Edgar Filing: Kosmos Energy Ltd.

kos_Current folio_10Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


(Mark One)
☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2016


☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-35167

Kosmos Energy Ltd.

(Exact name of registrant as specified in its charter)


Bermuda		98-0686001
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)


Clarendon House
2 Church Street
Hamilton, Bermuda		HM 11
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: +1 441 295 5950

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ☒		Accelerated filer ☐

Non-accelerated filer ☐		Smaller reporting company ☐
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


Class		Outstanding at August 1, 2016
Common Shares, $0.01 par value		386,541,822

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TABLE OF CONTENTS

Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its subsidiaries. We have provided definitions for some of the industry terms used in this report in the “Glossary and Selected Abbreviations” beginning on page 3.


	Page
PART I. FINANCIAL INFORMATION

Glossary and Select Abbreviations	3

Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015	7
Consolidated Statements of Operations for the three and six months ended June 30, 2016 and 2015	8
Consolidated Statements of Comprehensive Loss for the three and six months ended June 30, 2016 and 2015	9
Consolidated Statements of Shareholders’ Equity for the three and six months ended June 30, 2016	10
Consolidated Statements of Cash Flows for the six months ended June 30, 2016 and 2015	11
Notes to Consolidated Financial Statements	12
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3. Quantitative and Qualitative Disclosures about Market Risk	40
Item 4. Controls and Procedures	42

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	43
Item 1A. Risk Factors	43
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 3. Defaults Upon Senior Securities	43
Item 4. Mine Safety Disclosures	43
Item 5. Other Information	44
Item 6. Exhibits	46
Signatures	47
Index to Exhibits	48

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KOSMOS ENERGY LTD.

GLOSSARY AND SELECTED ABBREVIATIONS

The following are abbreviations and definitions of certain terms that may be used in this report. Unless listed below, all defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings.


“2D seismic data”		Two-dimensional seismic data, serving as interpretive data that allows a view of a vertical cross-section beneath a prospective area.

“3D seismic data”		Three-dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.

“API”		A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones.

“ASC”		Financial Accounting Standards Board Accounting Standards Codification.

“ASU”		Financial Accounting Standards Board Accounting Standards Update.

“Barrel” or “Bbl”		A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.

“BBbl”		Billion barrels of oil.

“BBoe”		Billion barrels of oil equivalent.

“Bcf”		Billion cubic feet.

“Boe”		Barrels of oil equivalent. Volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.

“Boepd”		Barrels of oil equivalent per day.

“Bopd”		Barrels of oil per day.

“Bwpd”		Barrels of water per day.

“Debt cover ratio”		The “debt cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) total long-term debt less cash and cash equivalents and restricted cash, to (y) the aggregate EBITDAX (see below) of the Company for the previous twelve months.

“Developed acreage”		The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Development”		The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.

“Dry hole”		A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.

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“EBITDAX”		Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity-based compensation expense, (iv) unrealized (gain) loss on commodity derivatives (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results.

“E&P”		Exploration and production.

“FASB”		Financial Accounting Standards Board.

“Farm-in”		An agreement whereby a party acquires a portion of the participating interest in a block from the owner of such interest, usually in return for cash and for taking on a portion of the drilling costs of one or more specific wells or other performance by the assignee as a condition of the assignment.

“Farm-out”		An agreement whereby the owner of the participating interest agrees to assign a portion of its participating interest in a block to another party for cash and/or for the assignee taking on a portion of the drilling costs of one or more specific wells and/or other work as a condition of the assignment.

“Field life cover ratio”		The “field life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) the forecasted net present value of net cash flow through the depletion of the Jubilee Field plus the net present value of the forecast of certain capital expenditures incurred in relation to the Jubilee Field and certain other fields in Ghana, to (y) the aggregate loan amounts outstanding under the Facility less the Resource Bridge, as applicable.

“FPSO”		Floating production, storage and offloading vessel.

“Interest cover ratio”		The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months.

“Loan life cover ratio”		The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of forecasted net cash flow through the final maturity date of the Facility plus the net present value of forecasted capital expenditures incurred in relation to the Jubilee Field and certain other fields in Ghana, to (y) the aggregate loan amounts outstanding under the Facility less the Resource Bridge, as applicable.

“Make-whole redemption price”		The “make-whole redemption price” is equal to the outstanding principal amount of such notes plus the greater of 1) 1% of the then outstanding principal amount of such notes and 2) the present value of the notes at 103.9% and required interest payments thereon through August 1, 2017 at such redemption date.

“MBbl”		Thousand barrels of oil.

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“Mcf”		Thousand cubic feet of natural gas.

“Mcfpd”		Thousand cubic feet per day of natural gas.

“MMBbl”		Million barrels of oil.

“MMBoe”		Million barrels of oil equivalent.

“MMcf”		Million cubic feet of natural gas.

“Natural gas liquid” or “NGL”		Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others.

“Petroleum contract”		A contract in which the owner of hydrocarbons gives an E&P company temporary and limited rights, including an exclusive option to explore for, develop, and produce hydrocarbons from the lease area.

“Petroleum system”		A petroleum system consists of organic material that has been buried at a sufficient depth to allow adequate temperature and pressure to expel hydrocarbons and cause the movement of oil and natural gas from the area in which it was formed to a reservoir rock where it can accumulate.

“Plan of development” or “PoD”		A written document outlining the steps to be undertaken to develop a field.

“Productive well”		An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

“Prospect(s)”		A potential trap that may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of these fail neither oil nor natural gas may be present, at least not in commercial volumes.

“Proved reserves”		Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).

“Proved developed reserves”		Those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.

“Proved undeveloped reserves”		Those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.

“Reconnaissance contract”		A contract in which the owner of hydrocarbons gives an E&P company rights to perform evaluation of existing data or potentially acquire additional data but may not convey an exclusive option to explore for, develop, and/or produce hydrocarbons from the lease area.

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“Resource Bridge”		Borrowing Base availability attributable to probable reserves and contingent resources from Jubilee Field Future Phases, Tweneboa, Enyenra and Ntomme fields and potentially Mahogany, Teak and Akasa fields.

“Shelf margin”		The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.

“Stratigraphy”		The study of the composition, relative ages and distribution of layers of sedimentary rock.

“Stratigraphic trap”		A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.

“Structural trap”		A topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and natural gas in the strata.

“Structural-stratigraphic trap”		A structural-stratigraphic trap is a combination trap with structural and stratigraphic features.

“Submarine fan”		A fan-shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.

“Three-way fault trap”		A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.

“Trap”		A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.

“Undeveloped acreage”		Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains discovered resources.

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KOSMOS ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	June 30,		December 31,
	2016		2015
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	112,817	$	275,004
Restricted cash		27,428		28,533
Receivables:
Joint interest billings		68,595		67,200
Oil sales		45,506		35,950
Other		25,246		34,882
Inventories		71,078		85,173
Prepaid expenses and other		5,781		24,766
Derivatives		96,723		182,640
Total current assets		453,174		734,148

Property and equipment:
Oil and gas properties, net		2,677,562		2,314,226
Other property, net		8,567		8,613
Property and equipment, net		2,686,129		2,322,839

Other assets:
Restricted cash		51,632		7,325
Long-term receivables - joint interest billings		42,572		37,687
Deferred financing costs, net of accumulated amortization of $9,844 and $8,475 at June 30, 2016 and December 31, 2015, respectively		6,617		7,986
Long-term deferred tax assets		29,976		33,209
Derivatives		18,028		59,856
Other		5,134		—
Total assets	$	3,293,262	$	3,203,050

Liabilities and shareholders’ equity
Current liabilities:
Accounts payable	$	215,755	$	295,689
Accrued liabilities		141,267		159,897
Derivatives		6,310		1,155
Total current liabilities		363,332		456,741

Long-term liabilities:
Long-term debt		1,191,334		860,878
Derivatives		26,286		4,196
Asset retirement obligations		46,339		43,938
Deferred tax liabilities		478,003		502,189
Other long-term liabilities		9,272		9,595
Total long-term liabilities		1,751,234		1,420,796

Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at June 30, 2016 and December 31, 2015		—		—
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 395,295,816 and 393,902,643 issued at June 30, 2016 and December 31, 2015, respectively		3,953		3,939
Additional paid-in capital		1,956,287		1,933,189
Accumulated deficit		(733,947)		(564,686)
Treasury stock, at cost, 9,101,395 and 8,812,054 shares at June 30, 2016 and December 31, 2015, respectively		(47,597)		(46,929)
Total shareholders’ equity		1,178,696		1,325,513
Total liabilities and shareholders’ equity	$	3,293,262	$	3,203,050

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
Revenues and other income:
Oil and gas revenue	$	45,506	$	119,200	$	107,631	$	228,364
Gain on sale of assets		—		1,900		—		24,651
Other income		170		713		178		1,355

