Edgar Filing: Kosmos Energy Ltd.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2015

o 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 x No o

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 x No o

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 x		Accelerated filer o

Non-accelerated filer o		Smaller reporting company o
(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 o No x

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 July 27, 2015
Common Shares, $0.01 par value		387,407,506

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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, 2015 and December 31, 2014	6
Consolidated Statements of Operations for the three and six months ended June 30, 2015 and 2014	7
Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2015 and 2014	8
Consolidated Statements of Shareholders’ Equity for the six months ended June 30, 2015	9
Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014	10
Notes to Consolidated Financial Statements	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3. Quantitative and Qualitative Disclosures about Market Risk	35
Item 4. Controls and Procedures	36

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	38
Item 1A. Risk Factors	38
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3. Defaults Upon Senior Securities	38
Item 4. Mine Safety Disclosures	38
Item 5. Other Information	38
Item 6. Exhibits	40
Signatures	40
Index to Exhibits	41

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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.

“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, (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.

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“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.

“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.

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“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.

“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 and/or natural gas 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 oil and/or natural gas 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,
	2015			2014
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	252,611		$	554,831
Restricted cash	31,500			15,926
Receivables:
Joint interest billings	54,569			60,592
Oil sales	59,338			61,731
Other	30,515			41,221
Inventories	70,078			55,354
Prepaid expenses and other	19,024			25,278
Deferred tax assets	8,160			32,268
Derivatives	110,674			163,275
Total current assets	636,469			1,010,476

Property and equipment:
Oil and gas properties, net	1,950,873			1,773,186
Other property, net	9,808			11,660
Property and equipment, net	1,960,681			1,784,846

Other assets:
Restricted cash	10,125			16,125
Long-term receivables – joint interest billings	24,922			14,174
Deferred financing costs, net of accumulated amortization of $37,788 and $33,389 at June 30, 2015 and December 31, 2014, respectively	52,300			48,753
Long-term deferred tax assets	12,515			9,182
Derivatives	44,251			89,210
Total assets	$	2,741,263		$	2,972,766

Liabilities and shareholders’ equity
Current liabilities:
Accounts payable	$	149,719		$	184,400
Accrued liabilities	110,006			201,967
Deferred tax liability	43,316			61,683
Derivatives	924			721
Total current liabilities	303,965			448,771

Long-term liabilities:
Long-term debt	798,543			794,269
Derivatives	7,574			68
Asset retirement obligations	47,854			44,023
Deferred tax liability	358,569			337,961
Other long-term liabilities	9,565			8,715
Total long-term liabilities	1,222,105			1,185,036

Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at June 30, 2015 and December 31, 2014	—			—
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 393,742,864 and 392,443,048 issued at June 30, 2015 and December 31, 2014, respectively	3,937			3,924
Additional paid-in capital	1,906,718			1,860,190
Accumulated deficit	(648,951		)	(494,850		)
Accumulated other comprehensive income	378			767
Treasury stock, at cost, 8,797,511 and 5,555,088 shares at June 30, 2015 and December 31, 2014, respectively	(46,889		)	(31,072		)
Total shareholders’ equity	1,215,193			1,338,959
Total liabilities and shareholders’ equity	$	2,741,263		$	2,972,766

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
Revenues and other income:
Oil and gas revenue	$	119,200		$	328,297	$	228,364		$	541,150
Gain on sale of assets	1,900			—		24,651			23,769
Other income	713			869		1,355			1,308

Total revenues and other income	121,813			329,166		254,370			566,227

Costs and expenses:
Oil and gas production	20,224			22,946		52,324			39,269
Exploration expenses	14,539			23,509		113,480			36,318
General and administrative	41,179			32,480		79,846			59,893
Depletion and depreciation	37,532			69,546		74,539			115,924
Interest and other financing costs, net	8,998			9,998		19,749			19,135
Derivatives, net	44,877			21,566		12,550			19,538
Restructuring charges	—			11,804		—			11,804
Other expenses, net	4,266			26		4,894			1,303

Total costs and expenses	171,615			191,875		357,382			303,184

Income (loss) before income taxes	(49,802		)	137,291		(103,012		)	263,043
Income tax expense	25,390			80,784		51,089			131,567

Net income (loss)	$	(75,192	)	$	56,507	$	(154,101	)	$	131,476

Net income (loss) per share:
Basic	$	(0.20	)	$	0.15	$	(0.40	)	$	0.34
Diluted	$	(0.20	)	$	0.15	$	(0.40	)	$	0.34

Weighted average number of shares used to compute net income (loss) per share:
Basic	382,138			378,820		381,238			378,327
Diluted	382,138			381,818		381,238			381,157

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014

Net income (loss)	$	(75,192	)	$	56,507		$	(154,101	)	$	131,476
Other comprehensive loss:
Reclassification adjustments for derivative gains included in net income (loss)	(195		)	(405		)	(389		)	(811		)
Other comprehensive loss	(195		)	(405		)	(389		)	(811		)
Comprehensive income (loss)	$	(75,387	)	$	56,102		$	(154,490	)	$	130,665

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands)

(Unaudited)

	Common Shares			Additional Paid-in			Accumulated			Accumulated Other Comprehensive			Treasury
	Shares	Amount		Capital			Deficit			Income			Stock			Total
Balance as of December 31, 2014	392,443	$	3,924	$	1,860,190		$	(494,850	)	$	767		$	(31,072	)	$	1,338,959
Equity-based compensation	—	—		48,679			—			—			—			48,679
Derivatives, net	—	—		—			—			(389		)	—			(389		)
Restricted stock awards and units	1,300	13		(13		)	—			—			—			—
Restricted stock forfeitures	—	—		15			—			—			(15		)	—
Purchase of treasury stock	—	—		(2,153		)	—			—			(15,802		)	(17,955		)
Net loss	—	—		—			(154,101		)	—			—			(154,101		)
Balance as of June 30, 2015	393,743	$	3,937	$	1,906,718		$	(648,951	)	$	378		$	(46,889	)	$	1,215,193

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended June 30,
	2015			2014
Operating activities
Net income (loss)	$	(154,101	)	$	131,476
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	79,758			121,269
Deferred income taxes	23,015			55,817
Unsuccessful well costs	86,603			2,815
Change in fair value of derivatives	11,605			22,301
Cash settlements on derivatives (including $93.5 million and $(0.2) million on commodity hedges)	93,275			(1,510		)
Equity-based compensation	48,527			40,898
Gain on sale of assets	(24,651		)	(23,769		)
Loss on extinguishment of debt	165			2,898
Other	5,977			(4,132		)
Changes in assets and liabilities:
(Increase) decrease in receivables	8,615			(135,631		)
(Increase) decrease in inventories	(14,754		)	7,519
(Increase) decrease in prepaid expenses and other	6,254			(24,696		)
Decrease in accounts payable	(34,681		)	(5,444		)
Increase (decrease) in accrued liabilities	(52,154		)	96,250
Net cash provided by operating activities	83,453			286,061

