Kosmos Energy Ltd. - Quarter Report: 2013 September (Form 10-Q)

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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 September 30, 2013

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 October 28, 2013
Common Shares, $0.01 par value		387,559,187

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

	Page
PART I. FINANCIAL INFORMATION

Glossary and Select Abbreviations	3

Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	6
Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012	7
Consolidated Statements of Comprehensive Loss for the three and nine months ended September 30, 2013 and 2012	8
Consolidated Statements of Shareholders’ Equity for the nine months ended September 30, 2013	9
Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	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	31
Item 4. Controls and Procedures	33

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	34
Item 1A. Risk Factors	34
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3. Defaults Upon Senior Securities	34
Item 4. Mine Safety Disclosures	34
Item 5. Other Information	34
Item 6. Exhibits	35
Signatures	36
Index to Exhibits	37

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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 (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) equity-based compensation expense, (4) (gain) loss on commodity derivatives, (5) (gain) loss on sale of oil and gas properties, (6) interest (income) expense, (7) income taxes, (8) loss on extinguishment of debt, (9) doubtful accounts expense, and (10) similar items.

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“E&P”		Exploration and production.

“FASB”		Financial Accounting Standards Board.

“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.

“FPSO”		Floating production, storage and offloading vessel.

“Ghana Obligors”		Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Finance International, Kosmos Energy Development, Kosmos Energy Ghana HC and an “Obligor” from time to time, as defined under the Facility Agreement, as amended and restated.

“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.

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“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.

“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 minerals 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 minerals 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 trap 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)

	September 30,			December 31,
	2013			2012
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	440,267		$	515,164
Restricted cash	19,377			21,341
Receivables:
Joint interest billings	71,591			21,539
Oil sales	113,067			108,995
Other	4,995			3,682
Inventories	33,118			33,281
Prepaid expenses and other	11,596			10,470
Current deferred tax assets	14,515			34,585
Derivatives	917			1,061
Total current assets	709,443			750,118

Property and equipment:
Oil and gas properties, net	1,486,224			1,510,312
Other property, net	15,490			15,450
Property and equipment, net	1,501,714			1,525,762

Other assets:
Restricted cash	24,634			29,884
Deferred financing costs, net of accumulated amortization of $22,191 and $13,922 at September 30, 2013 and December 31, 2012, respectively	42,897			50,214
Long-term deferred tax assets	14,808			10,145
Derivatives	1,583			—
Total assets	$	2,295,079		$	2,366,123

Liabilities and shareholders’ equity
Current liabilities:
Accounts payable	$	98,818		$	128,855
Accrued liabilities	115,866			41,021
Derivatives	9,458			20,377
Total current liabilities	224,142			190,253

Long-term liabilities:
Long-term debt	900,000			1,000,000
Derivatives	1,335			3,226
Asset retirement obligations	35,226			27,484
Deferred tax liability	145,193			104,137
Other long-term liabilities	18,886			12,117
Total long-term liabilities	1,100,640			1,146,964

Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2013 and December 31, 2012	—			—
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 391,956,419 and 391,423,703 issued at September 30, 2013 and December 31, 2012, respectively	3,920			3,914
Additional paid-in capital	1,763,227			1,712,880
Accumulated deficit	(778,386		)	(683,176		)
Accumulated other comprehensive income	2,563			3,685
Treasury stock, at cost, 4,397,232 and 2,731,941 shares at September 30, 2013 and December 31, 2012, respectively	(21,027		)	(8,397		)
Total shareholders’ equity	970,297			1,028,906
Total liabilities and shareholders’ equity	$	2,295,079		$	2,366,123

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Revenues and other income:
Oil and gas revenue	$	215,169		$	222,375		$	636,648		$	450,360
Interest income	77			137			191			1,165
Other income	133			725			708			930

Total revenues and other income	215,379			223,237			637,547			452,455

Costs and expenses:
Oil and gas production	32,576			44,873			79,651			71,791
Exploration expenses	78,038			38,127			194,384			96,134
General and administrative	35,646			39,898			118,787			112,558
Depletion and depreciation	58,367			63,794			175,578			128,442
Amortization—deferred financing costs	2,786			2,194			8,269			6,582
Interest expense	8,781			20,213			27,789			43,717
Derivatives, net	7,585			24,529			386			26,407
Other expenses, net	1,864			(64		)	3,345			728