Total revenues and other income		45,676		121,813		107,809		254,370

Costs and expenses:
Oil and gas production		32,681		20,224		62,073		52,324
Exploration expenses		36,402		14,539		60,260		113,480
General and administrative		19,838		41,179		37,758		79,846
Depletion and depreciation		16,927		37,532		48,193		74,539
Interest and other financing costs, net		8,878		8,998		19,202		19,749
Derivatives, net		54,988		44,877		50,643		12,550
Other expenses, net		(170)		4,266		14,563		4,894

Total costs and expenses		169,544		171,615		292,692		357,382

Loss before income taxes		(123,868)		(49,802)		(184,883)		(103,012)
Income tax expense (benefit)		(15,544)		25,390		(17,566)		51,089

Net loss	$	(108,324)	$	(75,192)	$	(167,317)	$	(154,101)

Net loss per share:
Basic	$	(0.28)	$	(0.20)	$	(0.43)	$	(0.40)
Diluted	$	(0.28)	$	(0.20)	$	(0.43)	$	(0.40)

Weighted average number of shares used to compute net loss per share:
Basic		384,918		382,138		384,676		381,238
Diluted		384,918		382,138		384,676		381,238

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In thousands)

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Net loss	$	(108,324)	$	(75,192)	$	(167,317)	$	(154,101)
Other comprehensive loss:
Reclassification adjustments for derivative gains included in net loss		—		(195)		—		(389)
Other comprehensive loss		—		(195)		—		(389)
Comprehensive loss	$	(108,324)	$	(75,387)	$	(167,317)	$	(154,490)

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands)

(Unaudited)



				Additional
	Common Shares			Paid-in		Accumulated		Treasury
	Shares	Amount		Capital		Deficit		Stock		Total
Balance as of December 31, 2015	393,903	$	3,939	$	1,933,189	$	(564,686)	$	(46,929)	$	1,325,513
Equity-based compensation	—		—		24,242		(1,944)		—		22,298
Derivatives, net	—		—		—		—		—		—
Restricted stock awards and units	1,393		14		(14)		—		—		—
Restricted stock forfeitures	—		—		2		—		(2)		—
Purchase of treasury stock	—		—		(1,132)		—		(666)		(1,798)
Net loss	—		—		—		(167,317)		—		(167,317)
Balance as of June 30, 2016	395,296	$	3,953	$	1,956,287	$	(733,947)	$	(47,597)	$	1,178,696

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30,
	2016		2015
Operating activities
Net loss	$	(167,317)	$	(154,101)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		53,295		79,758
Deferred income taxes		(19,929)		23,015
Unsuccessful well costs		2,300		86,603
Change in fair value of derivatives		55,175		11,605
Cash settlements on derivatives, net (including $101.8 million and $93.5 million on commodity hedges during 2016 and 2015)		99,815		93,275
Equity-based compensation		21,162		48,527
Gain on sale of assets		—		(24,651)
Loss on extinguishment of debt		—		165
Other		15,069		5,977
Changes in assets and liabilities:
(Increase) decrease in receivables		(11,225)		8,615
Increase in inventories		(1,082)		(14,754)
Decrease in prepaid expenses and other		18,985		6,254
Decrease in accounts payable		(80,359)		(34,681)
Decrease in accrued liabilities		(9,967)		(52,154)
Net cash provided by (used in) operating activities		(24,078)		83,453

Investing activities
Oil and gas assets		(417,704)		(384,194)
Other property		(601)		(536)
Proceeds on sale of assets		196		28,603
Restricted cash		(43,202)		(9,574)
Net cash used in investing activities		(461,311)		(365,701)

Financing activities
Borrowings under long-term debt		325,000		—
Payments on long-term debt		—		(200,000)
Net proceeds from issuance of senior secured notes		—		206,774
Purchase of treasury stock		(1,798)		(17,955)
Deferred financing costs		—		(8,791)
Net cash provided by (used in) financing activities		323,202		(19,972)

Net decrease in cash and cash equivalents		(162,187)		(302,220)
Cash and cash equivalents at beginning of period		275,004		554,831
Cash and cash equivalents at end of period	$	112,817	$	252,611

Supplemental cash flow information
Cash paid for:
Interest	$	8,200	$	28,335
Income taxes	$	6,978	$	17,119

Non-cash activity:
Conversion of joint interest billings receivable to long-term note receivable	$	5,033	$	—

See accompanying notes.

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements

(Unaudited)

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 product sales are currently related to production located offshore Ghana.

2. Accounting Policies

General

The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of June 30, 2016, the changes in the consolidated statements of shareholders’ equity for the six months ended June 30, 2016, the consolidated results of operations for the three and six months ended June 30, 2016 and 2015, and the consolidated cash flows for the six months ended June 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.

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 June 30, 2016 and December 31, 2015, we had $24.4 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 June 30, 2016 and December 31, 2015, we had $3.0 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.

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Inventories

Inventories consisted of $71.0 million and $84.4 million of materials and supplies and $0.1 million and $0.8 million of hydrocarbons as of June 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 $15.2 million during the six months ended, June 30, 2016 for materials and supplies inventories as other expenses, net in the consolidated statement of operations and other in the consolidated statement 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

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.

3. Acquisitions and Divestitures

In January and February 2016, we entered into farm-in agreements with Equator, an affiliate of Oando, 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 will fund the cost of acquiring and processing a 6,500 square kilometer 3D seismic survey, subject to a maximum spend, expected to commence in the third quarter of 2016. 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 will remain the operator.

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.

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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 June 30, 2016 and December 31, 2015, the joint interest billing receivables due from GNPC for the TEN development costs were $41.4 million and $35.3 million, respectively, which are classified as long-term on the consolidated balance sheets.

5. Property and Equipment

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


	June 30,		December 31,
	2016		2015
	(In thousands)
Oil and gas properties:
Proved properties	$	1,395,532	$	1,337,215
Unproved properties		811,348		593,510
Support equipment and facilities		1,373,186		1,241,943
Total oil and gas properties		3,580,066		3,172,668
Accumulated depletion		(902,504)		(858,442)
Oil and gas properties, net		2,677,562		2,314,226

Other property		36,369		34,807
Accumulated depreciation		(27,802)		(26,194)
Other property, net		8,567		8,613

Property and equipment, net	$	2,686,129	$	2,322,839

We recorded depletion expense of $14.9 million and $35.2 million for the three months ended June 30, 2016 and 2015, respectively, and $44.1 million and $69.8 million for the six months ended June 30, 2016 and 2015, respectively.

6. Suspended Well Costs

The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the six months ended June 30, 2016. The table excludes $2.3 million in costs that were capitalized and subsequently expensed during the same period.


	June 30,
	2016
	(In thousands)
Beginning balance	$	426,881
Additions to capitalized exploratory well costs pending the determination of proved reserves		293,518
Reclassification due to determination of proved reserves		—
Capitalized exploratory well costs charged to expense		—
Ending balance	$	720,399

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The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling:



	June 30, 2016		December 31, 2015
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	359,596	$	199,486
Exploratory well costs capitalized for a period of one to two years		151,103		17,702
Exploratory well costs capitalized for a period of three to seven years		209,700		209,693
Ending balance	$	720,399	$	426,881
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		4		3

As of June 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 development 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.

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7. Accrued Liabilities

Accrued liabilities consisted of the following:


	June 30,		December 31,
	2016		2015
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	104,400	$	111,064
General and administrative expenses		15,702		24,839
Interest		17,227		17,512
Income taxes		1,009		3,418
Taxes other than income		2,929		3,064
	$	141,267	$	159,897

8. Debt


	June 30,		December 31,
	2016		2015
	(In thousands)
Outstanding debt principal balances:
Facility	$	725,000	$	400,000
Senior Notes		525,000		525,000
Total		1,250,000		925,000
Unamortized issuance costs and discounts		(58,666)		(64,122)
Long-term debt	$	1,191,334	$	860,878

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. As of June 30, 2016, we have $33.9 million of net deferred financing costs related to the Facility, which will be amortized over the remaining term of the Facility, including certain costs related to the amendment.

In March 2016, following the lender’s semi-annual redetermination, the borrowing base under our Facility was reduced by $73.5 million to $1.427 billion. The borrowing base calculation includes value related to the Jubilee field and TEN development project. As of June 30, 2016, borrowings under the Facility totaled $725.0 million and the undrawn availability under the Facility was $701.5 million.

The Facility provides a revolving-credit and letter of credit facility. The availability period for the revolving-credit facility, as amended in March 2014, expires on March 31, 2018, however, the Facility has a revolving-credit sublimit, which will be the lesser of $500.0 million and the total available facility at that time, that will be available for drawing until the date falling one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2018, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2021. As of June 30, 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 March 31, 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;

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appraisal and development programs. As of June 30, 2016, we have $6.6 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term.

As of June 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 March 31, 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 June 30, 2016, there were 13 outstanding letters of credit totaling $72.8 million under the LC Facility. The LC Facility contains customary cross default provisions.