Investing activities
Oil and gas assets	(384,194		)	(186,463		)
Other property	(536		)	(914		)
Proceeds on sale of assets	28,603			58,315
Restricted cash	(9,574		)	(1,827		)
Net cash used in investing activities	(365,701		)	(130,889		)

Financing activities
Payments on long-term debt	(200,000		)	(100,000		)
Net proceeds from issuance of senior secured notes	206,774			—
Purchase of treasury stock	(17,955		)	(10,940		)
Deferred financing costs	(8,791		)	(20,709		)
Net cash used in financing activities	(19,972		)	(131,649		)

Net increase (decrease) in cash and cash equivalents	(302,220		)	23,523
Cash and cash equivalents at beginning of period	554,831			598,108
Cash and cash equivalents at end of period	$	252,611		$	621,631

Supplemental cash flow information
Cash paid for:
Interest	$	28,335		$	15,302
Income taxes	$	17,119		$	44,367

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 other major development projects offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Ireland, Mauritania, Portugal, Senegal, 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, 2015, the changes in the consolidated statements of shareholders’ equity for the six months ended June 30, 2015, the consolidated results of operations for the three months and six ended June 30, 2015 and 2014, and consolidated cash flows for the six months ended June 30, 2015 and 2014. 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, 2014, included in our annual report on Form 10-K.

Reclassifications

Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities or shareholders’ equity.

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, 2015 and December 31, 2014, we had $24.3 million and $15.9 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, 2015 and December 31, 2014, we had $7.2 million and zero, respectively, of short-term restricted cash and $10.1 million and $16.1 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 $68.1 million and $55.3 million of materials and supplies and $2.0 million and $0.1 million of hydrocarbons as of June 30, 2015 and December 31, 2014, 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 market.

Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or market. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.

Recent Accounting Standards

In April 2015, the FASB issued ASU 2015-03, “Interest - Imputation of Interest (Subtopic 835-30) — Simplifying the Presentation of Debt Issuance Costs.” ASU 2015-03 modifies existing guidance related to the presentation of debt issuance costs which are currently capitalized and presented on the balance sheet as an asset. ASU 2015-03 requires these costs to be presented as a direct deduction from the face amount of the related debt. This guidance is effective for public companies for fiscal years beginning after December 15, 2015 and will be applied retrospectively for all periods presented. The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial statements.

In February 2015, the FASB issued ASU 2015-02, “Consolidation (Topic 810) - Amendments to the Consolidation Analysis.” ASU 2015-02 modifies existing consolidation guidance related to limited partnerships and similar legal entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. This guidance is effective for public companies for fiscal years beginning after December 15, 2015 with early adoption permitted. The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial statements.

3. Acquisitions and Divestitures

In March 2015, we closed a farm-in agreement with Repsol Exploración, S.A. (“Repsol”), acquiring a non-operated interest in the Camarao, Ameijoa, Mexilhao and Ostra blocks in the Peniche Basin offshore Portugal. As part of the agreement, we will reimburse a portion of Repsol’s previously incurred exploration costs, as well as partially carry Repsol’s share of the costs of a planned 3D seismic program. After giving effect to the farm-in agreement, our participating interest is 31% in each of the blocks.

In March 2015, we closed a farm-out agreement with Chevron Mauritania Exploration Limited, a wholly owned subsidiary of Chevron Corporation (“Chevron”), covering the C8, C12 and C13 petroleum contracts offshore Mauritania. Under the terms of the farm-out agreement, Chevron acquired a 30% non-operated working interest in each of the contract areas. Chevron will pay a disproportionate share of the costs of one exploration well and a second contingent exploration well, subject to maximum expenditure caps. In addition, Chevron paid its proportionate share of certain previously incurred exploration costs. Chevron did not fund drilling of the Tortue prospect, but retains the option to elect to participate in this prospect subject to Chevron paying a disproportionate share of its costs related to the Tortue prospect. After giving effect to the farm-out agreements, Kosmos, Chevron and Société Mauritanienne des Hydrocarbures et de Patrimoine Minier’s (“SMHPM”) (Mauritania’s national oil company) participating interest in Block C8, Block C12 and Block C13 is 60%, 30% and 10%, respectively, and we remain as operator. The final allocation resulted in sales proceeds of $28.7 million, which exceeded our book basis in the assets, resulting in a $24.7 million gain on the transaction.

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. We will be reimbursed for our portion of such costs plus interest from GNPC’s TEN production revenues under the terms of the Deepwater Tano (“DT”) petroleum contract. As of June 30, 2015 and December 31, 2014, the joint interest billing receivables due from GNPC for the TEN development costs were $24.9 million and $14.2 million, respectively, which are classified as long-term on the consolidated balance sheets.

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5. Property and Equipment

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

	June 30,			December 31,
	2015			2014
	(In thousands)
Oil and gas properties:
Proved properties	$	1,223,514		$	1,156,868
Unproved properties	441,368			363,717
Support equipment and facilities	1,067,690			968,722
Total oil and gas properties	2,732,572			2,489,307
Less: accumulated depletion	(781,699		)	(716,121		)
Oil and gas properties, net	1,950,873			1,773,186

Other property	34,146			33,718
Less: accumulated depreciation	(24,338		)	(22,058		)
Other property, net	9,808			11,660

Property and equipment, net	$	1,960,681		$	1,784,846

We recorded depletion expense of $35.2 million and $67.2 million for the three months ended June 30, 2015 and 2014, respectively, and $69.8 million and $111.2 million for the six months ended June 30, 2014 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, 2015. The table excludes $63.2 million in costs that were capitalized and subsequently expensed during the same period.

	Six Months Ended June 30, 2015
	(In thousands)
Beginning balance	$	226,714
Additions to capitalized exploratory well costs pending the determination of proved reserves	149,450
Reclassification due to determination of proved reserves	—
Capitalized exploratory well costs charged to expense	(23,375		)
Ending balance	$	352,789

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, 2015		December 31, 2014
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	138,882	$	16,814
Exploratory well costs capitalized for a period of one to two years	33,843		40,865
Exploratory well costs capitalized for a period of three to six years	180,064		169,035
Ending balance	$	352,789	$	226,714
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	4		5

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As of June 30, 2015, 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 in Ghana.

Mahogany— In March 2015, we submitted a declaration of commerciality to Ghana’s Ministry of Petroleum (formerly Ghana’s Ministry of Energy and Petroleum) and expect to submit a PoD concerning the Mahogany discovery later this year.

Teak Discovery—We are currently in discussions with the government of Ghana regarding the declaration of commerciality for the Teak discovery. Upon resolution of such discussions and declaration of commerciality, a PoD would be prepared and submitted to Ghana’s Ministry of Petroleum, as required under the WCTP petroleum contract. The Teak-1 and Teak-2 discoveries are being treated as a single discovery area.

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.

