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, 2014

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 28, 2014
Common Shares, $0.01 par value		386,830,220

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TABLE OF CONTENTS

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

	Page
PART I. FINANCIAL INFORMATION

Glossary and Select Abbreviations	3

Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	6
Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013	7
Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2014 and 2013	8
Consolidated Statements of Shareholders’ Equity for the six months ended June 30, 2014	9
Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013	10
Notes to Consolidated Financial Statements	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3. Quantitative and Qualitative Disclosures about Market Risk	33
Item 4. Controls and Procedures	34

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	35
Item 1A. Risk Factors	35
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 3. Defaults Upon Senior Securities	36
Item 4. Mine Safety Disclosures	36
Item 5. Other Information	36
Item 6. Exhibits	37
Signatures	38
Index to Exhibits	39

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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.

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

“Farm-out”		An agreement whereby the owner of the participating interest agrees to assign a portion of its participating interest in a block to another party for cash 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) net present value of net cash flow through the depletion of the Jubilee Field plus the net present value 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.

“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 net cash flow through the final maturity date of the Facility plus the net present value of 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.

“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 them fail neither oil nor natural gas will 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”		Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.

“Proved undeveloped reserves”		Proved undeveloped reserves are 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 does not convey an exclusive option to explore for, develop, and/or produce hydrocarbons from the lease area.

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

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

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

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

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

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

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

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

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

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KOSMOS ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	June 30,			December 31,
	2014			2013
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	621,631		$	598,108
Restricted cash	19,552			21,475
Receivables:
Joint interest billings	33,324			19,930
Oil sales	115,987			281
Other	7,646			1,115
Inventories	39,839			47,424
Prepaid expenses and other	51,706			27,010
Current deferred tax assets	15,864			19,618
Total current assets	905,549			734,961

Property and equipment:
Oil and gas properties, net	1,551,427			1,508,062
Other property, net	12,977			14,900
Property and equipment, net	1,564,404			1,522,962

Other assets:
Restricted cash	35,250			31,500
Deferred financing costs, net of accumulated amortization of $28,186 and $24,976 at June 30, 2014 and December 31, 2013, respectively	52,692			40,111
Long-term deferred tax assets	20,161			16,292
Total assets	$	2,578,056		$	2,345,826

Liabilities and shareholders’ equity
Current liabilities:
Accounts payable	$	88,728		$	94,172
Accrued liabilities	216,830			115,212
Derivatives	21,380			9,940
Total current liabilities	326,938			219,324

Long-term liabilities:
Long-term debt	800,000			900,000
Derivatives	13,973			3,811
Asset retirement obligations	41,731			39,596
Deferred tax liability	224,767			170,226
Other long-term liabilities	17,689			20,534
Total long-term liabilities	1,098,160			1,134,167

Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at June 30, 2014 and December 31, 2013	—			—
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 392,285,186 and 391,974,287 issued at June 30, 2014 and December 31, 2013, respectively	3,923			3,920
Additional paid-in capital	1,821,468			1,781,535
Accumulated deficit	(642,744		)	(774,220		)
Accumulated other comprehensive income	1,347			2,158
Treasury stock, at cost, 5,490,138 and 4,400,135 shares at June 30, 2014 and December 31, 2013, respectively	(31,036		)	(21,058		)
Total shareholders’ equity	1,152,958			992,335
Total liabilities and shareholders’ equity	$	2,578,056		$	2,345,826

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,
	2014		2013			2014		2013
Revenues and other income:
Oil and gas revenue	$	328,297	$	193,413		$	541,150	$	421,479
Gain on sale of assets	—		—			23,769		—
Interest income	196		44			254		114
Other income	869		321			1,308		575

Total revenues and other income	329,362		193,778			566,481		422,168

Costs and expenses:
Oil and gas production	22,946		22,674			39,269		47,075
Exploration expenses	23,509		94,522			36,318		118,777
General and administrative	32,480		41,639			59,893		80,710
Depletion and depreciation	69,546		58,562			115,924		117,211
Amortization—deferred financing costs	2,559		2,785			5,345		5,483
Interest expense	7,635		10,017			11,146		19,008
Derivatives, net	21,566		(12,707		)	19,538		(7,199		)
Restructuring charges	11,804		—			11,804		—
Loss on extinguishment of debt	—		—			2,898		—
Other expenses, net	26		849			1,303		1,481

Total costs and expenses	192,071		218,341			303,438		382,546

Income (loss) before income taxes	137,291		(24,563		)	263,043		39,622
Income tax expense	80,784		46,253			131,567		90,344

Net income (loss)	$	56,507	$	(70,816	)	$	131,476	$	(50,722	)

Net income (loss) per share:
Basic	$	0.15	$	(0.19	)	$	0.34	$	(0.13	)
Diluted	$	0.15	$	(0.19	)	$	0.34	$	(0.13	)

Weighted average number of shares used to compute net income (loss) per share:
Basic	378,820		376,563			378,327		375,927
Diluted	381,818		376,563			381,157		375,927

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,
	2014			2013			2014			2013

Net income (loss)	$	56,507		$	(70,816	)	$	131,476		$	(50,722	)
Other comprehensive income:
Reclassification adjustments for gains on cash flow hedges included in net income (loss)	(405		)	(358		)	(811		)	(717		)
Other comprehensive income	(405		)	(358		)	(811		)	(717		)
Comprehensive income (loss)	$	56,102		$	(71,174	)	$	130,665		$	(51,439	)

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, 2013	391,974	$	3,920	$	1,781,535		$	(774,220	)	$	2,158		$	(21,058	)	$	992,335
Equity-based compensation	—	—		40,898			—			—			—			40,898
Derivatives, net	—	—		—			—			(811		)	—			(811		)
Restricted stock awards and units	311	3		(3		)	—			—			—			—
Restricted stock forfeitures	—	—		1			—			—			(1		)	—
Purchase of treasury stock	—	—		(963		)	—			—			(9,977		)	(10,940		)
Net income	—	—		—			131,476			—			—			131,476
Balance as of June 30, 2014	392,285	$	3,923	$	1,821,468		$	(642,744	)	$	1,347		$	(31,036	)	$	1,152,958

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended June 30,
	2014			2013
Operating activities
Net income (loss)	$	131,476		$	(50,722	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	121,269			122,694
Deferred income taxes	55,817			52,646
Unsuccessful well costs	2,815			85,668
Change in fair value of derivatives	22,301			(3,302		)
Cash settlements on derivatives	(1,510		)	(15,144		)
Equity-based compensation	40,898			37,000
Gain on sale of assets	(23,769		)	—
Loss on extinguishment of debt	2,898			—
Other	(4,132		)	2,827
Changes in assets and liabilities:
(Increase) decrease in receivables	(135,631		)	88,092
(Increase) decrease in inventories	7,519			(11,927		)
Increase in prepaid expenses and other	(24,696		)	(3,939		)
Decrease in accounts payable	(5,444		)	(64,900		)
Increase in accrued liabilities	96,250			37,877
Net cash provided by operating activities	286,061			276,870

Investing activities
Oil and gas assets	(186,463		)	(166,581		)
Other property	(914		)	(3,278		)
Proceeds on sale of assets	58,315			—
Restricted cash	(1,827		)	1,965
Net cash used in investing activities	(130,889		)	(167,894		)

Financing activities
Payments on long-term debt	(100,000		)	(100,000		)
Purchase of treasury stock	(10,940		)	(13,041		)
Deferred financing costs	(20,709		)	(2,225		)
Net cash used in financing activities	(131,649		)	(115,266		)

Net increase (decrease) in cash and cash equivalents	23,523			(6,290		)
Cash and cash equivalents at beginning of period	598,108			515,164
Cash and cash equivalents at end of period	$	621,631		$	508,874

Supplemental cash flow information
Cash paid for:
Interest	$	15,302		$	17,198
Income taxes	$	44,367		$	28,722

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.