7.875% Senior Secured Notes due 2021

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

During April 2015, we issued an additional $225.0 million of Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million of Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest will accrue.

The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries.

At June 30, 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)	$	1,250,000	$	—	$	—	$	—	$	207,271	$	348,123	$	694,606

(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 June 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 June 30, 2016, there were no borrowings under the Corporate Revolver.

(2)

Represents payments for the period July 1, 2016 through December 31, 2016.

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Interest and other financing costs, net

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In thousands)				(In thousands)
Interest expense	$	21,824	$	19,260	$	42,772	$	34,657
Amortization—deferred financing costs		2,551		2,609		5,102		5,219
Loss on extinguishment of debt		—		165		—		165
Capitalized interest		(17,584)		(13,154)		(34,030)		(21,994)
Deferred interest		149		137		(258)		1,291
Interest income		(466)		(172)		(834)		(340)
Other, net		2,404		153		6,450		751
Interest and other financing costs, net	$	8,878	$	8,998	$	19,202	$	19,749

9. Derivative Financial Instruments

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

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

Oil Derivative Contracts

The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of June 30, 2016.


			Weighted Average Dated Brent Price per Bbl
			Net Deferred
			Premium
Term	Type of Contract	MBbl	Payable		Swap		Sold Put		Floor		Ceiling		Call
2016:
July — December	Purchased puts	1,002	$	3.41	$	—	$	—	$	85.00	$	—	$	—
July — December	Three-way collars	1,005		—		—		—		85.00		110.00		135.00
July — December	Swaps with puts	1,000		—		75.00		60.00		—		—		—
2017:
January — December	Swap with puts/calls	2,000	$	2.13	$	72.50	$	55.00	$	—	$	—	$	90.00
January — December	Swap with puts	2,000		—		64.95		50.00		—		—		—
January — December	Sold calls(1)	2,000		—		—		—		—		85.00		—
January — December	Three-way collars	4,000		1.72		—		30.00		45.00		57.50		—
2018:
January — December	Three-way collars	913	$	2.37	$	—	$	45.00	$	60.00	$	75.00	$	—
January — December	Sold calls(1)	2,000		—		—		—		—		65.00		—
2019:
January — December	Sold calls(1)	913	$	—	$	—	$	—	$	—	$	80.00	$	—

(1)

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

Interest Rate Derivative Contracts

The following table summarizes our open interest rate swaps, whereby we pay a fixed rate of interest and the counterparty pays a variable LIBOR-based rate, and our capped interest rate swaps whereby we pay a fixed rate of

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interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of June 30, 2016:

Weighted Average

Term

Type of Contract

Floating Rate

Notional

Swap

Sold Call

(In thousands)

July 2016 — December 2018

Capped swap

1-month LIBOR

200,000

1.23

3.00

The following tables disclose the Company’s derivative instruments as of June 30, 2016 and December 31, 2015 and gain/(loss) from derivatives during the three and six months ended June 30, 2016 and 2015, respectively:


		Estimated Fair Value
		Asset (Liability)
		June 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	$	96,723	$	182,640
Commodity(2)	Derivatives assets—long-term		18,028		59,197
Interest rate	Derivatives assets—long-term		—		659
Derivative liabilities:
Commodity(3)	Derivatives liabilities—current		(4,922)		—
Interest rate	Derivatives liabilities—current		(1,388)		(1,155)
Commodity(4)	Derivatives liabilities—long-term		(24,598)		(4,196)
Interest rate	Derivatives liabilities—long-term		(1,688)		—
Total derivatives not designated as hedging instruments		$	82,155	$	237,145

(1)

Includes net deferred premiums payable of $5.2 million and $6.2 million related to commodity derivative contracts as of June 30, 2016 and December 31, 2015, respectively.

(2)

Includes net deferred premiums payable of $4.6 million and $6.9 million related to commodity derivative contracts as of June 30, 2016 and December 31, 2015, respectively.

(3)

Includes net deferred premiums payable of $2.8 million and zero related to commodity derivative contracts as of June 30, 2016 and December 31, 2015, respectively.

(4)

Includes net deferred premiums payable of $4.0 million and zero related to commodity derivative contracts as of June 30, 2016 and December 31, 2015, respectively.

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		Amount of Gain/(Loss)				Amount of Gain/(Loss)
		Three Months Ended				Six Months Ended
		June 30,				June 30,
Type of Contract	Location of Gain/(Loss)	2016		2015		2016		2015
		(In thousands)				(In thousands)
Derivatives in cash flow hedging relationships:
Interest rate(1)	Interest expense	$	—	$	195	$	—	$	389
Total derivatives in cash flow hedging relationships		$	—	$	195	$	—	$	389
Derivatives not designated as hedging instruments:
Commodity(2)	Oil and gas revenue	$	(1,665)	$	(2,336)	$	(1,055)	$	297
Commodity	Derivatives, net		(54,988)		(44,877)		(50,643)		(12,550)
Interest rate	Interest expense		(898)		433		(3,476)		259
Total derivatives not designated as hedging instruments		$	(57,551)	$	(46,780)	$	(55,174)	$	(11,994)

(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 June 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.

10. 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.

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The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 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)
June 30, 2016
Assets:
Commodity derivatives	$	—	$	114,751	$	—	$	114,751
Interest rate derivatives		—		—		—		—
Liabilities:
Commodity derivatives		—		(29,520)		—		(29,520)
Interest rate derivatives		—		(3,076)		—		(3,076)
Total	$	—	$	82,155	$	—	$	82,155
December 31, 2015
Assets:
Commodity derivatives	$	—	$	241,837	$	—	$	241,837
Interest rate derivatives		—		659		—		659
Liabilities:
Commodity derivatives		—		(4,196)		—		(4,196)
Interest rate derivatives		—		(1,155)		—		(1,155)
Total	$	—	$	237,145	$	—	$	237,145

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 9 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.

Provisional Oil Sales

The value attributable to the provisional oil sales derivative is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for Dated Brent over the term of the pricing period designated in the sales contract and the spot price on the lifting date.

Interest Rate Derivatives

We have interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate. We also have 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

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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 of financial instruments that are not carried at fair value in the consolidated balance sheets:


	June 30, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Long-term debt	$	1,226,909	$	1,232,938	$	900,186	$	823,612

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. The carrying value of long-term debt represents the principal amounts outstanding and does not include any unamortized issuance costs. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement.

11. Equity-based Compensation

Restricted Stock Awards and Restricted Stock Units

We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long-Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $10.5 million and $23.3 million during the three months ended June 30, 2016 and 2015, respectively, and $21.2 million and $48.5 million for the six months ended June 30, 2016 and 2015, respectively. The total tax benefit for the three months ended June 30, 2016 and 2015 was $3.3 million and $8.2 million, respectively, and $6.9 million and $17.0 million for the six months ended June 30, 2016 and 2015, respectively. Additionally, we expensed a tax shortfall related to equity-based compensation of $3.1 million and $18.3 million for the three months ended June 30, 2016 and 2015 respectively, and $4.3 million and $18.4 million for the six months ended June 30, 2016 and 2015, respectively. The fair value of awards vested during the three months ended June 30, 2016 and 2015 was approximately $7.7 million and $50.0 million, respectively, and $11.2 million and $50.8 million for the six months ended June 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.

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The following table reflects the outstanding restricted stock awards as of June 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	810	$	9.20	261	$	9.44
Granted	—		—	—		—
Forfeited	—		—	(162)		9.44
Vested	(322)		9.77	(99)		9.44
Outstanding at June 30, 2016	488		8.83	—		—

The following table reflects the outstanding restricted stock units as of June 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	3,592	$	9.79	6,578	$	14.24
Granted	2,070		3.99	1,344		4.88
Forfeited	(115)		8.81	(38)		14.41
Vested	(1,207)		9.77	(398)		15.82
Outstanding at June 30, 2016	4,340		7.05	7,486		12.48

As of June 30, 2016, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $50.0 million over a weighted average period of 1.64 years. At June 30, 2016, the Company had approximately 8.2 million shares that remain available for issuance under the LTIP.

For restricted stock awards and restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 100% of the awards granted for restricted stock awards and up to 200% of the awards granted for restricted stock units. The grant date fair value 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.

12. Income Taxes

Income tax expense (benefit) was $(15.5) million and $25.4 million for the three months ended June 30, 2016 and 2015, respectively, and $(17.6) million and $51.1 million for the six months ended June 30, 2016 and 2015, respectively. The income tax provision consists of United States and Ghanaian income and Texas margin taxes.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(In thousands)				(In thousands)
Bermuda	$	(15,427)	$	(17,374)	$	(31,223)	$	(31,037)
United States		2,219		3,887		4,315		8,554
Foreign—other		(110,660)		(36,315)		(157,975)		(80,529)
Loss before income taxes	$	(123,868)	$	(49,802)	$	(184,883)	$	(103,012)

Our effective tax rate for the three months ended June 30, 2016 and 2015 is a tax benefit of 13% and tax expense of 51%, respectively. For the six months ended June 30, 2016 and 2015, our effective tax rate is a tax benefit of 10% and tax expense of 50%, respectively. The effective tax rate for the United States is approximately 191% and 511% for the three months ended June 30, 2016 and 2015, respectively, and 151% and 256% for the six months ended, June 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 29% and 43% for the three months ended June 30, 2016 and 2015, respectively, and 30% and 36% for the six months ended, June 30, 2016 and 2015, respectively. Beginning with the three months ended June 30, 2016, 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 under insurance. Any insurance recoveries received would not be subject to income tax. Our 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.