Wawa Discovery—In April 2015, the Special Chamber of the International Tribunal of the Law of the Sea (“ITLOS”) issued an order in response to the provisional measures sought by the Government of Cote d’Ivoire in its pending maritime boundary dispute with the Government of Ghana. ITLOS rejected the request that Ghana suspend all ongoing exploration and development operations in the disputed area in which the Wawa Discovery is situated until ITLOS gives its decision on the maritime boundary dispute, which is expected in late 2017. ITLOS did order Ghana to suspend new drilling in the disputed area. We plan to discuss with the Government of Ghana the effects of the ITLOS order on the proposed Wawa appraisal activities so that we can more clearly define our future plans and corresponding timeline. In the meantime, we continue to reprocess seismic data and have acquired a high resolution seismic survey over the discovery area. Following additional evaluation and potential appraisal activities, a decision regarding commerciality of the Wawa discovery will be made by the DT Block partners. Within six months of a declaration of commerciality, a PoD would be prepared and submitted to Ghana’s Ministry of Petroleum, as required under the DT petroleum contract.

7. Accrued Liabilities

Accrued liabilities consisted of the following:

	June 30,		December 31,
	2015		2014
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	60,514	$	139,393
General and administrative expenses	15,112		21,926
Income taxes	12,542		9,233
Interest	17,456		10,271
Taxes other than income	4,175		20,315
Other	207		829
	$	110,006	$	201,967

8. Debt

Debt consists of the following:

	June 30,			December 31,
	2015			2014
	(In thousands)
Outstanding debt principal balances:
Facility	$	300,000		$	500,000
Senior Notes	525,000			300,000
Total	825,000			800,000
Unamortized issuance discounts	(26,457		)	(5,731		)
Long-term debt	$	798,543		$	794,269

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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, including the International Finance Corporation. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities.

As part of the debt refinancing in March 2014, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and existing unamortized debt issuance costs attributable to those participants were expensed. As a result, we recorded a $2.9 million loss on the extinguishment of debt. As of June 30, 2015, we have $41.0 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.

As of June 30, 2015, borrowings under the Facility totaled $300.0 million and the undrawn availability under the Facility was $1.2 billion.

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 sublimit 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, 2015, 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, 2015 (the most recent assessment date). The Facility contains customary cross default provisions.

Corporate Revolver

In June 2015, we amended and restated the Corporate Revolver from a number of financial institutions, increasing the borrowing capacity to $400.0 million, extending the maturity date to November 2018 and lowering the commitment fees on the undrawn portion of the total commitments to 30% per annum of the respective margin. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration; appraisal and development programs. As of June 30, 2015, we have $9.3 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term. Additionally, a negative covenant was added that restricts our ability to incur additional indebtedness that would not be permitted by the indenture governing our 7.875% senior secured notes due 2021.

As of June 30, 2015, 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, 2015 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.

Revolving Letter of Credit Facility

In July 2013, we entered into a revolving letter of credit facility agreement (“LC Facility”). The size of the LC Facility is $100.0 million, 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. As of June 30, 2015, there were eight outstanding letters of credit totaling $23.1 million under the LC Facility. The LC Facility contains customary cross default provisions. In July 2015, we reduced the size of our LC facility by $25.0 million to $75.0 million, 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.

7.875% Senior Secured Notes due 2021

In 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.

In 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. The net proceeds were used 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

existing $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.

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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 existing $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, 2015, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:

	Payments Due by Year
	2015(2)		2016		2017		2018		2019		Thereafter
	(In thousands)
Principal debt repayments(1)	$	—	$	—	$	—	$	—	$	—	$	825,000

(1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the estimated future available borrowing base as of June 30, 2015. 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, 2015, there were no borrowings under the Corporate Revolver.

(2) Represents payments for the period July 1, 2015 through December 31, 2015.

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,
	2015			2014			2015			2014
Interest expense	$	19,260		$	10,998		$	34,657		$	21,994
Amortization—deferred financing costs	2,609			2,559			5,219			5,345
Deferred interest	137			265			1,291			(3,846		)
Loss on extinguishment of debt	165			—			165			2,898
Capitalized interest	(13,154		)	(4,302		)	(21,994		)	(8,103		)
Interest income	(172		)	(196		)	(340		)	(254		)
Other, net	153			674			751			1,101
Interest and other financing costs, net	$	8,998		$	9,998		$	19,749		$	19,135

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.

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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, 2015.

			Weighted Average Dated Brent Price per Bbl
Term	Type of Contract	MBbl	Net Deferred Premium Payable		Swap		Put		Floor		Ceiling		Call
2015:
July — December	Three-way collars	2,129	$	0.46	$	—	$	—	$	87.43	$	110.00	$	133.82
July — December	Swaps with calls	1,006	—		93.59		—		—		—		115.00
2016:
January — December	Purchased puts	2,000	$	3.41	$	—	$	—	$	85.00	$	—	$	—
January — December	Three-way collars	2,000	—		—		—		85.00		110.00		135.00
January — December	Swaps with puts	2,000	—		75.00		60.00		—		—		—
2017:
January — December	Sold calls	2,000	$	—	$	—	$	—	$	—	$	85.00	$	—
January — December	Swap with puts/calls	2,000	2.13		72.50		55.00		—		—		90.00

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 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, 2015:

			Weighted Average
Term	Type of Contract	Floating Rate	Notional		Swap		Sold Call
			(In thousands)
July 2015 — December 2015	Swap	6-month LIBOR	$	25,000	2.27	%	—
January 2016 — June 2016	Swap	6-month LIBOR	12,500		2.27	%	—
January 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, 2015 and December 31, 2014 and gain/(loss) from derivatives during the three and six months ended June 30, 2015 and 2014, respectively:

		Estimated Fair Value Asset (Liability)
		June 30,			December 31,
Type of Contract	Balance Sheet Location	2015			2014
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity(1)	Derivatives assets—current	$	110,674		$	163,275
Commodity(2)	Derivatives assets—long-term	43,335			89,210
Interest rate	Derivatives assets—long-term	916			—

Derivative liabilities:
Interest rate	Derivatives liabilities—current	(924		)	(721		)
Commodity	Derivatives liabilities—long-term	(7,574		)	—
Interest rate	Derivatives liabilities—long-term	—			(68		)
Total derivatives not designated as hedging instruments		$	146,427		$	251,696

(1) Includes net deferred premiums payable of $3.8 million and $1.8 million related to commodity derivative contracts as of June 30, 2015 and December 31, 2014, respectively.

(2) Includes net deferred premiums payable of $8.1 million and $6.9 million related to commodity derivative contracts as of June 30, 2015 and December 31, 2014, respectively.

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		Amount of Gain/(Loss)						Amount of Gain/(Loss)
		Three Months Ended June 30,						Six Months Ended June 30,
Type of Contract	Location of Gain/(Loss)	2015			2014			2015			2014
		(In thousands)
Derivatives in cash flow hedging relationships:
Interest rate(1)	Interest expense	$	195		$	405		$	389		$	811
Total derivatives in cash flow hedging relationships		$	195		$	405		$	389		$	811

Derivatives not designated as hedging instruments:
Commodity(2)	Oil and gas revenue	$	(2,336	)	$	(1,841	)	$	297		$	(3,367	)
Commodity	Derivatives, net	(44,877		)	(21,566		)	(12,550		)	(19,538		)
Interest rate	Interest expense	433			(109		)	259			(207		)
Total derivatives not designated as hedging instruments		$	(46,780	)	$	(23,516	)	$	(11,994	)	$	(23,112	)

(1) Amounts were reclassified from accumulated other comprehensive income or loss (“AOCI”) into earnings upon settlement.