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, Morocco (including Western Sahara) and Suriname. 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, 2014, the changes in the consolidated statements of shareholders’ equity for the six months ended June 30, 2014, the consolidated results of operations for the three and six months ended June 30, 2014 and 2013, and consolidated cash flows for the six months ended June 30, 2014 and 2013. 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, 2013, 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 loss, current assets, total assets, current liabilities, total liabilities or shareholders’ equity.

Restricted Cash

In accordance with our commercial debt 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. As of June 30, 2014 and December 31, 2013, we had $18.6 million and $18.6 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, 2014 and December 31, 2013, we had $1.0 million and $2.9 million, respectively, of current restricted cash and $35.3 million and $31.5 million, respectively, of long-term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts.

Inventories

Inventories consisted of $39.8 million and $45.8 million of materials and supplies and nil and $1.6 million of hydrocarbons as of June 30, 2014 and December 31, 2013, 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.

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Variable Interest Entity

Our wholly owned subsidiary, Kosmos Energy Finance International, is a variable interest entity (“VIE”). The Company is the primary beneficiary of this VIE, which is consolidated in these financial statements.

The following assets and liabilities of Kosmos Energy Finance International are shown separately on the face of the consolidated balance sheets as of June 30, 2014 and December 31, 2013: long-term debt and long-term derivatives liabilities. At June 30, 2014, Kosmos Energy Finance International had $38.6 million in cash and cash equivalents; $18.6 million in current restricted cash; $48.2 million deferred financing costs, net; $0.9 million in accounts payable; $0.1 million in accrued liabilities; $18.0 million in current derivatives and $4.4 million in other long-term liabilities, which are included in the amounts shown on the face of the consolidated balance sheets. At December 31, 2013, Kosmos Energy Finance International had $38.1 million in cash and cash equivalents; $18.6 million in current restricted cash; $0.2 million in prepaid expenses and other; $34.2 million deferred financing costs, net; $1.4 million in accrued liabilities; $9.9 million in current derivatives and $8.2 million in other long-term liabilities, which are included in the amounts shown on the face of the consolidated balance sheets.

Restructuring Charges

The Company accounts for restructuring charges in accordance with ASC 420-Exit or Disposal Cost Obligations. Under these standards, the costs associated with restructuring charges are recorded during the period in which the liability is incurred. During the three months and 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 accelerated non-cash expense related to awards previously granted under our Long-Term Incentive Plan (the “LTIP”).

3. Property and Equipment

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

	June 30,			December 31,
	2014			2013
	(In thousands)
Oil and gas properties:
Proved properties	$	837,519		$	801,348
Unproved properties	628,688			524,257
Support equipment and facilities	724,238			710,289
Total oil and gas properties	2,190,445			2,035,894
Less: accumulated depletion	(639,018		)	(527,832		)
Oil and gas properties, net	1,551,427			1,508,062

Other property	32,273			31,658
Less: accumulated depreciation	(19,296		)	(16,758		)
Other property, net	12,977			14,900

Property and equipment, net	$	1,564,404		$	1,522,962

We recorded depletion expense of $67.2 million and $56.4 million for the three months ended June 30, 2014 and 2013, respectively and $111.2 million and $113.1 million for the six months ended June 30, 2014 and 2013, respectively.

In the first quarter of 2014, the Moroccan government issued a joint ministerial order approving a partial sale of our participating interests to BP Exploration (Morocco) Limited, a wholly owned subsidiary of BP plc (“BP”), covering our three blocks in the Agadir Basin, offshore Morocco. Upon receipt of this order, we closed the partial sale with BP. Certain governmental administrative processes required to officially reflect the transactions under Moroccan law are expected to be completed in due course. Under the terms of the agreements, BP acquired a non-operating interest in each of the Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks. The sales price of the farm-outs was $56.9 million. All proceeds have been received as of June 30, 2014. After giving effect to these farm-outs, our participating interests are 30.0%, 29.925% and 30.0% in the Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks, respectively, and we remain the operator. The proceeds on the sale of the interests exceeded our book basis in the assets, resulting in a $23.8 million gain on the transaction.

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In the first quarter of 2014, the Moroccan government issued a joint ministerial order approving a partial sale of our participating interest to Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”), covering the Cap Boujdour Offshore block, offshore Western Sahara. Upon receipt of this order, we closed the partial sale with Cairn. Certain governmental administrative processes required to officially reflect the transaction under Moroccan law are expected to be completed in due course. During the second quarter of 2014, Cairn paid $1.5 million for their share of costs incurred from the effective date of the farm-out agreement through the closing date, which was recorded as a reduction in our basis. After giving effect to the farm-out, our participating interest in the Cap Boujdour Offshore block is 55.0% and we remain the operator.

4. 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, 2014. The table excludes $2.8 million in costs that were capitalized and subsequently expensed during the same period.

	Six Months Ended June 30, 2014
	(In thousands)
Beginning balance	$	376,166
Additions to capitalized exploratory well costs pending the determination of proved reserves	46,265
Reclassification due to determination of proved reserves	—
Capitalized exploratory well costs charged to expense	—
Ending balance	$	422,431

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, 2014		December 31, 2013
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	45,638	$	11,426
Exploratory well costs capitalized for a period of one to two years	171,871		229,140
Exploratory well costs capitalized for a period of three to five years	204,922		135,600
Ending balance	$	422,431	$	376,166
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	8		8

As of June 30, 2014, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Mahogany, Teak-1, Teak-2 and Akasa discoveries in the West Cape Three Points (“WCTP”) Block and the Tweneboa, Enyenra, Ntomme and Wawa discoveries in the Deepwater Tano (“DT”) Block, which are all in Ghana.

Effective January 14, 2014, the Ministry of Energy and Ghana National Petroleum Corporation (“GNPC”) entered into a Memorandum of Understanding with Kosmos Energy, on behalf of the WCTP Petroleum Agreement (“PA”) Block partners, wherein all parties have settled all matters pertaining to the Notices of Dispute for the Mahogany East PoD, and the Ministry of Energy has approved the Appraisal Programs for the Mahogany, Teak, and Akasa discoveries.