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 2012 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 June 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.

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13. Net Income (Loss) Per Share

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
	(In thousands, except per share data)
Numerator:
Net loss	$	(108,324)	$	(75,192)	$	(167,317)	$	(154,101)
Basic income allocable to participating securities(1)		—		—		—		—
Basic net loss allocable to common shareholders		(108,324)		(75,192)		(167,317)		(154,101)
Diluted adjustments to income allocable to participating securities(1)		—		—		—		—
Diluted net loss allocable to common shareholders	$	(108,324)	$	(75,192)	$	(167,317)	$	(154,101)
Denominator:
Weighted average number of shares outstanding:
Basic		384,918		382,138		384,676		381,238
Restricted stock awards and units(1)(2)		—		—		—		—
Diluted		384,918		382,138		384,676		381,238
Net loss per share:
Basic	$	(0.28)	$	(0.20)	$	(0.43)	$	(0.40)
Diluted	$	(0.28)	$	(0.20)	$	(0.43)	$	(0.40)

(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 12.3 million and 11.4 million for the three months and six months ended June 30, 2016 and 2015, respectively, from the computations of diluted net income per share because the effect would have been anti-dilutive.

14. 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 June 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 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 costs.

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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 June 30, 2016, there was $5.1 million outstanding under the agreement, which is included in other long-term assets.

Future minimum rental commitments under these leases at June 30, 2016, are as follows:


	Payments Due By Year(1)
	Total		2016(2)		2017		2018		2019		2020		Thereafter
	(In thousands)
Operating leases(3)	$	12,913	$	1,805	$	4,127	$	3,820	$	3,161	$	—	$	—
Atwood Achiever drilling rig contract(4)		419,471		83,350		179,521		156,600		—		—		—

(1)

Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts.

(2)

Represents payments for the period from July 1, 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.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and our annual financial statements for the year ended December 31, 2015, included in our annual report on Form 10-K along with the section Management’s Discussion and Analysis of financial condition and Results of Operations contained in such annual report. Any terms used but not defined in the following discussion have the same meaning given to them in the annual report. Our discussion and analysis includes forward-looking statements that involve risks and uncertainties and should be read in conjunction with “Risk Factors” under Item 1A of this report and in the annual report, along with “Forward-Looking Information” at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are 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.

Recent Developments

Corporate

Ghana

Jubilee

In February 2016, the Jubilee Field operator identified an issue with the turret bearing of the FPSO Kwame Nkrumah. This necessitated the FPSO to be shut down for an extended period beginning in March with production resuming in early May. This resulted in the need to implement new operating and offloading procedures on the FPSO, which involves the use of a dynamically positioned (“DP”) shuttle tanker and storage tanker. Since then, over 25 parcels have been successfully offloaded to the DP shuttle tanker and gross production of the field has gradually increased, averaging around 90,000 bopd in June. The operator expects the Jubilee field to continue operating under these new procedures for the remainder of 2016 and anticipates average gross annual production to be around 74,000 bopd for 2016, which equates to average gross production of approximately 85,000 bopd in the second half of 2016.

Kosmos and its Partners have determined the preferred long-term solution to the turret bearing issue is to convert the FPSO to a permanently spread moored facility, with offloading through a new deepwater Catenary Anchor Leg Mooring (“CALM”) buoy. The Partners are now working with the Government of Ghana to seek their approval for this option. The first phase of this work will involve locking the main bearing and the installation of a stern anchoring system to replace the three heading control tugs currently in the field, and this is expected to be complete by the end of 2016 and will require short periods of reduced production. The Partners then plan a second phase of work to allow the FPSO to be rotated to its optimal spread moor heading in the first half of 2017. These phases of work are expected to cost up to $36 million net to Kosmos and it is estimated that the Jubilee FPSO will need to be shut down for 8-12 weeks during the first half of 2017.

Upon completion of the spread mooring work program, production is expected to return to the levels achieved before the turret bearing issue occurred. The Partners will review potential opportunities to improve the efficiency of

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offtake procedures, which may include the use of a larger DP shuttle tanker. The additional operating expenditure is expected to be around $28 million net to Kosmos for 2016 and $25 million net for 2017.

A deepwater CALM buoy, anticipated to be installed in the first half of 2018, is intended to restore full offloading functionality and remove the need for the DP shuttle and storage tankers and associated operating costs. Market inquiries are currently ongoing to estimate the cost and schedule for the fabrication and installation of this buoy.

Kosmos anticipates that the financial impact of lower Jubilee production as well as the additional expenditures associated with the damage to the turret bearing will be mitigated through a combination of the comprehensive Hull and Machinery insurance, procured by the operator, Tullow, on behalf of the partnership, and the Loss of Production Income (“LOPI”) insurance obtained by Kosmos. Claims under both policies have been notified to our insurers.

Tweneboa, Enyenra and Ntomme (“TEN”)

The TEN project is expected to achieve first oil in in August 2016, while remaining on schedule and within budget. A gradual ramp up in oil production towards the TEN FPSO capacity of 80,000 bopd gross (13,600 bopd net to Kosmos) is anticipated around the end of 2016 as the facilities complete performance testing and well production levels are increased to optimal rates. Per operator guidance, average annualized production from TEN in 2016 is expected to be approximately 23,000 bopd gross (3,900 bopd net to Kosmos). Additional drilling is not expected to occur at TEN until after the resolution of the Côte d’Ivoire and Ghana border dispute through the ITLOS tribunal whose decision is expected by late 2017.

Other

In June 2016, Kosmos Energy Ghana HC filed a Request for Arbitration with the International Chamber of Commerce against Tullow Ghana Limited in connection with a dispute arising under the DT Joint Operating Agreement. At dispute is Kosmos Energy Ghana HC’s responsibility for future expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives have concluded. Tullow has indicated it intends to charge such expenditures to the DT joint account. Kosmos disputes that these expenditures are chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement.

Senegal

In May 2016, we announced the Teranga-1 exploration well, located in the Cayar Offshore Profond block made a significant gas discovery. Located approximately 65 kilometers northwest of Dakar in nearly 1,800 meters of water, the Teranga-1 exploration well was drilled to a total depth of 4,485 meters. The well encountered 31 meters (102 feet) of net gas pay in good quality reservoir in the Lower Cenomanian objective. Well results confirm that an inboard gas fairway extends approximately 200 kilometers from the Marsouin-1 well in Mauritania through the Greater Tortue area on the maritime boundary to the Teranga-1 well in Senegal.

Mauritania

In June 2016, we received approval from the Ministry of Petroleum, Energy and Mines of our application to enter the second phase of the exploration period for blocks C8, C12 and C13. In conjunction with our entry into the second phase of the exploration period, we relinquished 25% of the surface area of each block. The second phase of the exploration period carries a 3D seismic requirement of 1,000 square kilometers and a one well drilling obligation for Block C13 and a one well drilling obligation for Block C12. We completed the 3D seismic obligation as well as the well obligation for Block C8 and the 3D seismic obligation for Block C12 during the first exploration period.

In June 2016, Chevron’s 30% non-operated participating interest was formally reassigned to Kosmos. Our participating interest in the Block C8, C12 and C13 petroleum contracts is now 90%.

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Morocco

Suriname

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 will fully fund the cost of acquiring and processing a 6,500 square kilometer 3D seismic survey, subject to a maximum spend, expected to commence in the third quarter of 2016. 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 will be one-third to each of Kosmos, Chevron and Hess, respectively. Kosmos will remain the operator.

In April 2016, we received an extension of the initial exploration phase for Block 45 offshore Suriname which now expires in September 2018. We plan to acquire and process an additional 340 square kilometers of 3D seismic in the block.