(2) Amounts represent the mark-to-market portion 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, 2015 and December 31, 2014, 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. Additionally, if an event of default occurred the offsetting amounts would be immaterial as of June 30, 2015 and December 31, 2014.

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, 2015 and December 31, 2014, for each fair value hierarchy level:

	Fair Value Measurements Using:
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)		Total
	(In thousands)
June 30, 2015
Assets:
Commodity derivatives	$	—	$	154,009		$	—	$	154,009
Interest rate derivatives	—		916			—		916
Liabilities:
Commodity derivatives	—		(7,574		)	—		(7,574		)
Interest rate derivatives	—		(924		)	—		(924		)
Total	$	—	$	146,427		$	—	$	146,427

December 31, 2014
Assets:
Commodity derivatives	$	—	$	252,485		$	—	$	252,485
Liabilities:
Interest rate derivatives	—		(789		)	—		(789		)
Total	$	—	$	251,696		$	—	$	251,696

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, if any, after any allowances for doubtful accounts 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 the 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 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.

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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, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Long-term debt	$	798,543	$	811,219	$	794,269	$	755,000

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 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 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 $23.3 million and $18.0 million during the three months ended June 30, 2015 and 2014, respectively, and $48.5 million and $35.9 million for the six months ended June 30, 2015 and 2014, respectively. The total tax benefit for the three months ended June 30, 2015 and 2014 was $8.2 million and $8.0 million, respectively, and $17.0 million and $14.1 million for the six months ended June 30, 2015 and 2014, respectively. Additionally, we expensed a tax shortfall related to equity-based compensation of $18.3 million and $6.4 million for the three months ended June 30, 2015 and 2014 respectively, and $18.4 million and $6.5 million for the six months ended June 30, 2015 and 2014, respectively. The fair value of awards vested during the three months ended June 30, 2015 and 2014 was approximately $50.0 million and $31.9 million, respectively, and $50.8 million and $33.3 million for the six months ended June 30, 2015 and 2014, respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service criteria under the LTIP. Our outstanding awards vest over a three or four year period. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock.

The following table reflects the outstanding restricted stock awards as of June 30, 2015:

			Weighted-		Market / Service		Weighted-
	Service Vesting Restricted Stock		Average Grant-Date		Vesting Restricted Stock		Average Grant-Date
	Awards		Fair Value		Awards		Fair Value
	(In thousands)				(In thousands)
Outstanding at December 31, 2014	3,240		$	16.95	3,361		$	13.00
Granted	660		8.64		—		—
Forfeited	(2	)	8.85		(1,554	)	13.29
Vested	(3,054	)	17.27		(1,546	)	13.30
Outstanding at June 30, 2015	844		9.33		261		9.44

The following table reflects the outstanding restricted stock units as of June 30, 2015:

			Weighted-		Market / Service		Weighted-
	Service Vesting Restricted Stock		Average Grant-Date		Vesting Restricted Stock		Average Grant-Date
	Units		Fair Value		Units		Fair Value
	(In thousands)				(In thousands)
Outstanding at December 31, 2014	3,367		$	10.76	3,246		$	15.66
Granted	1,283		8.64		3,430		12.96
Forfeited	(89	)	10.22		(67	)	14.94
Vested	(884	)	10.87		—		—
Outstanding at June 30, 2015	3,677		10.00		6,609		14.27

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As of June 30, 2015, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $73.9 million over a weighted average period of 2.03 years. In January 2015, the board of directors approved an amendment to the May 16, 2011 LTIP to add 15.0 million shares to the plan, which was approved at the Annual General Meeting in June 2015. At June 30, 2015, the Company had approximately 11.8 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 $12.96 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 a combination of our historical volatility and implied volatility and the historical and implied volatilities of our peer companies and ranged from 30% to 76%. 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 was $25.4 million and $80.8 million for the three months ended June 30, 2015 and 2014, respectively, and $51.1 million and $131.6 million for the six months ended June 30, 2015 and 2014, respectively. The income tax provision consists of United States and Ghanaian income and Texas margin taxes.

The components of income (loss) before income taxes were as follows:

	Three months ended June 30,						Six months ended June 30,
	2015			2014			2015			2014
	(In thousands)
Bermuda	$	(17,374	)	$	(6,904	)	$	(31,037	)	$	(12,219	)
United States	3,887			4,207			8,554			7,494
Foreign—other	(36,315		)	139,988			(80,529		)	267,768
Income (loss) before income taxes	$	(49,802	)	$	137,291		$	(103,012	)	$	263,043

Our effective tax rate for the three months ended June 30, 2015 and 2014 is (51%) and 59%, respectively. For the six months ended June 30, 2015 and 2014, our effective tax rate is (50%) and 50%, respectively. The effective tax rate for the United States is approximately 511% and 193% for the three months ended June 30, 2015 and 2014, respectively, and 256% and 128% for the six months ended June 30, 2015 and 2014, respectively. The effective tax rate in the United States is impacted by the effect of tax shortfalls related to equity-based compensation. The effective tax rate for Ghana is approximately 43% and 36% for the three months ended June 30, 2015 and 2014, respectively and 36% for the six months ended June 30, 2015 and 2014, respectively. 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 2014 and to Texas margin tax examinations for the tax years 2010 through 2014. In addition, the Company is open to income tax examinations for years 2011 through 2014 in its significant other foreign jurisdictions.

As of June 30, 2015, 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,
	2015			2014			2015			2014
	(In thousands, except per share data)
Numerator:
Net income (loss)	$	(75,192	)	$	56,507		$	(154,101	)	$	131,476
Less: Basic income allocable to participating securities(1)	—			(721		)	—			(1,920		)
Basic net income (loss) allocable to common shareholders	(75,192		)	55,786			(154,101		)	129,556
Diluted adjustments to income allocable to participating securities(1)	—			6			—			15
Diluted net income (loss) allocable to common shareholders	$	(75,192	)	$	55,792		$	(154,101	)	$	129,571
Denominator:
Weighted average number of shares used to compute net income (loss) per share:
Basic	382,138			378,820			381,238			378,327
Restricted stock awards and units(1)(2)	—			2,998			—			2,830
Diluted	382,138			381,818			381,238			381,157
Net income (loss) per share:
Basic	$	(0.20	)	$	0.15		$	(0.40	)	$	0.34
Diluted	$	(0.20	)	$	0.15		$	(0.40	)	$	0.34

(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 per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses and, therefore, are excluded from the basic net income per common share calculation in periods we are in a net loss position.

(2) We excluded outstanding restricted stock awards and units of 11.4 million and 4.4 million for the three months and six months ended June 30, 2015 and 2014, 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.