Mahogany— Three appraisal wells have been drilled. Additionally, we deepened a development well in the Jubilee Field to further appraise the Mahogany discovery. Following additional appraisal and evaluation, a decision regarding commerciality of the Mahogany discovery is expected to be made by the WCTP Block partners in early 2015. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP PA.

Teak-1 Discovery—Two appraisal wells have been drilled. Following additional appraisal and evaluation, a decision regarding commerciality of the Teak-1 discovery is expected to be made by the WCTP Block partners in early 2015. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP PA.

Teak-2 Discovery—We have performed a gauge installation on the well and are reprocessing seismic data. Following additional appraisal and evaluation, a decision regarding commerciality of the Teak-2 discovery is expected to be made by the WCTP Block partners in early 2015. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP PA.

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Akasa Discovery—We performed a drill stem test and gauge installation on the discovery well and drilled one appraisal well. Following additional appraisal and evaluation, a decision regarding commerciality of the Akasa discovery is expected to be made by the WCTP Block partners in early 2015. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP PA.

Tweneboa, Enyenra and Ntomme (“TEN”) Discoveries—In May 2013, the government of Ghana approved the PoD over the TEN discoveries. Development of TEN is expected to include the drilling and completion of up to 24 development wells, half of the wells are designed as producers, with the remaining wells designed for water or gas injection. The TEN project is expected to deliver first oil in the second half of 2016. The costs associated with the TEN development will remain as unproved property pending the determination of whether the discoveries are associated with proved reserves.

Wawa Discovery—We are currently reprocessing 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 is expected to be made by the DT Block partners in 2015. Within six months of such declaration, a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the DT PA.

5. Accrued Liabilities

Accrued liabilities consisted of the following:

	June 30,		December 31,
	2014		2013
	(In thousands)
Accrued liabilities:
Accrued exploration, development and production	$	130,350	$	73,976
Income taxes	56,673		20,379
Accrued taxes other than income	16,857		15,188
Accrued general and administrative expenses	10,906		4,255
Accrued other	2,044		1,414
	$	216,830	$	115,212

6. Debt

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. 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, 2014, we have $48.2 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, 2014, borrowings under the Facility totaled $800.0 million and the undrawn availability under the Facility was $700.0 million.

Interest is the aggregate of the applicable margin (3.25% to 4.50%, depending on the length of time that has passed from the date the Facility was entered into); LIBOR; and mandatory cost (if any, as defined in the Facility). Interest is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). We pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. Commitment fees are equal to 40% per annum of the then-applicable respective margin when a commitment is available for utilization and, equal to 20% per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835—Interest, which requires interest expense to be recognized using the effective interest method. As part of the March 2014 amendment, the Facility’s estimated effective interest rate was changed and, accordingly, we adjusted our estimate of deferred interest previously recorded during prior years by $4.5 million, which was recorded as a reduction to interest expense.

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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, 2014, we had no letters of credit issued under the Facility.

Kosmos has the right to cancel all the undrawn commitments under the Facility. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined each year on March 31 and September 30 as part of a forecast that is prepared by and agreed to by us and the Technical and Modeling Bank and the Facility Agent. The formula to calculate the borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources.

If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. The Facility contains customary cross default provisions.

We were in compliance with the financial covenants contained in the Facility as of the March 31, 2014 forecast (the most recent assessment date).

Corporate Revolver

In November 2012, we secured a Corporate Revolver from a number of financial institutions. In April 2013, the availability under the Corporate Revolver was increased from $260.0 million to $300.0 million due to additional commitments received from existing and new financial institutions. As of June 30, 2014, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $300.0 million. The Corporate Revolver contains customary cross default provisions.

Revolving Letter of Credit Facility

In July 2013, we entered into a 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, 2014, we had $35.3 million of restricted cash collateralizing seven outstanding letters of credit under the LC Facility. The LC Facility contains customary cross default provisions.

At June 30, 2014, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:

	Payments Due by Year
	2014(1)		2015		2016		2017		2018		Thereafter
	(In thousands)
Facility(2)	$	—	$	—	$	—	$	—	$	35,812	$	764,188

(1) Represents payments for the period July 1, 2014 through December 31, 2014.

(2) The scheduled maturities of debt are based on the level of borrowings and the estimated future available borrowing base as of June 30, 2014. Any increases or decreases in the level of borrowings or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.

7. 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, 2014.

			Weighted Average Dated Brent Price per Bbl
Term	Type of Contract	MBbl	Net Deferred Premium Payable		Swap		Floor		Ceiling		Call
2014:
July — December	Three-way collars	3,014	$	0.01	$	—	$	88.44	$	113.75	$	134.58
2015:
January — December	Three-way collars	3,230	$	0.60	$	—	$	87.32	$	110.00	$	135.00
January — December	Swaps with calls	2,000	—		99.00		—		—		115.00
2016:
January — December	Purchased puts	2,000	$	3.41	$	—	$	85.00	$	—	$	—

Provisional Oil Sales

At June 30, 2014, we had sales volumes of 973.8 MBbls provisionally priced at an average of $113.84 per Bbl, after differentials, which are subject to final pricing over the next month.

Interest Rate Swap Derivative Contracts

The following table summarizes our open interest rate swaps as of June 30, 2014, whereby we pay a fixed rate of interest and the counterparty pays a variable LIBOR-based rate:

Term	Weighted Average Notional Amount		Weighted Average Fixed Rate		Floating Rate
	(In thousands)
July 2014 — December 2014	$	110,555	1.93	%	6-month LIBOR
January 2015 — December 2015	45,319		2.03	%	6-month LIBOR
January 2016 — June 2016	12,500		2.27	%	6-month LIBOR

The following tables disclose the Company’s derivative instruments as of June 30, 2014 and December 31, 2013 and gain/(loss) from derivatives during the three and six months ended June 30, 2014 and 2013, respectively:

		Estimated Fair Value Asset (Liability)
		June 30,			December 31,
Type of Contract	Balance Sheet Location	2014			2013
		(In thousands)
Derivatives not designated as hedging instruments:

Derivative liabilities:
Commodity(1)	Derivatives liabilities—current	$	(20,027	)	$	(7,873	)
Interest rate	Derivatives liabilities—current	(1,353		)	(2,067		)
Commodity(2)	Derivatives liabilities—long-term	(13,710		)	(3,144		)
Interest rate	Derivatives liabilities—long-term	(263		)	(667		)
Total derivatives not designated as hedging instruments		$	(35,353	)	$	(13,751	)

(1) Includes $3.4 million and zero as of June 30, 2014 and December 31 2013, respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of $0.9 million and $0.1 million related to commodity derivative contracts as of June 30, 2014 and December 31, 2013, respectively.