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Results of Operations

All of our results, as presented in the table below, represent operations from the Jubilee Field in Ghana. Certain operating results and statistics for the three and six months ended June 30, 2016 and 2015 are included in the following table:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
	(In thousands, except per barrel data)				(In thousands, except per barrel data)
Sales volumes:
MBbl		948		1,946		2,844		3,845

Revenues:
Oil sales	$	45,506	$	119,200	$	107,631	$	228,364
Average sales price per Bbl		48.00		61.26		37.84		59.39

Costs:
Oil production, excluding workovers	$	32,687	$	20,521	$	62,062	$	38,737
Oil production, workovers		(6)		(297)		11		13,587
Total oil production costs	$	32,681	$	20,224	$	62,073	$	52,324

Depletion and depreciation	$	16,927	$	37,532	$	48,193	$	74,539

Average cost per Bbl:
Oil production, excluding workovers	$	34.48	$	10.55	$	21.82	$	10.07
Oil production, workovers		(0.01)		(0.15)		—		3.53
Total oil production costs		34.47		10.40		21.82		13.60

Depletion and depreciation		17.86		19.29		16.95		19.38
Oil production cost and depletion costs	$	52.33	$	29.69	$	38.77	$	32.98

The following table shows the number of wells in the process of being drilled or in active completion stages, and the number of wells suspended or waiting on completion as of June 30, 2016:


	Actively Drilling or				Wells Suspended or
	Completing				Waiting on Completion
	Exploration		Development		Exploration		Development
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Ghana
Jubilee Unit	—	—	—	—	—	—	2	0.48
West Cape Three Points	—	—	—	—	9	2.78	—	—
TEN	—	—	1	0.17	—	—	7	1.19
Deepwater Tano	—	—	—	—	1	0.18	—	—
Mauritania
C8 (1)	—	—	—	—	3	2.70	—	—
Senegal
Saint Louis Offshore Profond	—	—	—	—	1	0.60	—	—
Cayar Profond	—	—	—	—	1	0.60	—	—
Total	—	—	1	0.17	15	6.86	9	1.67

(1)

Chevron has withdrawn from our Mauritania blocks. Chevron’s 30% non-operated participating interest has been reassigned to us, and our participating interests in the Block C8, C12 and C13 petroleum contracts is 90%.

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The discussion of the results of operations and the period-to-period comparisons presented below analyze our historical results. The following discussion may not be indicative of future results.

Three months ended June 30, 2016 compared to three months ended June 30, 2015


	Three Months Ended
	June 30,				Increase
	2016		2015		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	45,506	$	119,200	$	(73,694)
Gain on sale of assets		—		1,900		(1,900)
Other income		170		713		(543)
Total revenues and other income		45,676		121,813		(76,137)
Costs and expenses:
Oil and gas production		32,681		20,224		12,457
Exploration expenses		36,402		14,539		21,863
General and administrative		19,838		41,179		(21,341)
Depletion and depreciation		16,927		37,532		(20,605)
Interest and other financing costs, net		8,878		8,998		(120)
Derivatives, net		54,988		44,877		10,111
Other expenses, net		(170)		4,266		(4,436)
Total costs and expenses		169,544		171,615		(2,071)
Loss before income taxes		(123,868)		(49,802)		(74,066)
Income tax expense (benefit)		(15,544)		25,390		(40,934)
Net loss	$	(108,324)	$	(75,192)	$	(33,132)

Oil and gas revenue. Oil and gas revenue decreased by $73.7 million as a result of one cargo during the three months ended June 30, 2016 impacted by the turret bearing issue, compared to two cargos during the three months ended June 30, 2015 and a lower realized price per barrel in 2016. We lifted and sold 948 MBbl at an average realized price per barrel of $48.00 during the three months ended June 30, 2016 and 1,946 MBbl at an average realized price per barrel of $61.26 during the three months ended June 30, 2015.

Oil and gas production. Oil and gas production costs increased by $12.5 million during the three months ended June 30, 2016, as compared to the three months ended June 30, 2015 as a result of an increase in operating costs related to our overlift position and limited production as well as additional costs related to the turret bearing issue during the three months ended June 30, 2016.

Exploration expenses. Exploration expenses increased by $21.9 million during the three months ended June 30, 2016, as compared to the three months ended June 30, 2015. The increase is primarily a result of $16.4 million of stacked rig costs associated with the Atwood Achiever in 2016 and an increase in seismic costs and geological and geophysical costs of $5.5 million.

General and administrative. General and administrative costs decreased by $21.3 million during the three months ended June 30, 2016, as compared with the three months ended June 30, 2015. The decrease is primarily a result of a decrease in non-cash stock-based compensation, professional fees and an increase in capitalized general and administrative costs.

Depletion and depreciation. Depletion and depreciation decreased $20.6 million during the three months ended June 30, 2016, as compared with the three months ended June 30, 2015. The decrease is primarily a result of lower depletion recognized related to the sale of only one cargo of oil during the three months ended June 30, 2016, as compared to two cargos during the three months ended June 30, 2015. In addition, the depletion rate is lower during the three months ended June 30, 2016 as a result of an increase in proved reserves associated with the Jubilee Field in the fourth quarter of 2015.

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Derivatives, net. During the three months ended June 30, 2016 and 2015, we recorded losses of $55.0 million and $44.9 million, respectively, on our outstanding hedge positions. The losses recorded were a result of changes in the forward curve of oil prices during the respective periods.

Other expenses, net. Other expenses, net decreased by $4.4 million during the three months ended June 30, 2016, as compared to the three months ended June 30, 2015 as a result of a $4.2 million write-off related to a damaged riser during the three months ended June 30, 2015.

Income tax expense (benefit). The Company’s effective tax rates for the three months ended June 30, 2016 and 2015 were a tax benefit of 13% and tax expense of 51%, respectively. The effective tax rates for the periods presented were impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such expenses or losses. Beginning with the three months ended June 30, 2016 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 under insurance. Any insurance recoveries received would not be subject to income tax. Income tax expense decreased $40.9 million during the three months ended June 30, 2016, as compared with June 30, 2015, primarily as a result of lower revenue in Ghana.

Six months ended June 30, 2016 compared to six months ended June 30, 2015


	Six Months Ended
	June 30,				Increase
	2016		2015		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	107,631	$	228,364	$	(120,733)
Gain on sale of assets		—		24,651		(24,651)
Other income		178		1,355		(1,177)
Total revenues and other income		107,809		254,370		(146,561)
Costs and expenses:
Oil and gas production		62,073		52,324		9,749
Exploration expenses		60,260		113,480		(53,220)
General and administrative		37,758		79,846		(42,088)
Depletion and depreciation		48,193		74,539		(26,346)
Interest and other financing costs, net		19,202		19,749		(547)
Derivatives, net		50,643		12,550		38,093
Other expenses, net		14,563		4,894		9,669
Total costs and expenses		292,692		357,382		(64,690)
Loss before income taxes		(184,883)		(103,012)		(81,871)
Income tax expense		(17,566)		51,089		(68,655)
Net loss	$	(167,317)	$	(154,101)	$	(13,216)

Oil and gas revenue. Oil and gas revenue decreased by $120.7 million as a result of three cargos during the six months ended June 30, 2016 impacted by the turret bearing issue, compared to four cargos during the six months ended June 30, 2015 and a lower realized price per barrel in 2016. We lifted and sold 2,844 MBbl at an average realized price per barrel of $37.84 during the six months ended June 30, 2016 and 3,845 MBbl at an average realized price per barrel of $59.39 during the six months ended June 30, 2015.

Gain on sale of assets. During the six months ended June 30, 2015, we closed a farm‑out agreement with Chevron. The proceeds from the sale were in excess of our book basis, resulting in a gain of $24.7 million.

Oil and gas production. Oil and gas production costs increased by $9.7 million during the six months ended June 30, 2016, as compared to the six months ended June 30, 2015 as a result of increased operating costs related to our overlift position and limited production as well as additional costs related to the turret bearing issue during 2016 offset by decreased workover costs, which are performed on an as needed basis. We expect the amount of costs associated with workovers to fluctuate based on the activity level during each quarter.

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Exploration expenses. Exploration expenses decreased by $53.2 million during the six months ended June 30, 2016, as compared to the six months ended June 30, 2015. The decrease is primarily a result of $86.7 million of unsuccessful well costs for the Western Sahara CB-1 exploration well in 2015 offset by $16.4 million of stacked rig costs and a $14.7 million increase in seismic and geological and geophysical costs.

General and administrative. General and administrative costs decreased by $42.1 million during the six months ended June 30, 2016, as compared with the six months ended June 30, 2015. The decrease is primarily a result of a decrease in non-cash stock-based compensation, operator costs and professional fees and an increase in capitalized general and administrative costs.

Depletion and depreciation. Depletion and depreciation decreased $26.3 million during the six months ended June 30, 2016, as compared with the six months ended June 30, 2015. The decrease is primarily a result of depletion recognized related to the sale of three cargos of oil during the six months ended June 30, 2016, as compared to four cargos during the six months ended June 30, 2015. In addition, the depletion rate is lower during the three months ended June 30, 2016 as a result of an increase in proved reserves associated with the Jubilee Field in the fourth quarter of 2015.

Derivatives, net. During the six months ended June 30, 2016 and 2015, we recorded losses of $50.6 million and $12.6 million, respectively, on our outstanding hedge positions. The losses recorded were a result of changes in the forward curve of oil prices during the respective periods.

