60
Weighted average ceiling price per Bbl	61.75	75
Term January 2018 to December 2018 | Sold calls
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		2,000
Weighted average ceiling price per Bbl		65
Term January 2019 to December 2019 | Sold calls
Derivative Financial Instruments
Volumes (in MBbl) | MBbls		913
Weighted average ceiling price per Bbl		80

Derivative Financial Instrume43

Derivative Financial Instruments - Swaps (Details) - 1-month LIBOR - Interest Rate Cap Swap - Term October 2016 to December 2018 $ in Thousands	Sep. 30, 2016USD ($)
Derivative Financial Instruments
Weighted Average Notional Amount	$ 200,000
Weighted Average Fixed Rate (as a percent)	1.23%
Interest rate cap	3.00%

Derivative Financial Instrume44

Derivative Financial Instruments - Derivatives (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Derivative instruments, Balance Sheet Location
Derivatives assets - current	$ 68,434	$ 182,640
Derivatives assets-long-term	12,493	59,856
Derivatives liabilities - current	(8,055)	(1,155)
Derivatives liabilities - long-term	(17,428)	(4,196)
Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Total	55,444	237,145
Commodity derivatives | Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Derivatives assets - current	68,434	182,640
Derivatives assets-long-term	12,493	59,197
Derivatives liabilities - current	(7,102)
Derivatives liabilities - long-term	(16,451)	(4,196)
Net deferred premiums payable related to commodity derivative contracts - current assets	4,500	6,200
Net deferred premiums payable related to commodity derivative contracts - non current assets	3,500	6,900
Net deferred premiums payable related to commodity derivative contracts - current liabilities	4,600	0
Net deferred premiums payable related to commodity derivative contracts - non current liabilities	2,300	0
Interest rate contracts | Not designated as hedging instruments
Derivative instruments, Balance Sheet Location
Derivatives assets-long-term		659
Derivatives liabilities - current	(953)	$ (1,155)
Derivatives liabilities - long-term	$ (977)

Derivative Financial Instrume45

Derivative Financial Instruments- Location of Gain (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives not designated as hedging instruments	$ 17,995	$ 138,934	$ (37,179)	$ 126,940
Commodity derivatives | Oil and gas revenue
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives not designated as hedging instruments	344	(1,033)	(712)	(736)
Commodity derivatives | Derivatives, net
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives not designated as hedging instruments	16,891	142,129	(33,752)	129,579
Interest rate contracts | Interest expense
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss), derivatives not designated as hedging instruments	$ 760	(2,162)	$ (2,715)	(1,903)
Derivatives in cash flow hedging relationships
Derivative instruments, Location of Gain/(Loss)
Interest rate derivatives, net		378		767
Derivatives in cash flow hedging relationships | Interest rate contracts | Interest expense
Derivative instruments, Location of Gain/(Loss)
Amount of Gain/(Loss) reclassified from AOCI into earnings		$ 378		$ 767

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Carrying Value
Liabilities:
Long-term debt	$ 1,352,802	$ 900,186
Total Fair Value
Liabilities:
Long-term debt	1,359,250	823,612
Recurring basis
Liabilities:
Total fair value, net	55,444	237,145
Recurring basis | Commodity derivatives
Assets:
Derivative asset, fair value	80,927	241,837
Liabilities:
Derivative liability, fair value	(23,553)	(4,196)
Recurring basis | Interest rate contracts
Assets:
Derivative asset, fair value		659
Liabilities:
Derivative liability, fair value	(1,930)	(1,155)
Recurring basis | Level 2
Liabilities:
Total fair value, net	55,444	237,145
Recurring basis | Level 2 | Commodity derivatives
Assets:
Derivative asset, fair value	80,927	241,837
Liabilities:
Derivative liability, fair value	(23,553)	(4,196)
Recurring basis | Level 2 | Interest rate contracts
Assets:
Derivative asset, fair value		659
Liabilities:
Derivative liability, fair value	(1,930)	(1,155)
Facility | Carrying Value
Liabilities:
Long-term debt	850,000	400,000
Facility | Total Fair Value
Liabilities:
Long-term debt	850,000	400,000
Senior Notes | Carrying Value
Liabilities:
Long-term debt	502,802	500,186
Senior Notes | Total Fair Value
Liabilities:
Long-term debt	$ 509,250	$ 423,612