(2) Includes net deferred premiums payable of $7.9 million and $6.5 million related to commodity derivative contracts as of June 30, 2014 and December 31, 2013, 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)	2014			2013			2014			2013
		(In thousands)
Derivatives in cash flow hedging relationships:
Interest rate(1)	Interest expense	$	405		$	358		$	811		$	717
Total derivatives in cash flow hedging relationships		$	405		$	358		$	811		$	717

Derivatives not designated as hedging instruments:
Commodity(2)	Oil and gas revenue	$	(1,841	)	$	(9,252	)	$	(3,367	)	$	(4,664	)
Commodity	Derivatives, net	(21,566		)	12,707			(19,538		)	7,199
Interest rate	Interest expense	(109		)	23			(207		)	50
Total derivatives not designated as hedging instruments		$	(23,516	)	$	3,478		$	(23,112	)	$	2,585

(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, 2014 and December 31, 2013, 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, 2014 and December 31, 2013.

8. Fair Value Measurements

In accordance with ASC 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, 2014 and December 31, 2013, 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, 2014
Liabilities:
Commodity derivatives	$	—	$	(33,737	)	$	—	$	(33,737	)
Interest rate derivatives	—		(1,616		)	—		(1,616		)
Total	$	—	$	(35,353	)	$	—	$	(35,353	)

December 31, 2013
Liabilities:
Commodity derivatives	$	—	$	(11,017	)	$	—	$	(11,017	)
Interest rate derivatives	—		(2,734		)	—		(2,734		)
Total	$	—	$	(13,751	)	$	—	$	(13,751	)

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. The carrying values of our debt approximates fair value since they are subject to short-term floating interest rates that approximate the rates available to us for those periods. 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, purchased puts and swaps with calls 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 7—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 subject to provisional pricing and (ii) an independently sourced forward curve over the term of the provisional pricing period.

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. 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.

9. 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 LTIP awards. We recorded compensation expense from awards granted under our LTIP of $18.0 million and $18.1 million during the three months ended June 30, 2014 and 2013, respectively, and $35.9 million and $37.0 million during the six months ended June 30, 2014 and 2013. During the three and six months ended June 30, 2014, an additional $5.0 million of equity-based compensation was recorded as restructuring charges. The total tax benefit for the three months ended June 30, 2014 and 2013 was $8.0 million and $6.3 million, respectively, and for the six months ended June 30, 2014 and 2013 was $14.1 million and $12.7 million. Additionally, we expensed a tax shortfall related to equity-based compensation of $6.4 million and $6.9 million for the three months ended June 30,

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2014 and 2013, respectively, and $6.5 million and $6.9 million for the six months ended June 30, 2014 and 2013 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. 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, 2014:

			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, 2013	6,384		$	16.48	3,438		$	12.95
Granted	—		—		—		—
Forfeited	(104	)	15.85		(33	)	8.94
Vested	(2,783	)	17.06		—		—
Outstanding at June 30, 2014	3,497		16.03		3,405		12.98

The following table reflects the outstanding restricted stock units as of June 30, 2014:

			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, 2013	2,238		$	10.74	1,858		$	15.59
Granted	1,910		10.97		1,438		15.44
Forfeited	(343	)	10.92		(152	)	15.44
Vested	(403	)	10.85		—		—
Outstanding at June 30, 2014	3,402		10.84		3,144		15.53

As of June 30, 2014, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $122.5 million over a weighted average period of 1.75 years. At June 30, 2014, the Company had approximately 2.2 million shares that remain available for issuance under the LTIP.

For restricted stock awards 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. The grant date fair value of these awards ranged from $6.70 to $13.57 per award. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 41.3% to 56.7%. 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 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 200% of the awards granted. The grant date fair value of these awards ranged from $15.44 to $15.81 per award. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 53.0% to 54.0%. 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 0.7%.

10. Income Taxes

Income tax expense was $80.8 million and $46.3 million for the three months ended June 30, 2014 and 2013, respectively, and $131.6 million and $90.3 million for the six months ended June 30, 2014 and 2013, respectively. The income tax provision consists of United States and Ghanaian income and Texas margin taxes.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
Bermuda	$	(6,904	)	$	(6,663	)	$	(12,219	)	$	(13,440	)
United States	4,207			2,903			7,494			5,273
Foreign—other	139,988			(20,803		)	267,768			47,789
Income (loss) before income taxes	$	137,291		$	(24,563	)	$	263,043		$	39,622

Our effective tax rate for the three months ended June 30, 2014 and 2013 is 59% and (188)%, respectively. For the six months ended June 30, 2014 and 2013, our effective tax rate is 50% and 228%, respectively. The effective tax rate for the United States is approximately 193% and 274% for the three months ended June 30, 2014 and 2013, respectively, and 128% and 167% for the six months ended June 30, 2014 and 2013, 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 36% and 34% for the three months ended June 30, 2014 and 2013, respectively, and 36% for the six months ended June 30, 2014 and 2013. 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.

The Company has no material unrecognized income tax benefits.

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 the Company operates. The Company is open to U.S. federal income tax examinations for tax years 2012 through 2013 and to Texas margin tax examinations for the tax years 2009 through 2013. In addition, the Company is open to income tax examinations for years 2004 through 2013 in its significant other foreign jurisdictions (Ghana, Cameroon, Mauritania, Suriname and Morocco).

As of June 30, 2014, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense, but have not accrued any material amounts to date.

11. 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 per share:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(In thousands, except per share data)
Numerator:
Net income (loss)	$	56,507		$	(70,816	)	$	131,476		$	(50,722	)
Less: Basic income allocable to participating securities(1)	(721		)	—			(1,920		)	—
Basic net income (loss) allocable to common shareholders	55,786			(70,816		)	129,556			(50,722		)
Diluted adjustments to income allocable to participating securities(1)	6			—			15			—
Diluted net income (loss) allocable to common shareholders	$	55,792		$	(70,816	)	$	129,571		$	(50,722	)
Denominator:
Weighted average number of shares used to compute net income (loss) per share:
Basic	378,820			376,563			378,327			375,927
Restricted stock awards and units(1)(2)	2,998			—			2,830			—
Diluted	381,818			376,563			381,157			375,927
Net income (loss) per share:
Basic	$	0.15		$	(0.19	)	$	0.34		$	(0.13	)
Diluted	$	0.15		$	(0.19	)	$	0.34		$	(0.13	)

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(1) Our service vesting restricted stock awards represent participating securities because they participate in nonforfeitable 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 of 4.4 million and 14.2 million for the three months ended June 30, 2014 and 2013, respectively, and 4.4 million and 14.2 million for the six months ended June 30, 2014 and 2013, respectively, from the computations of diluted net income per share because the effect would have been anti-dilutive.

12. Commitments and Contingencies

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 drillship “Atwood Achiever.” Currently under construction, the rig is expected to commence drilling operations in the second half of 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 two rig slots (estimated to be 150 days in total during 2015) were assigned to a third-party. The estimated rig delivery date is in the third quarter of 2014.