Other expenses, net. Other expenses, net increased by $9.7 million during the six months ended June 30, 2016, as compared to the six months ended June 30, 2015 primarily related to an impairment of inventory of $15.2 million during the six months ended June 30, 2016, offset by a $4.2 million write-off related to a damaged riser during the six months ended June 30, 2015.

Income tax expense (benefit). The Company’s effective tax rates for the six months ended June 30, 2016 and 2015 were a tax benefit of 10% and tax expense of 50%, respectively. The effective tax rates for the periods presented were impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such expenses or losses. Beginning with the three months ended June 30, 2016, 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 under insurance. Any insurance recoveries received would not be subject to income tax. Income tax expense decreased $68.7 million during the six months ended June 30, 2016, as compared with June 30, 2015, primarily as a result of lower revenue in Ghana.

Liquidity and Capital Resources

We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to exploring for and developing oil and natural gas resources along the Atlantic Margin. We have historically met our funding requirements through cash flows generated from our operating activities and obtained additional funding from issuances of equity and debt. In relation to cash flow generated from our operating activities, if we are unable to continuously export associated natural gas in large quantities from the Jubilee Field, and the potential production restraints caused thereby, then the Company’s cash flows from operations will be adversely affected. In prior years, certain near wellbore productivity issues were identified, impacting several Phase 1 production wells. The Jubilee Unit partners identified and implemented a means of successfully mitigating such past near wellbore productivity issues. We have also experienced mechanical issues in the Jubilee Field, including failures of our water injection facilities and gas compressor on the FPSO, as well as the current Jubilee turret bearing issue. This equipment downtime negatively impacted past oil production and we are in the process of correcting the current mechanical issues experienced in the Jubilee Field.

While we are presently in a strong financial position, the decline in oil prices experienced since 2014, if prolonged or if further deterioration of pricing occurs, could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements as well as impact the borrowing base available under the Facility or the related debt covenants. Commodity prices are volatile and future prices cannot be accurately predicted. We maintain a hedging program to partially mitigate the price volatility. Our investment decisions are based on longer-term commodity prices based on the long-term nature of our projects and development plans. Current commodity prices, our

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hedging program and our current liquidity position support our capital program for 2016. As such, our 2016 capital budget is based on our development plans for Ghana and our exploration and appraisal program for 2016.

Our future financial condition and liquidity will be impacted by, among other factors, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the reliability of our oil and gas production facilities, our ability to continuously export oil and gas, our partners alignment with respect to capital plans, and the actual cost of exploration, appraisal and development of our oil and natural gas assets.

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents for the six months ended June 30, 2016 and 2015:


	Six Months Ended
	June 30,
	2016		2015
	(In thousands)
Sources of cash and cash equivalents:
Net cash provided by (used in) activities	$	(24,078)	$	83,453
Net proceeds from issuance of senior secured notes		—		206,774
Borrowings under long-term debt		325,000		—
Proceeds on sale of assets		196		28,603
		301,118		318,830
Uses of cash and cash equivalents:
Oil and gas assets	$	417,704	$	384,194
Other property		601		536
Payments on long-term debt		—		200,000
Purchase of treasury stock		1,798		17,955
Deferred financing costs		—		8,791
Restricted cash		43,202		9,574
		463,305		621,050
Decrease in cash and cash equivalents	$	(162,187)	$	(302,220)

Net cash provided by (used in) operating activities. Net cash used in operating activities for the six months ended June 30, 2016 was $24.1 million compared with net cash provided by operating activities for the six months ended June 30, 2015 of $83.5 million. The decrease in cash provided by operating activities in the six months ended June 30, 2016 when compared to the same period in 2015 is primarily a result of a decrease in results from operations driven by lower barrels sold related to the turret bearing issue and lower realized revenue per barrel sold.

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The following table presents our net debt and liquidity as of June 30, 2016:


	June 30, 2016
	(In thousands)
Cash and cash equivalents	$	112,817
Restricted cash		79,060
Senior Notes at par		525,000
Drawings under the Facility		725,000
Net debt	$	1,058,123

Availability under the Facility	$	701,500
Availability under the Corporate Revolver	$	400,000
Available borrowings plus cash and cash equivalents	$	1,214,317

Capital Expenditures and Investments

We expect to incur substantial costs as we:

complete the TEN development and fund asset integrity projects at Jubilee;

execute exploration and appraisal activities in our Senegal and Mauritania license areas; and

purchase and analyze seismic, evaluate new ventures and manage our rig activities.

We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells we plan to drill, our participating interests in our prospects including disproportionate payment amounts, the costs involved in developing or participating in the development of a prospect, the timing of third-party projects, our ability to utilize our available drilling rig capacity, the availability of suitable and reliable equipment and qualified personnel and our cash flows from operations. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if market conditions deteriorate; or one or more of our assumptions proves to be incorrect or if we choose to expand our acquisition, exploration, appraisal, development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could result in dilution to our shareholders. The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations.

2016 Capital Program

We estimate we will spend approximately $650 million of capital for the year ending December 31, 2016. Through June 30, 2016, we have spent approximately $434 million of the capital budget, which is front-end loaded in the first half of the year based on all of our drilling activity being completed by June 2016.

This positions us to achieve our objectives and invest counter-cyclically while maintaining a strong balance sheet. The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our drilling results among other factors. Given the status of ongoing prospect development, we suspended Kosmos operated drilling activities after the completion of the Teranga-1 exploration well offshore Senegal at the end of May 2016.

Significant Sources of Capital

Facility

In March 2014, we amended and restated the commercial debt facility (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.

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We were in compliance with the financial covenants contained in the Facility as of March 31, 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. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration; appraisal and development programs.

As of June 30, 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 March 31, 2016 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.

Revolving Letter of Credit Facility

7.875% Senior Secured Notes due 2021

During August 2014, we 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 Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued.

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Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of June 30, 2016:


	Payments Due By Year(5)
	Total		2016(6)		2017		2018		2019		2020		Thereafter
	(In thousands)
Principal debt repayments(1)	$	1,250,000	$	—	$	—	$	—	$	207,271	$	348,123	$	694,606
Interest payments on long-term debt(2)		388,260		43,074		85,405		82,110		71,840		61,339		44,492
Operating leases(3)		12,913		1,805		4,127		3,820		3,161		—		—
Atwood Achiever drilling rig contract(4)		419,471		83,350		179,521		156,600		—		—		—

(1)

(2)

Based on outstanding borrowings as noted in (1) above and the LIBOR yield curves at the reporting date and commitment fees related to the Facility and Corporate Revolver and the interest on the Senior Notes.

(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. 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 costs.

(5)

(6)

Represents payments for the period from July 1, 2016 through December 31, 2016.

We currently have 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.

The following table presents maturities by expected debt maturity dates, the weighted average interest rates expected to be paid on the Facility given current contractual terms and market conditions, and the debt’s estimated fair

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value. Weighted-average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not take into account amortization of deferred financing costs.


																			Liability
	July 1																		Fair Value
	Through																		at
	December 31,			Years Ending December 31,															June 30,
	2016			2017			2018			2019			2020			Thereafter			2016
				(In thousands, except percentages)
Fixed rate debt:
Senior Notes	$	—		$	—		$	—		$	—		$	—		$	525,000		$	(507,938)
Fixed interest rate		7.88	%		7.88	%		7.88	%		7.88	%		7.88	%		7.88	%
Variable rate debt:
Facility(1)	$	—		$	—		$	—		$	207,271		$	348,123		$	169,606		$	(725,000)
Weighted average interest rate(2)		3.76	%		3.87	%		4.41	%		4.65	%		5.27	%		5.67	%
Capped interest rate swaps:
Notional debt amount	$	200,000		$	200,000		$	200,000		$	—		$	—		$	—		$	(3,076)
Cap		3.00	%		3.00	%		3.00	%		—			—			—
Average fixed rate payable(3)		1.23	%		1.23	%		1.23	%		—			—			—
Variable rate receivable(4)		0.47	%		0.55	%		0.72	%		—			—			—

(1)

The amounts included in the table represent principal maturities only. The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of June 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 June 30, 2016, there were no borrowings under the Corporate Revolver.

(2)

Based on outstanding borrowings as noted in (1) above and the LIBOR yield curves plus applicable margin at the reporting date. Excludes commitment fees related to the Facility and Corporate Revolver.

(3)

We expect to pay the fixed rate if 1-month LIBOR is below the cap, and pay the market rate less the spread between the cap and the fixed rate if LIBOR is above the cap, net of the capped interest rate swaps.

(4)

Based on implied forward rates in the yield curve at the reporting date.

Off-Balance Sheet Arrangements

As of June 30, 2016, our material off-balance sheet arrangements and transactions include operating leases and undrawn letters of credit. There are no other transactions, arrangements, or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect Kosmos’ liquidity or availability of or requirements for capital resources.