Equity-based Compensation (Deta

Equity-based Compensation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
LTIP
Compensation agreement
Compensation expense recognized	$ 9.2	$ 13.9	$ 30.4	$ 62.4
Tax benefit	3	4.7	9.9	21.1
Tax shortfall related to equity-based compensation	1	0.1	5.3	18.5
Fair value of awards vested	$ 2.4	$ 1	$ 13.4	$ 51.8
Other disclosures
Number of shares remaining available for grant	8,300		8,300
Minimum | LTIP
Equity-based Compensation
Vesting period			3 years
Maximum | LTIP
Equity-based Compensation
Vesting period			4 years
Service Vesting Restricted Stock Awards | LTIP
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)			810
Vested (in shares)			(322)
Outstanding at the end of the period (in shares)	488		488
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)			$ 9.20
Vested (in dollars per share)			9.77
Outstanding at the end of the period (in dollars per share)	$ 8.83		$ 8.83
Market/Service Vesting Restricted Stock Awards | LTIP
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)			261
Forfeited (in shares)			(162)
Vested (in shares)			(99)
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)			$ 9.44
Forfeited (in dollars per share)			9.44
Vested (in dollars per share)			9.44
Market/Service Vesting Restricted Stock Awards | Minimum | LTIP
Weighted-Average Grant-Date Fair Value for awards
Granted (in dollars per share)			6.70
Weighted-Average Grant-Date Fair Value
Granted (in dollars per share)			$ 6.70
Significant assumptions used to calculate fair values
Expected volatility (as a percent)			41.30%
Risk-free interest rate (as a percent)			0.50%
Market/Service Vesting Restricted Stock Awards | Maximum | LTIP
Weighted-Average Grant-Date Fair Value for awards
Granted (in dollars per share)			$ 13.57
Weighted-Average Grant-Date Fair Value
Granted (in dollars per share)			$ 13.57
Significant assumptions used to calculate fair values
Expected volatility (as a percent)			56.70%
Risk-free interest rate (as a percent)			1.10%
Other disclosures
Vesting percentage of the awards granted			100.00%
Service Vesting Restricted Stock Units | LTIP
Weighted-Average Grant-Date Fair Value for awards
Granted (in dollars per share)			$ 4.05
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)			3,592
Granted (in shares)			2,152
Forfeited (in shares)			(131)
Vested (in shares)			(1,378)
Outstanding at the end of the period (in shares)	4,235		4,235
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)			$ 9.79
Granted (in dollars per share)			4.05
Forfeited (in dollars per share)			8.91
Vested (in dollars per share)			9.67
Outstanding at the end of the period (in dollars per share)	$ 6.94		6.94
Market/Service Vesting Restricted Stock Units | LTIP
Weighted-Average Grant-Date Fair Value for awards
Granted (in dollars per share)			$ 4.88
Outstanding unvested awards activity
Outstanding at the beginning of the period (in shares)			6,578
Granted (in shares)			1,379
Forfeited (in shares)			(70)
Vested (in shares)			(652)
Outstanding at the end of the period (in shares)	7,235		7,235
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of the period (in dollars per share)			$ 14.24
Granted (in dollars per share)			4.88
Forfeited (in dollars per share)			14.49
Vested (in dollars per share)			15.81
Outstanding at the end of the period (in dollars per share)	$ 12.31		12.31
Market/Service Vesting Restricted Stock Units | Minimum | LTIP
Weighted-Average Grant-Date Fair Value for awards
Granted (in dollars per share)			4.83
Weighted-Average Grant-Date Fair Value
Granted (in dollars per share)			$ 4.83
Significant assumptions used to calculate fair values
Expected volatility (as a percent)			44.00%
Risk-free interest rate (as a percent)			0.50%
Market/Service Vesting Restricted Stock Units | Maximum | LTIP
Weighted-Average Grant-Date Fair Value for awards
Granted (in dollars per share)			$ 15.81
Weighted-Average Grant-Date Fair Value
Granted (in dollars per share)			$ 15.81
Significant assumptions used to calculate fair values
Expected volatility (as a percent)			54.00%
Risk-free interest rate (as a percent)			1.20%
Other disclosures
Vesting percentage of the awards granted			200.00%
Restricted Stock Awards and Restricted Stock Units
Weighted-Average Grant-Date Fair Value
Compensation expense not yet recognized	$ 41		$ 41
Weighted average period over which compensation expense is to be recognized			1 year 5 months 19 days