In June 2013, we signed a long-term rig agreement with a subsidiary of Atwood Oceanics, Inc. for the new build 6th generation drillship “Atwood Achiever.” We took delivery of the Atwood Achiever in September 2014. The rig agreement covers 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. We have entered into a rig sharing agreement, whereby one rig slot (estimated to be 51 days remaining in 2015) was assigned to a third-party.

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The estimated future minimum commitments as of June 30, 2015, are:

	Payments Due By Year(1)
	Total		2015(2)		2016		2017		2018		2019		Thereafter
	(In thousands)
Operating leases(3)	$	14,469	$	1,634	$	3,158	$	3,223	$	3,323	$	3,131	$	—
Atwood Achiever drilling rig contract(4)	443,275		79,135		217,770		146,370		—		—		—

(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, 2015 through December 31, 2015.

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

(4) Commitments calculated using a day rate of $0.6 million, excluding applicable taxes. The rig commitments reflect the execution of a rig sharing agreement, whereby one rig slot (estimated to 51 days remaining in 2015) was assigned to a third-party.

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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, 2014, 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 information that involves 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 other major development projects offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Ireland, Mauritania, Portugal, Senegal, Suriname, Morocco and Western Sahara.

Recent Developments

Corporate

During April 2015, we issued an additional $225.0 million of 7.875% Senior Secured Notes due 2021 (“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 existing $300.0 million of Senior Notes issued in August 2014, other than the date of issue, the initial price, the first interest payment date and the first date from which interest will accrue.

In June 2015, we amended and restated the Corporate Revolver from a number of financial institutions, increasing the borrowing capacity from $300.0 million to $400.0 million, extending the maturity date to November 23, 2018 and lowering the commitment fees on the undrawn portion of the total commitments to 30% per annum of the respective margin. Additionally, a negative covenant was added that restricts our ability to incur additional indebtedness that would not be permitted by the indenture governing our 7.875% senior secured notes due 2021.

In July 2015, we reduced the size of our revolving letter of credit facility agreement (“LC facility”) by $25.0 million to $75.0 million, 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.

Ghana

We submitted a declaration of commerciality on the Mahogany discovery in March 2015. We expect to submit a plan of development concerning the Mahogany discovery area later this year.

We are currently in discussions with the government of Ghana regarding the declaration of commerciality for the Teak discovery. Upon resolution of such discussions and declaration of commerciality, we expect to submit a plan of development concerning the Teak discovery later this year.

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 Akasa discovery.

In April 2015, the Special Chamber of the International Tribunal of the Law of the Sea (the “ITLOS”) issued an order in response to the provisional measures sought by the Government of Cote d’Ivoire in its pending maritime boundary dispute with the Government of Ghana. ITLOS rejected the request that Ghana suspend all ongoing exploration and development operations in the disputed area in which the TEN project and Wawa Discovery are situated until ITLOS gives its decision on the maritime boundary dispute, which is expected in late 2017. ITLOS did order Ghana to suspend new drilling in the disputed area. On June 11, 2015, the Ghana Attorney General issued a letter to the DT Operator, which confirmed the DT Block partners may (i) continue to drill wells that had been started but not completed prior to the ITLOS order and (ii) carry out completion work on wells that have already been drilled. The TEN project is currently estimated to be approximately 65 percent complete. We expect TEN development activities will continue as planned with first oil expected in the second half of 2016. With respect to the Wawa Discovery, we plan to discuss with

the Government of Ghana the effects of the ITLOS order on the proposed Wawa appraisal activities so that we can more clearly define our future plans and corresponding timeline.

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Jubilee gas exports were temporarily halted in July due to an issue with the Jubilee FPSO processing facilities. The reduction in gas exports constrained Jubilee Field production to approximately 65,000 barrels (gross) of oil per day. We are now in the final stages of repairing the gas compressor and we expect to resume full production shortly.

Mauritania

In April 2015, we announced the Tortue-1 exploration well on block C8 offshore Mauritania had made a significant, play-opening gas discovery. Based on preliminary analysis of drilling results and intermediate logging, the Tortue-1 exploration well has intersected 107 meters (351 feet) of net hydrocarbon pay. A single gas pool was encountered in the Lower Cenomanian objective, which is comprised of three reservoirs totaling 88 meters (288 feet) in thickness over a gross hydrocarbon interval of 160 meters (528 feet). A fourth reservoir totaling 19 meters (62 feet) was penetrated within the Upper Cenomanian target over a gross hydrocarbon interval of 150 meters (492 feet). In May 2015, the Tortue-1 exploration well was drilled to a total depth of 5,107 meters, intersecting an additional 10 meters (32 feet) of net hydrocarbon pay in the lower Albian section, which is interpreted to be gas. The Tortue discovery area has been renamed Ahmeyim. An appraisal program is being planned to delineate the Ahmeyim discovery.

Portugal

In June 2015, we commenced a 3D seismic survey of approximately 3,200 square kilometers over the Camarao block offshore Portugal, which is expected to be completed in the third quarter of 2015.

Senegal

In June 2015, we entered the first renewal of the exploration period for the Cayar Offshore Profond and Saint Louis Profond Contract Areas, which lasts for three years. The first renewal period includes a one well commitment in each block. After the required relinquishment of acreage to enter the first renewal, the Cayar Offshore Profond and Saint Louis Profond Contract Areas comprise approximately 1.4 million acres and 1.6 million acres, respectively.

Suriname

In April 2015, we received an extension of the initial exploration phases for Block 42 and Block 45 offshore Suriname, both now expire in September 2016.

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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, 2015 and 2014 are included in the following table:

	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015		2014
	(In thousands, except per barrel data )
Sales volumes:
MBbl	1,946			2,916		3,845		4,853

Revenues:
Oil sales	$	119,200		$	328,297	$	228,364	$	541,150
Average sales price per Bbl	61.26			112.58		59.39		111.50

Costs:
Oil production, excluding workovers	$	20,521		$	22,845	$	38,737	$	37,903
Oil production, workovers	(297		)	101		13,587		1,366
Total oil production costs	$	20,224		$	22,946	$	52,324	$	39,269

Depletion and depreciation	$	37,532		$	69,546	$	74,539	$	115,924

Average cost per Bbl:
Oil production, excluding workovers	$	10.55		$	7.84	$	10.07	$	7.81
Oil production, workovers	(0.15		)	0.03		3.53		0.28
Total oil production costs	10.40			7.87		13.60		8.09

Depletion and depreciation	19.29			23.85		19.38		23.89
Oil production cost and depletion costs	$	29.69		$	31.72	$	32.98	$	31.98

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, 2015:

					Wells Suspended or
	Actively Drilling or Completing				Waiting on Completion
	Exploration		Development		Exploration		Development
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Ghana
Jubilee Unit	—	—	1	0.24	—	—	2	0.48
West Cape Three Points	—	—	—	—	9	2.78	—	—
TEN	—	—	1	0.17	—	—	14	2.38
Deepwater Tano	—	—	—	—	1	0.18	—	—
Mauritania
Block C8(1)	—	—	—	—	1	0.90	—	—
Total	—	—	2	0.41	11	3.86	16	2.86

(1) In March 2015, we closed a farm-out agreement covering our three license areas in Mauritania with Chevron. If Chevron exercises their option to participate in the Tortue prospect, our net interest will be 60% in the well.