Critical Accounting Policies

We consider accounting policies related to our revenue recognition, exploration and development costs, receivables, income taxes, derivative instruments and hedging activities, estimates of proved oil and natural gas reserves, asset retirement obligations and impairment of long-lived assets as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations section in our annual report on Form 10-K, for the year ended December 31, 2015.

Cautionary Note Regarding Forward-looking Statements

This quarterly report on Form 10-Q contains estimates and forward-looking statements, principally in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our estimates and forward-looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward-looking statements

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are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in our quarterly report on Form 10-Q and our annual report on Form 10-K, may adversely affect our results as indicated in forward-looking statements. You should read this quarterly report on Form 10-Q, the annual report on Form 10-K and the documents that we have filed with the Securities and Exchange Commission completely and with the understanding that our actual future results may be materially different from what we expect. Our estimates and forward-looking statements may be influenced by the following factors, among others:

our ability to find, acquire or gain access to other discoveries and prospects and to successfully develop and produce from our current discoveries and prospects;

uncertainties inherent in making estimates of our oil and natural gas data;

the successful implementation of our and our block partners’ prospect discovery and development and drilling plans;

projected and targeted capital expenditures and other costs, commitments and revenues;

termination of or intervention in concessions, rights or authorizations granted by the governments of Ghana, Mauritania, Morocco (including Western Sahara), Portugal, Sao Tome and Principe, Senegal or Suriname (or their respective national oil companies) or any other federal, state or local governments or authorities, to us;

our dependence on our key management personnel and our ability to attract and retain qualified technical personnel;

the ability to obtain financing and to comply with the terms under which such financing may be available;

the volatility of oil and natural gas prices;

the availability, cost, function and reliability of developing appropriate infrastructure around and transportation to our discoveries and prospects;

the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;

other competitive pressures;

potential liabilities inherent in oil and natural gas operations, including drilling and production risks and other operational and environmental risks and hazards;

current and future government regulation of the oil and gas industry or regulation of the investment in or ability to do business with certain countries or regimes;

cost of compliance with laws and regulations;

changes in environmental, health and safety or climate change or greenhouse gas (“GHG”) laws and regulations or the implementation, or interpretation, of those laws and regulations;

adverse effects of sovereign boundary disputes in the jurisdictions in which we operate, including an ongoing maritime boundary demarcation dispute between Cote d’Ivoire and Ghana impacting our operations in the Deepwater Tano Block offshore Ghana;

environmental liabilities;

geological, technical, drilling, production and processing problems;

the failure of machinery and equipment necessary for the reliable production of oil and natural gas;

military operations, civil unrest, outbreaks of disease, terrorist acts, wars or embargoes;

the cost and availability of adequate insurance coverage and whether such coverage is enough to sufficiently mitigate potential losses and whether our insurers comply with their obligations under our coverage agreements;

our vulnerability to severe weather events;

our ability to meet our obligations under the agreements governing our indebtedness;

the availability and cost of financing and refinancing our indebtedness;

the amount of collateral required to be posted from time to time in our hedging transactions, letters of credit and other secured debt;

the result of any legal proceedings, arbitrations, or investigations we may be subject to or involved in;

our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; and

other risk factors discussed in the “Item 1A. Risk Factors” section of this quarterly report on Form 10-Q and our annual report on Form 10-K.

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The words “believe,” “may,” “will,” “aim,” “estimate,” “continue,” “anticipate,” “intend,” “expect,” “plan” and similar words are intended to identify estimates and forward-looking statements. Estimates and forward-looking statements speak only as of the date they were made, and, except to the extent required by law, we undertake no obligation to update or to review any estimate and/or forward-looking statement because of new information, future events or other factors. Estimates and forward-looking statements involve risks and uncertainties and are not guarantees of future performance. As a result of the risks and uncertainties described above, the estimates and forward-looking statements discussed in this quarterly report on Form 10-Q might not occur, and our future results and our performance may differ materially from those expressed in these forward-looking statements due to, including, but not limited to, the factors mentioned above. Because of these uncertainties, you should not place undue reliance on these forward-looking statements.

Item 3. Qualitative and Quantitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risks” as it relates to our currently anticipated transactions refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage ongoing market risk exposures. We enter into market-risk sensitive instruments for purposes other than to speculate.

We manage market and counterparty credit risk in accordance with our policies. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8. Financial Statements and Supplementary Data — Note 2 — Accounting Policies, Note 9 — Derivative Financial Instruments and Note 10 — Fair Value Measurements” section of our annual report on Form 10-K for a description of the accounting procedures we follow relative to our derivative financial instruments.

The following table reconciles the changes that occurred in fair values of our open derivative contracts during the six months ended June 30, 2016:


	Derivative Contracts Assets (Liabilities)
	Commodities		Interest Rates		Total
	(In thousands)
Fair value of contracts outstanding as of December 31, 2015	$	237,641	$	(496)	$	237,145
Changes in contract fair value		(51,699)		(3,476)		(55,175)
Contract maturities		(100,711)		896		(99,815)
Fair value of contracts outstanding as of June 30, 2016	$	85,231	$	(3,076)	$	82,155

Commodity Price Risk

The Company’s revenues, earnings, cash flows, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, which have historically been very volatile. Our oil sales are indexed against Dated Brent crude. Oil prices during the six months ended June 30, 2016 ranged between $25.99 and $50.72.

Commodity Derivative Instruments

We enter into various oil derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future oil production. These contracts currently consist of three-way collars, put options, call options and swaps. In regards to our obligations under our various commodity derivative instruments, if our production does not exceed our existing hedged positions, our exposure to our commodity derivative instruments would increase.

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Commodity Price Sensitivity

The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of June 30, 2016:


			Weighted Average Dated Brent Price per Bbl												Asset (Liability)
			Deferred												Fair Value at
			Premium												June 30,
Term	Type of Contract	MBbl	Payable		Swap		Sold Put		Floor		Ceiling		Call		2016(2)
2016:
July — December	Purchased puts	1,002	$	3.41	$	—	$	—	$	85.00	$	—	$	—	$	31,891
July — December	Three-way collars	1,005		—		—		—		85.00		110.00		135.00		35,417
July — December	Swaps with puts	1,000		—		75.00		60.00		—		—		—		14,240
2017:
January — December	Swap with puts/calls	2,000	$	2.13	$	72.50	$	55.00	$	—	$	—	$	90.00	$	18,938
January — December	Swap with puts	2,000		—		64.95		50.00		—		—		—		12,324
January — December	Sold calls(1)	2,000		—		—		—		—		85.00		—		(1,057)
January — December	Three-way collars	4,000		1.72		—		30.00		45.00		57.50		—		(14,875)
2018:
January — December	Three-way collars	913	$	2.37	$	—	$	45.00	$	60.00	$	75.00	$	—	$	1,472
January — December	Sold calls(1)	2,000		—		—		—		—		65.00		—		(9,887)
2019:
January — December	Sold calls(1)	913	$	—	$	—	$	—	$	—	$	80.00	$	—	$	(3,232)

(1)

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

(2)

Fair values are based on the average forward Dated Brent oil prices on June 30, 2016 which by year are: 2016 — $49.70, 2017 — $52.74 2018 — $55.31 and 2019 — $56.86. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on August 1, 2016 market quotes by year are: 2016 — $41.78, 2017 — $45.81, 2018 — $49.50 and 2019 — $51.82.

At June 30, 2016, our open commodity derivative instruments were in a net asset position of $85.2 million. As of June 30, 2016, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $50.0 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $43.6 million.

Interest Rate Derivative Instruments

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations” section of our annual report on Form 10-K for specific information regarding the terms of our interest rate derivative instruments that are sensitive to changes in interest rates.

Interest Rate Sensitivity

At June 30, 2016, we had indebtedness outstanding under the Facility of $725.0 million, of which $525.0 million bore interest at floating rates after consideration of our fixed rate interest rate hedges. The interest rate on this indebtedness as of June 30, 2016 was approximately 3.7%. If LIBOR increased by 10% at this level of floating rate debt, we would pay an additional $0.2 million in interest expense per year on the Facility. We pay commitment fees on the $701.5 million of undrawn availability and $73.5 million of unavailable commitments under the Facility and on the $400.0 million of undrawn availability under the Corporate Revolver, which are not subject to changes in interest rates.

As of June 30, 2016, the fair market value of our interest rate swaps was a net liability of approximately $3.1 million. If LIBOR changed by 10%, it would have a negligible impact on the fair market value of our interest rate swaps.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. However, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2016, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure.

Evaluation of Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Apart from the proceeding, there have been no material changes from the information concerning legal proceedings discussed in the “Item 3. Legal Proceedings” section of our annual report on Form 10-K.

Item 1A. Risk Factors

There have been no material changes from the risks discussed in the “Item 1A. Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2015.