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Taxes
Income tax expense (benefit)	$ 7,502	$ 62,218	$ (10,064)	$ 113,307
Income (loss) before income taxes	$ (52,261)	$ 122,483	$ (237,144)	$ 19,471
Effective tax rate (as a percent)	14.00%	51.00%	(4.00%)	582.00%
Bermuda
Income Taxes
Income (loss) before income taxes	$ (15,989)	$ (16,268)	$ (47,212)	$ (47,304)
United States
Income Taxes
Income (loss) before income taxes	$ 1,132	$ 2,903	$ 5,447	$ 11,457
Effective tax rate (as a percent)	156.00%	44.00%	152.00%	202.00%
Foreign-other
Income Taxes
Income (loss) before income taxes	$ (37,404)	$ 135,848	$ (195,379)	$ 55,318
Effective tax rate (as a percent)			0.00%
Statutory tax rate (as a percent)			0.00%
Ghana
Income Taxes
Effective tax rate (as a percent)	45.00%	35.00%	(27.00%)	35.00%

Net Income (Loss) Per Share (De

Net Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Numerator:
Net income (loss)	$ (59,763)	$ 60,265	$ (227,080)	$ (93,836)
Basic income allocable to participating securities		131
Basic net income (loss) allocable to common shareholders	(59,763)	60,134	(227,080)	(93,836)
Diluted net income (loss) allocable to common shareholders	$ (59,763)	$ 60,134	$ (227,080)	$ (93,836)
Weighted average number of shares used to compute net income (loss) per share:
Basic (in shares)	386,026	383,924	385,130	382,603
Restricted stock awards and units (in shares)		6,662
Diluted (in shares)	386,026	390,586	385,130	382,603
Net income (loss) per share:
Basic (in dollars per share)	$ (0.15)	$ 0.16	$ (0.59)	$ (0.25)
Diluted (in dollars per share)	$ (0.15)	$ 0.15	$ (0.59)	$ (0.25)
Outstanding restricted stock awards and units excluded from the computations of diluted net income per share (in shares)	12,000	1,800	12,000	11,500

Commitments and Contingencies50

Commitments and Contingencies (Details) $ in Thousands, $ / site in Millions	Oct. 15, 2015USD ($)	Oct. 01, 2015USD ($)	Oct. 31, 2016km²	Nov. 30, 2015USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)km²$ / site
Offshore drilling rig contract commitments
Line of credit receivable				$ 30,000
Interest accrual rate on line of credit receivable				7.875%
Morocco | Maximum
Commitments and contingencies
Spending per well by third party for exploration well (in dollars per well) | $ / site						120
Mauritania
Commitments and contingencies
3 D seismic requirements (in square kilometers) | km²			2,000			1,000
Sao Tome and Principe
Commitments and contingencies
2 D seismic requirements (in square kilometers) | km²						1,200
3 D seismic requirements (in square kilometers) | km²						4,000
Western Sahara
Commitments and contingencies
3 D seismic requirements (in square kilometers) | km²						5,000
Other noncurrent assets
Offshore drilling rig contract commitments
Line of credit receivable amount outstanding						$ 8,300
Operating leases
Future minimum rental commitments
2,016						925
2,017						4,190
2,018						3,820
2,019						3,161
Total						$ 12,096
Atwood Achiever drilling rig contract
Offshore drilling rig contract commitments
Contract end date extension		1 year
Drilling rig contract period						3 years
Initial rig rate per day					$ 600
Optional extension period						3 years
Future minimum rental commitments
2,016						$ 38,957
2,017						177,624
2,018						156,600
Total						$ 373,181
Rig rate per day	$ 500	$ 500
Rig rate per day - subsidiary's revert option	$ 600

Additional Financial Informat51

Additional Financial Information - Accrued Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Accrued liabilities:
Exploration, development and production	$ 66,606		$ 66,606		$ 111,064
General and administrative expenses	20,642		20,642		24,839
Interest	6,891		6,891		17,512
Income taxes	3,188		3,188		3,418
Taxes other than income	2,485		2,485		3,064
Other	618		618
Accrued liabilities	100,430		100,430		$ 159,897
Asset retirement obligations:
Beginning asset retirement obligations			43,938
Liabilities incurred during period			13,463
Accretion expense			3,762
Ending asset retirement obligations	61,163		61,163
Other Income
Other Income	20,000		20,000
Other Expenses, Net
Inventory write-off	0		15,177
(Gain) loss on insurance settlements	(3,047)		(4,003)	$ 4,151
Other, net	2,252	$ 290	2,594	1,033
Other expenses, net	$ (795)	$ 290	$ 13,768	$ 5,184