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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, 2015 compared to three months ended June 30, 2014

	Three Months Ended June 30,					Increase
	2015			2014		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	119,200		$	328,297	$	(209,097	)
Gain on sale of assets	1,900			—		1,900
Other income	713			869		(156		)
Total revenues and other income	121,813			329,166		(207,353		)
Costs and expenses:
Oil and gas production	20,224			22,946		(2,722		)
Exploration expenses	14,539			23,509		(8,970		)
General and administrative	41,179			32,480		8,699
Depletion and depreciation	37,532			69,546		(32,014		)
Interest and other financing costs, net	8,998			9,998		(1,000		)
Derivatives, net	44,877			21,566		23,311
Restructuring charges	—			11,804		(11,804		)
Other expenses, net	4,266			26		4,240
Total costs and expenses	171,615			191,875		(20,260		)
Income (loss) before income taxes	(49,802		)	137,921		(187,093		)
Income tax expense	25,390			80,784		(55,394		)
Net income (loss)	$	(75,192	)	$	56,507	$	(131,699	)

Oil and gas revenue. Oil and gas revenue decreased by $209.1 million during the three months ended June 30, 2015 as compared to the three months ended June 30, 2014, primarily due to a decrease in volumes, two liftings in 2015 compared to three in 2014, and a lower realized price per barrel. We lifted and sold approximately 1,946 MBbl at an average realized price per barrel of $61.26 during the three months ended June 30, 2015 and approximately 2,916 MBbl at an average realized price per barrel of $112.58 during the three months ended June 30, 2014.

Oil and gas production. Oil and gas production costs decreased by $2.7 million during the three months ended June 30, 2015, as compared to the three months ended June 30, 2014 primarily due to a decrease in routine operating costs associated with the decreased sales volumes and a decrease in well workover costs. Our workover costs are related to performing workovers on our wells, 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.

Exploration expenses. Exploration expenses decreased by $9.0 million during the three months ended June 30, 2015, as compared to the three months ended June 30, 2014 primarily due to a decrease in seismic costs.

General and administrative. General and administrative costs increased by $8.7 million during the three months ended June 30, 2015, as compared with the three months ended June 30, 2014. The increase is primarily due an increase in non-cash stock-based compensation and cash compensation and benefits.

Depletion and depreciation. Depletion and depreciation decreased $32.0 million during the three months ended June 30, 2015, as compared with the three months ended June 30, 2014. The decrease is primarily due to depletion recognized related to the sale of two liftings of oil during the three months ended June 30, 2015, as compared to three liftings during the three months ended June 30, 2014. In addition, the depletion rate is lower during the three months ended June 30, 2015 due to an increase in proved reserves in the fourth quarter of 2014.

Derivatives, net. During the three months ended June 30, 2015 and 2014, we recorded losses of $44.9 million and $21.6 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.

Restructuring charges. During the three months ended June 30, 2014, we recognized $11.8 million in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization, which includes $5.0 million of non-cash expense related to awards granted under our LTIP.

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Other expenses, net. During the three months ended June 30, 2015, we recognized a $4.2 million write-off related to a damaged riser. We are awaiting the results of a root cause analysis of the damage to the riser to determine if any costs are recoverable through an insurance claim or a potential warranty claim.

Income tax expense. The Company’s effective tax rates for the three months ended June 30, 2015 and 2014 were (51%) and 59%, respectively. The effective tax rates for the periods presented are impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and, therefore, do not generate any income tax benefits 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 losses. Income tax expense decreased $55.4 million during the three months ended June 30, 2015, as compared with June 30, 2014, primarily due to reduced income in our Ghanaian subsidiary.

Six months ended June 30, 2015 compared to six months ended June 30, 2014

	Six Months Ended June 30,					Increase
	2015			2014		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	228,364		$	541,150	$	(312,786	)
Gain on sale of assets	24,651			23,769		882
Other income	1,355			1,308		47
Total revenues and other income	254,370			566,227		(311,857		)
Costs and expenses:
Oil and gas production	52,324			39,269		13,055
Exploration expenses	113,480			36,318		77,162
General and administrative	79,846			59,893		19,953
Depletion and depreciation	74,539			115,924		(41,385		)
Interest and other financing costs, net	19,749			19,135		614
Derivatives, net	12,550			19,538		(6,988		)
Restructuring charges	—			11,804		(11,804		)
Other expenses, net	4,894			1,303		3,591
Total costs and expenses	357,382			303,184		54,198
Income before income taxes	(103,012		)	263,043		(366,055		)
Income tax expense	51,089			131,567		(80,478		)
Net income	$	(154,101	)	$	131,476	$	(285,577	)

Oil and gas revenue. Oil and gas revenue decreased by $312.8 million during the six months ended June 30, 2015 as compared to the six months ended June 30, 2014, primarily due a decrease in sales volumes, four liftings in 2015 compared to five in 2014 and a lower realized price per barrel. We lifted and sold 3,845 MBbl at an average realized price per barrel of $59.39 during the six months ended June 30, 2015 and 4,853 MBbl at an average realized price per barrel of $111.50 during the six months ended June 30, 2014.

Oil and gas production. Oil and gas production costs increased by $13.1 million during the six months ended June 30, 2015, as compared to the six months ended June 30, 2014 primarily due to an increase in well workover costs which offset a reduction from one less lifting compared to 2014. Our workover costs are related to performing workovers on our wells, 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.

Exploration expenses. Exploration expenses increased by $77.2 million during the six months ended June 30, 2015, as compared to the six months ended June 30, 2014 primarily due to $86.7 million of unsuccessful well costs for the Western Sahara
CB-1 exploration well in 2015 offset by a decrease in seismic costs of $6.7 million.

General and administrative. General and administrative costs increased by $20.0 million during the six months ended June 30, 2015, as compared with the six months ended June 30, 2014. The increase is primarily due an increase in non-cash stock-based compensation, professional fees and occupancy and general expenses.

Depletion and depreciation. Depletion and depreciation decreased $41.4 million during the six months ended June 30, 2015, as compared with the six months ended June 30, 2014. The decrease is primarily due to depletion recognized related to the sale of four liftings of oil during the six months ended June 30, 2015, as compared to five liftings during the six months ended June 30, 2014. In addition, the lower depletion rate is lower during the six months ended June 30, 2015 due to an increase in proved reserves in the fourth quarter of 2014.

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Derivatives, net. During the six months ended June 30, 2015 and 2014, we recorded losses of $12.6 million and $19.5 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.

Restructuring charges. During the six months ended June 30, 2014, we recognized $11.8 million in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization, which includes $5.0 million of non-cash expense related to awards granted under our LTIP.

Other expenses, net. During the six months ended June 30, 2015, we recognized a $4.2 million write-off related to a damaged riser. We are awaiting the results of a root cause analysis of the damage to the riser to determine if any costs are recoverable through an insurance claim or a potential warranty claim.