The estimated future minimum commitments under this contract as of June 30, 2014, are:

	Payments Due By Year(1)
	Total		2014(2)		2015		2016		2017		2018		Thereafter
	(In thousands)
Operating leases	$	18,722	$	2,372	$	3,515	$	3,158	$	3,223	$	3,323	$	3,131
Atwood Achiever drilling rig contract (3)	562,870		91,035		127,925		217,770		126,140		—		—

(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, 2014 through December 31, 2014.

(3) Commitments calculated using a day rate of $595,000 and assuming a rig delivery date of August 1, 2014. The rig commitments reflect the execution of a rig sharing agreement, whereby two rig slots (estimated to be 150 days in total during 2015) were assigned to a third-party.

13. Subsequent Events

During August 2014, the Company issued $300.0 million of 7.875% Senior Notes due 2021 (the “Notes”) and received net proceeds of $292.5 million after deducting discounts, commissions and other expenses. The Company expects to use the net proceeds of the offering of the Notes to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.

The Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by the Company in its direct subsidiary, Kosmos Energy Holdings. The Notes are currently guaranteed on a subordinated, unsecured basis by Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development, Kosmos Energy Ghana HC and Kosmos Energy Finance International, being the Company’s subsidiaries that guarantee the Facility and the Corporate Revolver.

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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, 2013, 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 were incorporated pursuant to the laws of Bermuda as Kosmos Energy Ltd. in January 2011 to become a holding company for Kosmos Energy Holdings. Pursuant to the terms of a corporate reorganization that was completed immediately prior to the closing of Kosmos Energy Ltd.’s IPO on May 16, 2011, all of the interests in Kosmos Energy Holdings were exchanged for newly issued common shares of Kosmos Energy Ltd. As a result, Kosmos Energy Holdings became wholly owned by Kosmos Energy Ltd.

Recent Developments

Corporate

During the second quarter of 2014, we recognized $11.8 million in restructuring charges for employee severance and related benefits during the second quarter of 2014, which includes $5.0 million of accelerated non-cash expense related to awards previously granted under the Long-Term Incentive Plan (the “LTIP”).

Ghana

In May 2014, we completed a 3D seismic program of approximately 940 square kilometers over the Tweneboa, Enyenra, and Ntomme (“TEN”) development and Wawa appraisal areas in the Deepwater Tano (“DT”) Block.

GNPC notified us and our block partners that it would exercise its right for the contractor group to pay its 5% share of the TEN development costs, currently estimated as $4.9 billion (gross). Our portion of GNPC’s share is estimated at $49.0 million. The block partners will be reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues under the terms of the DT PA. We expect to begin paying our share of such costs in the third quarter of 2014.

Approval was granted by the Government of Ghana and the Ghanaian Environmental Protection Agency in June 2014 to permit the flaring of 500 MMcf of gas per month from the Jubilee field until the end of October 2014. This limited flaring is expected to assist in the maintenance of existing production levels until the Western Corridor Gas Infrastructure (Jubilee Gas Export) is operational.

Morocco

In July 2014, we completed a 3D seismic program of approximately 4,300 square kilometers over the Tarhazoute Offshore and Essaouira Offshore blocks. In June 2014, we commenced a 3D seismic survey of approximately 5,100 square kilometers over the Cap Boujdour Offshore block which is expected to be completed in the third quarter of 2014.

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In the first quarter of 2014, the Moroccan government issued a joint ministerial order approving a partial sale of our participating interests to BP Exploration (Morocco) Limited, a wholly owned subsidiary of BP plc (“BP”) covering our three blocks in the Agadir Basin, offshore Morocco. Upon receipt of this order, we closed the partial sale with BP. Certain governmental administrative processes required to officially reflect the transactions under Moroccan law are expected to be completed in due course. Under the terms of the agreements, BP acquired a non-operating interest in each of the Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks. The sales price of the farm-outs was $56.9 million. All proceeds have been received as of June 30, 2014. After giving effect to these farm-outs, our participating interests are 30.0%, 29.925% and 30.0% in the Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks, respectively, and we remain the operator. The proceeds on the sale of the interests exceeded our book basis in the assets, resulting in a $23.8 million gain on the transaction.

In Morocco, the FA-1 exploration well on the Foum Assaka Offshore block in the Agadir Basin was determined to be non-commercial and accordingly was plugged and abandoned. BP funded our share of the FA-1 exploration well, subject to a maximum gross spend of $120.0 million. During the second quarter of 2014, we expensed $2.8 million associated with the FA-1 well as Exploration Expense.

We entered the first extension period effective May 2014 on the Essaouira Offshore block, which requires us to drill one exploration well. After the required relinquishment of acreage to enter the first extension period, the Essaouira Offshore block comprises approximately 2.2 million acres (8,786 square kilometers).

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, 2014 and 2013, are included in the following table:

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(In thousands, except per barrel data)
Sales volumes:
MBbl	2,916		1,944		4,853		3,935

Revenues:
Oil sales	$	328,297	$	193,413	$	541,150	$	421,479
Average sales price per Bbl	112.58		99.51		111.50		107.11

Costs:
Oil production, excluding workovers	$	22,845	$	12,700	$	37,903	$	26,119
Oil production, workovers	101		9,974		1,366		20,956
Total oil production costs	$	22,946	$	22,674	$	39,269	$	47,075

Depletion	$	67,167	$	56,448	$	111,186	$	113,069

Average cost per Bbl:
Oil production, excluding workovers	$	7.84	$	6.54	$	7.81	$	6.63
Oil production, workovers	0.03		5.13		0.28		5.33
Total oil production costs	7.87		11.67		8.09		11.96

Depletion	23.03		29.04		22.91		28.73
Oil production cost and depletion costs	$	30.90	$	40.71	$	31.00	$	40.69

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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, 2014:

					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
West Cape Three Points	—	—	—	—	9	2.78	—	—
TEN	—	—	1	0.17	—	—	13	2.21
Deepwater Tano	—	—	—	—	1	0.18	—	—
Total	—	—	1	0.17	10	2.96	14	2.45

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, 2014 compared to three months ended June 30, 2013

	Three Months Ended June 30,					Increase
	2014		2013			(Decrease)
			(In thousands)
Revenues and other income:
Oil and gas revenue	$	328,297	$	193,413		$	134,884
Interest income	196		44			152
Other income	869		321			548
Total revenues and other income	329,362		193,778			135,584
Costs and expenses:
Oil and gas production	22,946		22,674			272
Exploration expenses	23,509		94,522			(71,013		)
General and administrative	32,480		41,639			(9,159		)
Depletion and depreciation	69,546		58,562			10,984
Amortization—deferred financing costs	2,559		2,785			(226		)
Interest expense	7,635		10,017			(2,382		)
Derivatives, net	21,566		(12,707		)	34,273
Restructuring charges	11,804		—			11,804
Other expenses, net	26		849			(823		)
Total costs and expenses	192,071		218,341			(26,270		)
Income before income taxes	137,291		(24,563		)	161,854
Income tax expense	80,784		46,253			34,531
Net income	$	56,507	$	(70,816	)	$	127,323

Oil and gas revenue. Oil and gas revenue increased by $134.9 million during the three months ended June 30, 2014 as compared to the three months ended June 30, 2013, primarily due to an increase in sales volumes, three liftings in 2014 compared to two in 2013, and a higher realized price per barrel. We lifted and sold approximately 2,916 MBbl at an average realized price per barrel of $112.58 during the three months ended June 30, 2014 and approximately 1,944 MBbl at an average realized price per barrel of $99.51 during the three months ended June 30, 2013.