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

Under the terms of our Long Term Incentive Plan (“LTIP”), we have issued restricted shares and restricted share units to our employees. On the date that these restricted shares and restricted share units vest, we provide such employees the option to withhold, via a net exercise provision pursuant to our applicable restricted share award agreements and the LTIP, either the number of vested shares (based on the closing price of our common shares on such vesting date) equal to the minimum statutorily tax liability owed by such grantee or up to the maximum statutory tax liability for such grantee. The shares withheld from the grantees to settle their tax liability are reallocated to the number of shares available for issuance under the LTIP. The following table outlines the total number of shares withheld during the six months ended, June 30, 2016 and the average price paid per share.


	Total Number	Average
	of Shares	Price Paid
	Withheld/Purchased	per Share
	(In thousands)
January 1, 2016—January 31, 2016	79	$	5.20
February 1, 2016—February 29, 2016	14		4.32
March 1, 2016—March 31, 2016	4		4.92
April 1, 2016—April 30, 2016	9		5.56
May 1, 2016—May 31, 2016	5		6.48
June 1, 2016—June 30, 2016	17		5.60
Total	128		5.22

Item 3.Defaults Upon Senior Securities

None.

Item 4.Mine Safety Disclosures

Not applicable.

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Item 5.Other Information.

There have been no material changes required to be reported under this Item that have not previously been disclosed in the annual report on Form 10-K, other than as follows:

Disclosures Required Pursuant to Section 13(r) of the Securities Exchange Act of 1934

Under the Iran Threat Reduction and Syria Human Rights Act of 2012, which added Section 13(r) of the Exchange Act, we are required to include certain disclosures in our periodic reports if we or any of our “affiliates” (as defined in Rule 12b-2 under the Exchange Act) knowingly engaged in certain specified activities during the period covered by the report. Because the Securities and Exchange Commission (“SEC”) defines the term “affiliate” broadly, it includes any entity controlled by us as well as any person or entity that controls us or is under common control with us (“control” is also construed broadly by the SEC).

We are not presently aware that we and our consolidated subsidiaries have knowingly engaged in any transaction or dealing reportable under Section 13(r) of the Exchange Act during the fiscal quarter ended June 30, 2016. In addition, except as described below, at the time of filing this quarterly report on Form 10-Q, we are not aware of any such reportable transactions or dealings by companies that may be considered our affiliates as to whether they have knowingly engaged in any such reportable transactions or dealings during such period. Upon the filing of periodic reports by such other companies for the fiscal quarter or fiscal year ended June 30, 2016, as the case may be, additional reportable transactions may be disclosed by such companies.

As of June 30, 2016, funds affiliated with The Blackstone Group (“Blackstone”) held approximately 25% of our outstanding common shares, and funds affiliated with Warburg Pincus (“Warburg Pincus”) held approximately 31% of our outstanding common shares. We are also a party to a shareholders agreement with Blackstone and Warburg Pincus pursuant to which, among other things, Blackstone and Warburg Pincus each currently has the right to designate three members of our board of directors. Accordingly, each of Blackstone and Warburg Pincus may be deemed an “affiliate” of us, both currently and during the fiscal quarter ended June 30, 2016.

Disclosure relating to Blackstone and its affiliates

Blackstone informed us of the information produced below (the “NCR Disclosure”) regarding NCR Corporation (“NCR”). NCR may be considered an affiliate of Blackstone, and because we and NCR may be deemed to be controlled by Blackstone, we may be considered an “affiliate” of NCR for the purposes of Section 13(r) of the Exchange Act.

NCR Disclosure:

Quarter ended June 30, 2016

“Pursuant to Section 13(r)(1)(D)(iii) of the Securities Exchange Act of 1934, as amended, we note that, during the period from April 1, 2016 through April 30, 2016, we continued to maintain a bank account and guarantees at the Commercial Bank of Syria (“CBS”), which was designated as a Specially Designated National pursuant to Executive Order 13382 (“EO 13382”) on August 10, 2011. This bank account and the guarantees at CBS were maintained in the normal course of business prior to the listing of CBS pursuant to EO 13382. We note that the last known account balance as of April 30, 2016 was approximately $3,468. The bank account did not generate interest from April 1, 2016 through April 30, 2016, and the guarantees did not generate any revenue or profits for the Company. Pursuant to a license granted to the Company by OFAC on January 3, 2013, and subsequent licenses granted on April 29, 2013, July 12, 2013, February 28, 2014, November 12, 2014, and October 24, 2015, the Company had been engaged in winding down its past operations in Syria. The Company’s last such license expired on April 30, 2016. In addition, the Company’s application to renew its license to transact business with CBS, which was submitted to OFAC on May 18, 2015, was not acted upon prior to the expiration of the Company’s last such license. As a result, and in connection with the license expiration, the Company abandoned its remaining property in Syria, which, including the CBS account, was commercially insignificant, and ended the employment of its final two employees in Syria, who had remained employed

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by the Company to assist with the execution of the Company’s wind-down activities pursuant to authority granted by the OFAC licenses. The Company does not intend to engage in any further business activities with CBS.”

The NCR Disclosure relates solely to activities conducted by NCR and do not relate to any activities conducted by us. We have no involvement in or control over the activities of NCR, any of its predecessor companies or any of its subsidiaries. Other than as described above, we have no knowledge of the activities of NCR with respect to transactions with Iran, and we have not participated in the preparation of the NCR Disclosure. We have not independently verified the NCR Disclosure, are not representing to the accuracy or completeness of the NCR Disclosure and undertake no obligation to correct or update the NCR Disclosure.

Disclosure relating to Warburg Pincus and its affiliates

Warburg Pincus informed us of the information reproduced below (the “SAMIH Disclosure”) regarding Santander Asset Management Investment Holdings Limited (“SAMIH”). SAMIH is a company that may be considered an affiliate of Warburg Pincus. Because we and SAMIH may be deemed to be controlled by Warburg Pincus, we may be considered an “affiliate” of SAMIH for the purposes of Section 13(r) of the Exchange Act.

SAMIH Disclosure:

Quarter ended June 30, 2016

“Santander UK plc (“Santander UK”) holds two frozen savings accounts and two frozen current accounts for three customers resident in the United Kingdom (“UK”) who are currently designated by the United States (“US”) under the Specially Designated Global Terrorist (“SDGT”) sanctions program. The accounts held by each customer were blocked after the customer’s designation and have remained blocked and dormant through the first half of 2016. Revenue generated by Santander UK on these accounts in the first half of 2016 was £7.31 whilst net profits in the first half of 2016 were negligible relative to the overall profits of Banco Santander, S.A.

An Iranian national, resident in the UK, who is currently designated by the US under the Iranian Financial Sanctions Regulations (“IFSR”) and the Weapons of Mass Destruction Proliferators Sanctions Regulations, held a mortgage with Santander UK that was issued prior to any such designation. The mortgage account was redeemed and closed on April 13, 2016. No further drawdown has been made (or would be allowed) under this mortgage although Santander UK continued to receive repayment installments prior to redemption. In the first half of 2016, total revenue generated by Santander UK in connection with the mortgage was £434.64 whilst net profits were negligible relative to the overall profits of Banco Santander SA. Santander UK does not intend to enter into any new relationships with this customer, and any disbursements will only be made in accordance with applicable sanctions. The same Iranian national also held two investment accounts with Santander ISA Managers Limited. The funds within both accounts were invested in the same portfolio fund. The accounts remained frozen until the investments were closed on May 12, 2016 and checks issued to customer on May 13, 2016. Total revenue in the first half of 2016 generated by Santander UK in connection with the investment accounts was £7.60 whilst net profits in the first half of 2016 were negligible relative to the overall profits of Banco Santander SA.

A UK national designated by the US under the SDGT sanctions program holds a Santander UK current account. The account remained in arrears through the first half of 2016 (£1,344.01 in debit) and is currently being managed by Santander UK Collections & Recoveries department.

In addition, during the first half of 2016, Santander UK has identified an OFAC match on a power of attorney account. A party listed on the account is currently designated by the US under the SDGT and IFSR sanctions programs. During the first half of 2016, related revenue generated by Santander UK was £129.21 whilst net profits in the first half of 2016 were negligible relative to the overall profits of Banco Santander SA.”

The SAMIH Disclosure relates solely to activities conducted by SAMIH and do not relate to any activities conducted by us. We have no involvement in or control over the activities of SAMIH, any of its predecessor companies or any of its subsidiaries. Other than as described above, we have no knowledge of the activities of SAMIH with respect to transactions with Iran, and we have not participated in the preparation of the SAMIH Disclosure. We have not independently verified the SAMIH Disclosure, are not representing to the accuracy or completeness of the SAMIH Disclosure and undertake no obligation to correct or update the SAMIH Disclosure.

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Item 6. Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		Kosmos Energy Ltd.
		(Registrant)

Date	August 8, 2016	/s/ THOMAS P. CHAMBERS
		Thomas P. Chambers
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

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INDEX OF EXHIBITS


Exhibit Number		Description of Document
31.1*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith.

** Furnished herewith.