Income tax expense. The Company’s effective tax rate for the six months ended June 30, 2015 and 2014 were (50%) and 50%, respectively. The effective tax rates for the periods presented are impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and, therefore, do not generate any income tax benefits 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 losses. Income tax expense decreased $80.5 million during the six months ended June 30, 2015, as compared with June 30, 2014, primarily due to reduced income from and deferred taxes related to our Ghanaian subsidiary.

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 from issuances of equity and debt. While we are presently in a strong financial position, should the current decline in oil pricing be significantly prolonged or if further deterioration of pricing continues, it could 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. Commodity prices are volatile and future prices cannot be accurately predicted; however, we maintain a hedging program to 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 hedging program and our current liquidity position support our capital program for 2015.

In March 2015, following the lenders’ semi-annual redetermination, the borrowing base under our Facility remained unchanged at $1.5 billion. In addition to the Jubilee field, the borrowing base calculation included value related to the TEN development project for the first time. As of June 30, 2015, undrawn availability under the Facility was $1.2 billion.

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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, 2015 and 2014:

	Six Months Ended June 30,
	2015			2014
	(In thousands)
Sources of cash and cash equivalents:
Net cash provided by operating activities	$	83,453		$	286,061
Net proceeds from issuance of senior secured notes	206,774			—
Proceeds on sale of assets	28,603			58,315
	318,830			344,376
Uses of cash and cash equivalents:
Oil and gas assets	384,194			186,463
Other property	536			914
Payments on long-term debt	200,000			100,000
Deferred financing costs	8,791			20,709
Restricted cash	9,574			1,827
Purchase of treasury stock	17,955			10,940
	621,050			320,853
Increase (decrease) in cash and cash equivalents	$	(302,220	)	$	23,523

Net cash provided by operating activities. Net cash provided by operating activities for the six months ended June 30, 2015 was $83.5 million compared with net cash provided by operating activities for the six months ended June 30, 2014 of $286.1 million. The decrease in cash provided by operating activities in the six months ended June 30, 2015 when compared to the same period in 2014 was primarily due to a decrease in results from operations in addition to a negative change in working capital items.

The following table presents our net debt and liquidity as of June 30, 2015:

	June 30, 2015
	(In thousands)
Cash and cash equivalents	$	252,611
Restricted cash	41,625
Senior Notes at par	525,000
Drawings under the Facility	300,000
Net debt	$	530,764

Availability under the Facility	$	1,200,000
Availability under the Corporate Revolver	400,000
Available borrowings plus cash and cash equivalents (liquidity)	1,852,611

Capital Expenditures and Investments

We expect to incur substantial costs as we:

· develop our discoveries that we determine to be commercially viable;

· execute our exploration and appraisal drilling program in our license areas;

· purchase and analyze seismic and other geological and geophysical data to identify future prospects; and

· invest in additional oil and natural gas leases and licenses.

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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, the price we realize for our production of oil and natural gas, 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, and the availability of suitable equipment and qualified personnel. 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 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.

2015 Capital Program

We estimate we will spend approximately $800 million of capital for the year ending December 31, 2015. Through June 30, 2015, we have spent approximately $318 million of the capital budget. This amount is net of the $28.7 million of proceeds received from the Mauritania farm-out.

The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our drilling results. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil and natural gas and the prices we receive from the sale of these commodities, 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, and the actual cost of exploration, appraisal and development of our oil and natural gas assets.

Significant Sources of Capital

Facility

In March 2014, the Company amended and restated the then existing commercial debt facility (the “Facility”) with a total commitment of $1.5 billion from a number of financial institutions, including the International Finance Corporation. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities.

As of June 30, 2015, borrowings under the Facility totaled $300.0 million and the undrawn availability under the Facility was $1.2 billion.

We were in compliance with the financial covenants contained in the Facility as of March 31, 2015 (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 23, 2018 and lowering the commitment fees on the undrawn portion of the total commitments to 30% per annum of the respective margin. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration; appraisal and development programs. Additionally, a negative covenant was added that restricts our ability to incur additional indebtedness that would not be permitted by the indenture governing our 7.875% senior secured notes due 2021.

Revolving Letter of Credit Facility

In July 2013, we entered into the LC Facility. The size of the LC Facility is $100.0 million, with additional commitments up to $50.0 million being available if the existing lender increases its commitments or if commitments from new financial institutions are added. As of June 30, 2015, there were eight outstanding letters of credit totaling $23.1 million under the LC Facility. The LC Facility contains customary cross default provisions. In July 2015, we reduced the size of our LC facility by $25.0 million to $75.0 million, 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.

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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 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 existing $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 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. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” section of our annual report on Form 10-K for the terms of the Senior Notes.

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of June 30, 2015:

	Payments Due By Year(5)
	Total		2015(6)		2016		2017		2018		2019		Thereafter
	(In thousands)
Principal debt repayments(1)	$	825,000	$	—	$	—	$	—	$	—	$	—	$	825,000
Interest payments on long-term debt(2)	435,339		37,683		76,553		78,506		70,982		63,141		108,474
Operating leases(3)	14,469		1,634		3,158		3,223		3,323		3,131		—
Atwood Achiever drilling rig contract(4)	443,275		79,135		217,770		146,370		—		—		—

(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 the Facility are based on the level of borrowings and the estimated future available borrowing base as of June 30, 2015. 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, 2015, there were no borrowings under the Corporate Revolver.

(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 a day rate of $0.6 million. The rig commitments reflect the execution of a rig sharing agreement, whereby one rig slot (estimated to be 51 days remaining in 2015) was assigned to a third-party.

(5) 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.

(6) Represents payments for the period from July 1, 2015 through December 31, 2015.

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The following table presents maturities by expected maturity dates under the Senior Notes and the Facility. For the Senior Notes, the interest rate represents the contractual fixed rate that we are obligated to periodically pay on the debt as of June 30, 2015. For the Facility, the interest rates represent 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 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.

	July 1 Through December 31,			Years Ending December 31,															Liability Fair Value at June 30,
	2015			2016			2017			2018			2019			Thereafter			2015
	(In thousands, except percentages)
Fixed rate debt:
Senior Notes	$	—		$	—		$	—		$	—		$	—		$	525,000		$	(511,219	)
Fixed interest rate	7.88		%	7.88		%	7.88		%	7.88		%	7.88		%	7.88		%
Variable rate debt:
Facility(1)	$	—		$	—		$	—		$	—		$	—		$	300,000		$	(300,000	)
Weighted average interest rate(2)	3.57		%	4.04		%	4.80		%	5.73		%	6.25		%	7.18		%
Interest rate swaps:
Notional debt amount(3)	$	25,000		$	12,500		$	—		$	—		$	—		$	—		$	(327	)
Average fixed rate payable	2.27		%	2.27		%	—			—						—
Variable rate receivable(4)	0.45		%	0.73		%	—			—						—
Capped interest rate swaps:
Notional debt amount	$	—		$	200,000		$	200,000		$	200,000		$	—		$	—		$	319
Cap	—			3.00		%	3.00		%	3.00		%	—			—
Average fixed rate payable (5)	—			1.23		%	1.23		%	1.23		%	—			—
Variable rate receivable(4)	—			0.75		%	1.48		%	2.03		%	—			—

(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, 2015. 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, 2015, 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) Represents weighted average notional contract amounts of interest rate derivatives. In the final year of maturity, represents notional amount from January — June.