Oil and gas production. Oil and gas production costs increased by $0.3 million during the three months ended June 30, 2014, as compared to the three months ended June 30, 2013. As compared to the three months ended June 30, 2013, we had an increase in routine operating costs associated with the increased sales volumes offset by a reduction in well workover costs and non-routine operating costs in the three months ended June 30, 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 decreased by $71.0 million during the three months ended June 30, 2014, as compared to the three months ended June 30, 2013. The decrease is primarily due to $75.6 million for unsuccessful well costs and other related costs for the Cameroon Sipo-1 exploration well incurred during the three months ended June 30, 2013.

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General and administrative. General and administrative costs decreased by $9.2 million during the three months ended June 30, 2014, as compared to the three months ended June 30, 2013. The decrease from prior year is related to an increase in capitalized general and administrative costs incurred and general and administrative costs for the benefit of and allocated to exploration expenses and a decrease in professional fees.

Depletion and depreciation. Depletion and depreciation increased $11.0 million during the three months ended June 30, 2014, as compared with the three months ended June 30, 2013. The increase is primarily due to depletion recognized related to the sale of three liftings of oil during the three months ended June 30, 2014, as compared to two liftings during the three months ended June 30, 2013. The increase in liftings is partially offset by a lower depletion rate during the three months ended June 30, 2014 due to an increase in proved reserves in the fourth quarter of 2013.

Interest expense. Interest expense decreased $2.4 million during the three months ended June 30, 2014, as compared with the three months ended June 30, 2013. The decrease is primarily due to a lower average outstanding debt balance during the three months ended June 30, 2014, as compared to the three months ended June 30, 2013.

Derivatives, net. During the three months ended June 30, 2014 and 2013, we recorded a loss of $21.6 million and a gain of $12.7 million, respectively, on our outstanding hedge positions. The gain and loss 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.

Income tax expense. The Company’s effective tax rates for the three months ended June 30, 2014 and 2013 were 59% and (188)%, 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 increased $34.5 million during the three months ended June 30, 2014, as compared with June 30, 2013, primarily due to an increase in pre-tax income from our Ghanaian subsidiary.

Six months ended June 30, 2014 compared to six months ended June 30, 2013

	Six Months Ended June 30,					Increase
	2014		2013			(Decrease)
			(In thousands)
Revenues and other income:
Oil and gas revenue	$	541,150	$	421,479		$	119,671
Gain on sale of assets	23,769		—			23,769
Interest income	254		114			140
Other income	1,308		575			733
Total revenues and other income	566,481		422,168			144,313
Costs and expenses:
Oil and gas production	39,269		47,075			(7,806		)
Exploration expenses	36,318		118,777			(82,459		)
General and administrative	59,893		80,710			(20,817		)
Depletion and depreciation	115,924		117,211			(1,287		)
Amortization—deferred financing costs	5,345		5,483			(138		)
Interest expense	11,146		19,008			(7,862		)
Derivatives, net	19,538		(7,199		)	26,737
Restructuring charges	11,804		—			11,804
Loss on extinguishment of debt	2,898		—			2,898
Other expenses, net	1,303		1,481			(178		)
Total costs and expenses	303,438		382,546			(79,108		)
Income before income taxes	263,043		39,622			223,421
Income tax expense	131,567		90,344			41,223
Net income	$	131,476	$	(50,722	)	$	182,198

Oil and gas revenue. Oil and gas revenue increased by $119.7 million during the six months ended June 30, 2014 as compared to the six months ended June 30, primarily due an increase in sales volumes, five liftings in 2014 compared to four in 2013, and a higher realized price per barrel. We lifted and sold approximately 4,853 MBbl at an average realized price per barrel of $111.50

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during the six months ended June 30, 2014 and approximately 3,935 MBbl at an average realized price per barrel of $107.11 during the six months ended June 30, 2013.

Gain on sale of assets. During the six months ended June 30, 2014, we closed three farm-out agreements with BP plc. As part of the transaction, we received proceeds in excess of our book basis, resulting in a gain of $23.8 million.

Oil and gas production. Oil and gas production costs decreased by $7.8 million during the six months ended June 30, 2014 as compared to the six months ended June 30, 2013. The change is due a reduction in well workover costs and non-routine operating costs in the six months ended June 30, 2014 as compared to the six months ended June 30, 2013, offsetting an increase in routine production costs due to incremental liftings in 2014 compared to 2013. 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 period.

Exploration expenses. Exploration expenses decreased by $82.5 million during the six months ended June 30, 2014, as compared to the six months ended June 30, 2013. The decrease is primarily due to $83.9 million of unsuccessful well costs and other related costs primarily related to the Cameroon Sipo-1 exploration well and the Ghana Sapele-1 exploration well incurred during the six months ended June 30, 2013.

General and administrative. General and administrative costs decreased by $20.8 million during the six months ended June 30, 2014, as compared to the six months ended June 30, 2013. The decrease from prior year is related to an increase in capitalized general and administrative costs and general and administrative costs incurred for the benefit of and allocated to exploration expense; a decrease in professional fees and occupancy and general expenses; and a decrease in operator charges partially offset by an increase in compensation and benefits.

Depletion and depreciation. Depletion and depreciation decreased $1.3 million during the six months ended June 30, 2014, as compared with the six months ended June 30, 2013. The change is due to the increase in proved reserves in the fourth quarter of 2013, which reduced the depletion rate used for the six months ended June 30, 2014, offset by an increase in depletion recognized related to the sale of five liftings of oil during the six months ended June 30, 2014, as compared to four liftings during the six months ended June 30, 2013.

Interest expense. Interest expense decreased $7.9 million during the six months ended June 30, 2014, as compared with the six months ended June 30, 2013, primarily due to a write-down of the deferred interest (reduction in interest expense) as a result of a decrease in the estimated effective interest rate based on the terms of the amended and restated Facility effective in March 2014 and a lower average outstanding debt balance during the six months ended June 30, 2014, as compared to the six months ended June 30, 2013.

Derivatives, net. During the six months ended June 30, 2014 and 2013, we recorded a loss of $19.5 million and a gain of $7.2 million, respectively, on our outstanding hedge positions. The gain and loss recorded were a result of changes in the forward curve of oil prices during the respective periods.