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

(5) 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.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of June 30, 2015, 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, 2014.

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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 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, Ireland, Mauritania, Morocco (including Western Sahara), Portugal, 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 laws, greenhouse gas regulation 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 Côte d’Ivoire and Ghana impacting our operations in the Deepwater Tano Block offshore Ghana;

· environmental liabilities;

· geological, technical, drilling, production and processing problems;

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

· the cost and availability of insurance coverage and whether such coverage is enough to sufficiently mitigate potential losses;

· 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;

· the result of any legal proceedings or investigations we may be subject to;

· 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.

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.

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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 internal policies and guidelines. 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, 2015:

	Derivative Contracts Assets (Liabilities)
	Commodities			Interest Rates			Total
	(In thousands)
Fair value of contracts outstanding as of December 31, 2014	$	252,485		$	(789	)	$	251,696
Changes in contract fair value	(12,253		)	259			(11,994		)
Contract maturities	(93,797		)	522			(93,275		)
Fair value of contracts outstanding as of June 30, 2015	$	146,435		$	(8	)	$	146,427

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. Crude oil prices in 2014 began the year strong and remained strong through the summer before decreasing rapidly during the fourth quarter. Dated Brent crude, the benchmark against which our oil sales are indexed, peaked above $115 per barrel in June 2014 before falling below $50 during 2015.

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, 2015:

			Weighted Average Dated Brent Price per Bbl												Asset(Liability)
Term	Type of Contract	MBbl	Net Deferred Premium Payable		Swap		Put		Floor		Ceiling		Call		Fair Value at June 30, 2015(1)
2015:
July — December	Three-way collars	2,129	$	0.46	$	—	$	—	$	87.43	$	110.00	$	133.82	$	48,276
July — December	Swaps with calls	1,006	—		93.59		—		—		—		115.00		29,231
2016:
January — December	Purchased puts	2,000	$	3.41	$	—	$	—	$	85.00	$	—	$	—	$	32,209
January — December	Three-way collars	2,000	—		—		—		85.00		110.00		135.00		38,292
January — December	Swaps with puts	2,000	—		75.00		60.00		—		—		—		6,001
2017:
January — December	Sold calls	2,000	$	—	$	—	$	—	$	—	$	85.00	$	—	$	(7,192	)
January — December	Swap with puts/calls	2,000	2.13		72.50		55.00		—		—		90.00		(382		)

(1) Fair values are based on the average forward Dated Brent oil prices on June 30, 2015 which by year are: 2015—$64.38, 2016—$67.43 and 2017 — $69.69. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on July 27, 2015 market quotes by year are: 2015—$54.43, 2016—$58.42 and 2017—$62.76.

At June 30, 2015, our open commodity derivative instruments were in a net asset position of $146.4 million. As of
June 30, 2015, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $62.4 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $63.1 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, 2015, we had indebtedness outstanding under the Facility of $300.0 million, of which $275.0 million bore interest at floating rates after consideration of our interest rate hedges. The interest rate on this indebtedness as of June 30, 2015 was approximately 3.4%. If LIBOR increased by 10% at this level of floating rate debt, we would pay an additional $0.1 million in interest expense per year on the Facility. We pay commitment fees on the $1.2 billion of undrawn availability 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, 2015, the fair market value of our interest rate derivatives was a net liability of approximately $8 thousand. If LIBOR changed by 10%, it would have a negligible impact on the fair market value of our interest rate swaps.

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, 2015, in ensuring that information required to be disclosed by the

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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

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, 2014 and in the “Item 1A. Risk Factors” section of our quarterly report on Form 10-Q for the quarter ended March 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, the number of vested shares (based on the closing price of our common shares on such vesting date) equal to the statutorily required tax liability owed by such grantee. The shares withheld from the grantees to settle their statutorily required 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 three months ended, June 30, 2015 and the average price paid per share.

	Total Number of Share Withheld/Purchased	Average Price Paid per Share
	(In thousands)
January 1, 2015—January 31, 2015	—	$	—
February 1, 2015—February 28, 2015	1	8.77
March 1, 2015—March 31, 2015	4	8.98
April 1, 2015—April 30, 2015	196	9.53
May 1, 2015—May 31, 2015	1,470	9.31
June 1, 2015—June 30 2015	23	8.87
Total	1,694	9.33

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

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).

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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, 2015. 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, 2015, as the case may be, additional reportable transactions may be disclosed by such companies.

As of June 30, 2015, 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, 2015.

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”), a company that may be considered an affiliate of Warburg Pincus. Because both 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, 2015

“An Iranian national, resident in the U.K., who is currently designated by the U.S. under the Iranian Financial Sanctions Regulations and the Weapons of Mass Destruction Proliferators Sanctions Regulations (“NPWMD sanctions program”), holds a mortgage with Santander UK that was issued prior to any such designation. No further drawdown has been made (or would be allowed) under this mortgage although Santander UK continues to receive repayment installments. In the first half of 2015, total revenue in connection with the mortgage was approximately £1,780 while net profits were negligible relative to the overall profits of Santander UK. 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 holds two investment accounts with Santander Asset Management UK Limited. The accounts have remained frozen during the first half of 2015. The investment returns are being automatically reinvested, and no disbursements have been made to the customer. Total revenue for the Group in connection with the investment accounts was approximately £120 while net profits in the first quarter of 2015 were negligible relative to the overall profits of Banco Santander, S.A.”

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 disclosed 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.

Disclosure relating to Blackstone and its affiliates

Blackstone informed us of the information reproduced below (the “Travelport Disclosure”) regarding Travelport Limited (“Travelport”), a company that may be considered one of Blackstone’s affiliates. Because both we and Travelport may be deemed to be controlled by Blackstone, we may be considered an “affiliate” of Travelport for the purposes of Section 13(r) of the Exchange Act.

Travelport Disclosure:

Quarter ended June 30, 2015

“As part of our global business in the travel industry, we provide certain passenger travel related Travel Commerce Platform and Technology Services to Iran Air. We also provide certain Technology Services to Iran Air Tours. All of these services are either exempt from applicable sanctions prohibitions pursuant to a statutory exemption permitting transactions ordinarily incident to travel or, to the extent not otherwise exempt, specifically licensed by the U.S. Office of Foreign Assets Control. Subject to any changes in the exempt/licensed status of such activities, we intend to continue these business activities, which are directly related to and promote the arrangement of travel for individuals.”

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

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 3, 2015	/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
10.1†*		Offer Letter, dated February 11, 2008 between Kosmos Energy, LLC and Eric J. Haas.

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.

† Management contract or compensatory plan or arrangement.