Income tax expense. The Company’s effective tax rates for the six months ended June 30, 2014 and 2013 were 50% and 228%, 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 increased $41.2 million during the six months ended June 30, 2014, as compared with June 30, 2013, primarily due to an increase in pre-tax income from 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 secured funding from issuances of equity and commercial debt facilities. In relation to cash flow generated from our operating activities, if we are unable to resolve issues related to the continuous removal of associated natural gas in large quantities from the Jubilee Field, and the production restraints caused thereby, then the Company’s cash flows from operations will be adversely affected. See “Item 1A. Risk Factors— section of this quarterly report on Form 10-Q and our annual report on Form 10-K

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Significant Sources of Capital

Facility

As of June 30, 2014, borrowings under the Facility totaled $800.0 million and the undrawn availability under the Facility was $700.0 million.

We were in compliance with the financial covenants contained in the Facility as of the March 31, 2014 forecast (the most recent assessment date).

Corporate Revolver

Revolving Letter of Credit Facility

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added. As of June 30, 2014, we had $35.3 million of restricted cash collateralizing seven outstanding letters of credit under the LC Facility. The LC Facility contains customary cross default provisions.

Senior Notes

During August 2014, the Company issued the Notes and received net proceeds of $292.5 million after deducting discounts, commissions and other expenses. The Company expects to use the net proceeds of the offering of the Notes to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.

The Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015. The 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 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 Notes will become guaranteed by certain of our other existing or future restricted subsidiaries (the “Guarantees”). As of the closing of the offering, the Notes were guaranteed by Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development, Kosmos Energy Ghana HC and Kosmos Energy Finance International.

Redemption and Repurchase. At any time prior to August 1, 2017 and subject to certain conditions, the Company may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of Notes issued under the indenture dated August 1, 2014 related to the Notes (the “Indenture”) at a redemption price of 107.875%, plus accrued and unpaid interest, with the cash proceeds of certain eligible equity offerings. Additionally, at any time prior to August 1, 2017, the Company may, on any one or more occasions, redeem all or a part of the Notes at a redemption price equal to 100%, plus any accrued and unpaid interest, and plus a make-whole premium. On or after August 1, 2017, the Company may redeem all or a part of the Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:

Year	Percentage
On or after August 1, 2017, but before August 1, 2018	103.938	%
On or after August 1, 2018, but before August 1, 2019	101.969	%
On or after August 1, 2019 and thereafter	100.000	%

We may also redeem the Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the Notes at a price equal to the principal amount of the Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted.

Upon the occurrence of a change of control triggering event as defined under the Indenture, the Company will be required to make an offer to repurchase Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.

If we sells assets, under certain circumstances outlined in the Indenture, we will be required to use the net proceeds to make an offer to purchase Notes at an offer price in cash in an amount equal to 100% of the principal amount of the Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.

Covenants. The Indenture restricts our ability and the ability of our restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of our subsidiaries to make dividends or other payments to us, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing.

Collateral. The Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all currently outstanding shares, additional shares, dividends or other distributions paid in respect of such shares or any other property derived from such shares, in each case held by us in relation to the Company’s direct subsidiary, Kosmos Energy Holdings, pursuant to the terms of the Charge over Shares of Kosmos Energy Holdings dated November 23, 2012, as amended and restated on March 14, 2014, between the Company and BNP Paribas as Security and Intercreditor Agent. The Notes share pari passu in the benefit of such equitable charge based on the respective amounts of the obligations under the Indenture and the amount of obligations under the Corporate Revolver. The Guarantees are not secured.

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Capital Expenditures and Investments

We expect to incur substantial costs as we continue to develop our oil and natural gas prospects and as we:

· execute our 2014 exploration and appraisal drilling program in our license areas;

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

· 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.

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 reliance on joint venture partners to meet their obligations, the costs involved in developing or participating in the development of a prospect, the timing of third-party projects, 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 hydrocarbon asset 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.

2014 Capital Program

Our estimate for the 2014 capital program is $575.0 million consisting of:

· approximately $400.0 million for developmental related expenditures offshore Ghana; and

· approximately $175.0 million for exploration and appraisal related expenditures, including new venture opportunities.

The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our exploration activities and drilling results. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil 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.

The following table presents our liquidity and financial position as of June 30, 2014:

	June 30, 2014
	(In thousands)
Cash and cash equivalents	$	621,631
Restricted cash	54,802
Drawings under the Facility	800,000
Net debt	123,567

Availability under the Facility	$	700,000
Availability under the Corporate Revolver	300,000
Available borrowings plus cash and cash equivalents(1)	1,621,631

(1) Does not include the Notes which were issued in August 2014. After the issuance of the Notes, our available borrowings plus cash and cash equivalents increased to approximately $1.9 billion.

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Cash Flows

	Six Months Ended June 30,
	2014			2013
	(In thousands)
Net cash provided by (used in):
Operating activities	$	286,061		$	276,870
Investing activities	(130,889		)	(167,894		)
Financing activities	(131,649		)	(115,266		)

Operating activities. Net cash provided by operating activities for the six months ended June 30, 2014 was $286.1 million compared with net cash provided by operating activities for the six months ended June 30, 2013 of $276.9 million. The increase in cash provided by operating activities in the six months ended June 30, 2014 when compared to the same period in 2013 was primarily due to an increase in results from operations offset by a negative change in working capital items.

Investing activities. Net cash used in investing activities for the six months ended June 30, 2014 was $130.9 million compared with net cash used in investing activities for the six months ended June 30, 2013 of $167.9 million. The decrease in cash used in investing activities in the six months ended June 30, 2014 when compared to the same period in 2013 was primarily attributable to proceeds from the sale of assets of $58.3 million offset by an increase in expenditures for oil and gas assets of $19.9 million during 2014.

Financing activities. Net cash used in financing activities for the six months ended June 30, 2014 was $131.6 million compared with net cash used in financing activities for the six months ended June 30, 2013 of $115.3 million. The increase in cash used in financing activities in the six months ended June 30, 2014 when compared to the same period in 2013 was primarily due an increase in deferred financing costs associated with the amendment to the Facility.

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of June 30, 2014:

	Payments Due By Year(4)
	Total		2014(5)		2015		2016		2017		2018		Thereafter
	(In thousands)
Facility(1)	$	800,000	$	—	$	—	$	—	$	—	$	35,812	$	764,188
Interest payments on long-term debt(2)	289,033		22,252		45,187		44,780		50,717		52,065		74,032
Operating leases	18,722		2,372		3,515		3,158		3,223		3,323		3,131
Atwood Achiever drilling rig contract(3)	562,870		91,035		127,925		217,770		126,140		—		—

(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, 2014. 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, 2014, 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.

(4) 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. Additionally does not include the repayment of principal or interest payments related to the Notes which were issued in August 2014.

(5) Represents payments for the period from July 1, 2014 through December 31, 2014.

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The following table presents maturities by expected maturity dates under the Facility, 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,
	2014			2015			2016			2017			2018			Thereafter			2014
	(In thousands, except percentages)
Variable rate debt:
Facility(1)	$	—		$	—		$	—		$	—		$	35,812		$	764,188		$	(800,000	)
Weighted average interest rate(2)	3.48		%	3.71		%	4.55		%	5.45		%	6.39		%	7.20		%
Interest rate swaps:
Notional debt amount(3)	$	35,000		$	16,875		$	6,250		$	—		$	—		$	—		$	(639	)
Fixed rate payable	2.22		%	2.22		%	2.22		%	—			—			—
Variable rate receivable(4)	0.33		%	0.58		%	1.17		%	—			—			—
Notional debt amount(3)	$	35,000		$	16,875		$	6,250		$	—		$	—		$	—		$	(670	)
Fixed rate payable	2.31		%	2.31		%	2.31		%	—			—			—
Variable rate receivable(4)	0.33		%	0.58		%	1.17		%	—			—			—
Notional debt amount(3)	$	40,555		$	23,137		$	—		$	—		$	—		$	—		$	(307	)
Fixed rate payable	1.34		%	1.34		%	—			—			—			—
Variable rate receivable(4)	0.33		%	0.43		%	—			—			—			—

(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.

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, 2014, 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, 2013.

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

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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 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) 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 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;

· environmental liabilities;

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

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

· the cost and availability of adequate insurance coverage;

· our vulnerability to severe weather events;

· our ability to meet our obligations under the agreements governing our indebtedness, including the indenture governing our senior notes ;

· 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;

· 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 policies. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8. Financial Statements and Supplementary Data—Note 2—Accounting Policies, Note 9—Derivative Financial Information 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 three months ended June 30, 2014:

	Derivative Contracts Assets (Liabilities)
	Commodities			Interest Rates			Total
	(In thousands)
Fair value of contracts outstanding as of December 31, 2013	$	(11,017	)	$	(2,734	)	$	(13,751	)
Changes in contract fair value	(22,905		)	(207		)	(23,112		)
Contract maturities	185			1,325			1,510
Fair value of contracts outstanding as of June 30, 2014	$	(33,737	)	$	(1,616	)	$	(35,353	)

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, purchased puts and swaps with calls. 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.

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, 2014:

			Weighted Average Dated Brent Price per Bbl										Asset(Liability)
Term	Type of Contract	MBbl	Net Deferred Premium Payable		Swap		Floor		Ceiling		Call		Fair Value at June 30, 2014(1)
2014:
July — December	Three-way collars	3,014	$	0.01	$	—	$	88.44	$	113.75	$	134.58	$	(5,292	)
2015:
January — December	Three-way collars	3,230	$	0.60	$	—	$	87.32	$	110.00	$	135.00	$	(12,692	)
January — December	Swaps with calls	2,000	—		99.00		—		—		115.00		(10,266		)
2016:
January — December	Purchased puts	2,000	$	3.41	$	—	$	85.00	$	—	$	—	$	(2,113	)

(1) Fair values are based on the average forward Dated Brent oil prices on June 30, 2014 which by year are: 2014—$111.26, 2015—$107.39 and 2016 — $102.89. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on July 28, 2014 market quotes by year are: 2014—$107.19, 2015—$105.56 and 2016—$102.05.

At June 30, 2014, our open commodity derivative instruments were in a net liability position of $33.7 million. As of
June 30, 2014, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $52.4 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $40.5 million.

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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, 2014, we had indebtedness outstanding under the Facility of $800.0 million, of which $689.4 million bore interest at floating rates. The interest rate on this indebtedness as of June 30, 2014 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 $700.0 million of undrawn availability under the Facility and on the $300.0 million of undrawn availability under the Corporate Revolver, which are not subject to changes in interest rates.

As of June 30, 2014, the fair market value of our interest rate swaps was a net liability of approximately $1.6 million. If LIBOR changed by 10%, we estimate 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, 2014, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure.

Evaluation of Changes in Internal Control over Financial Reporting

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

The risk factor below supplements the risks discussed in the “Item 1A. Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2013.

A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.

The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data.

We depend on digital technology, including information systems and related infrastructure as well as cloud application and services, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. Our business partners, including vendors, service providers, co-venturers, purchasers of our production, and financial institutions, are also dependent on digital technology. The complexity of the technologies needed to explore for and develop oil and gas in increasingly difficult physical environments, such as deepwater, and global competition for oil and gas resources make certain information more attractive to thieves.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. For example, in 2012, a wave of network attacks impacted Saudi Arabia’s oil industry and breached financial institutions in the U.S. Certain countries are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies.

Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations. Although to date we have not experienced any significant cyber-attacks, there can be no assurance that we will not be the target of cyber-attacks in the future or suffer such losses related to any cyber-incident. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

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

There have been no material changes from the information concerning the use of proceeds from our IPO discussed in the “Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” section of our annual report on Form 10-K.

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 withholding tax obligation owed by such grantee. The shares withheld from the grantees to settle their tax liability are reallocated to the number of shares available for issuance under the LTIP. The following table outlines the total number of shares withheld during the six months ended, June 30, 2014 and the average price paid per share.

	Total Number of Share Withheld/Purchased	Average Price Paid per Share
	(In thousands)
January 1, 2014—January 31, 2014	—	$	—
February 1, 2014—February 28, 2014	7	10.34
March 1, 2014—March 31, 2014	—	—
April 1, 2014—April 30, 2014	1	10.99
May 1, 2014—May 31, 2014	923	10.46
June 1, 2014—June 30, 2014	23	10.48
Total	954	10.46

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).

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, 2014. 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, 2014, as the case may be, additional reportable transactions may be disclosed by such companies.

As of the date hereof, funds affiliated with The Blackstone Group (“Blackstone”) held approximately 26% of our outstanding common shares, and funds affiliated with Warburg Pincus (“Warburg Pincus”) held approximately 32% 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

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of Blackstone and Warburg Pincus may be deemed an “affiliate” of us, both currently and during the fiscal quarter ended June 30, 2014.

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, 2014

“As part of our global business in the travel industry, we provide certain passenger travel-related GDS 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.

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 one of Warburg Pincus’s affiliates. 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, 2014

“Warburg Pincus understands that SAMIH’s affiliates intend to disclose in their next annual or quarterly SEC report that an Iranian national, resident in the U.K., who is currently designated by the U.S. under the Iranian Financial Sanctions Regulations and the NPWMD designation, holds two investment accounts with Santander Asset Management UK Limited. The accounts have remained frozen throughout 2013 and the first half of 2014. The investment returns are being automatically reinvested, and no disbursements have been made to the customer. In the first half of 2014, the total revenue for the Santander Group in connection with the investment accounts was £23,200 whilst net profits 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 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.

Item 6. Exhibits

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

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SIGNATURES

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

		Kosmos Energy Ltd.
		(Registrant)

Date	August 4, 2014	/s/ W. GREG DUNLEVY
		W. Greg Dunlevy
		Executive 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 September 1, 2011, between Kosmos Energy, LLC and Jason Doughty

10.2*		Offer Letter, dated May 22, 2013, between Kosmos Energy, LLC and Christopher Ball

10.3*		Assignment Agreement, dated April 16, 2014, between Kosmos Energy, LLC and Brian F. Maxted

10.4*		Separation and Release Agreement, dated May 12, 2014, between Kosmos Energy, LLC and Darrell McKenna

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.