Total costs and expenses	225,643			233,564			608,189			486,359

Income (loss) before income taxes	(10,264		)	(10,327		)	29,358			(33,904		)
Income tax expense	34,224			25,923			124,568			64,730

Net loss	$	(44,488	)	(36,250		)	$	(95,210	)	(98,634		)

Net loss per share:
Basic	$	(0.12	)	(0.10		)	$	(0.25	)	(0.27		)
Diluted	$	(0.12	)	(0.10		)	$	(0.25	)	(0.27		)

Weighted average number of shares used to compute net loss per share:
Basic	377,654			373,448			376,509			371,140
Diluted	377,654			373,448			376,509			371,140

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012

Net loss	$	(44,488	)	$	(36,250	)	$	(95,210	)	$	(98,634	)
Other comprehensive income (loss):
Reclassification adjustments for derivative (gains) losses included in net loss	(405		)	(133		)	(1,122		)	295
Other comprehensive income (loss)	(405		)	(133		)	(1,122		)	295
Comprehensive loss	$	(44,893	)	$	(36,383	)	$	(96,332	)	$	(98,339	)

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, 2012	391,424	$	3,914	$	1,712,880		$	(683,176	)	$	3,685		$	(8,397	)	$	1,028,906
Equity-based compensation	—	—		50,792			—			—			—			50,792
Derivatives, net	—	—		—			—			(1,122		)	—			(1,122		)
Restricted stock awards and units	532	6		(6		)	—			—			—			—
Restricted stock forfeitures	—	—		6			—			—			(6		)	—
Purchase of treasury stock	—	—		(445		)	—			—			(12,624		)	(13,069		)
Net loss	—	—		—			(95,210		)	—			—			(95,210		)
Balance as of September 30, 2013	391,956	$	3,920	$	1,763,227		$	(778,386	)	$	2,563		$	(21,027	)	$	970,297

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2013			2012
Operating activities
Net loss	$	(95,210	)	$	(98,634	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization	183,847			135,024
Deferred income taxes	62,757			51,867
Unsuccessful well costs	98,912			19,357
Change in fair value of derivatives	4,752			13,847
Cash settlements on derivatives	(18,658		)	(18,755		)
Equity-based compensation	50,792			58,215
Other	4,468			7,739
Changes in assets and liabilities:
(Increase) decrease in receivables	(56,725		)	89,102
Increase in inventories	(2,419		)	(7,812		)
(Increase) decrease in prepaid expenses and other	(1,126		)	4,112
Decrease in accounts payable	(30,037		)	(127,025		)
Increase in accrued liabilities	79,996			23,073
Net cash provided by operating activities	281,349			150,110

Investing activities
Oil and gas assets	(244,452		)	(272,681		)
Other property	(3,712		)	(9,030		)
Restricted cash	7,214			(23,089		)
Net cash used in investing activities	(240,950		)	(304,800		)

Financing activities
Payment on long-term debt	(100,000		)	(110,000		)
Purchase of treasury stock	(13,069		)	(8,378		)
Deferred financing costs	(2,227		)	(374		)
Net cash used in financing activities	(115,296		)	(118,752		)

Net decrease in cash and cash equivalents	(74,897		)	(273,442		)
Cash and cash equivalents at beginning of period	515,164			673,092
Cash and cash equivalents at end of period	$	440,267		$	399,650

Supplemental cash flow information
Cash paid for:
Interest	$	27,046		$	30,247
Income taxes	$	49,716		$	16,620

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 asset portfolio includes existing production and other major project developments 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 September 30, 2013, the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2013, the consolidated results of operations for the three and nine months ended September 30, 2013 and 2012, and consolidated cash flows for the nine months ended September 30, 2013 and 2012. 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 (“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, 2012, 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 September 30, 2013 and December 31, 2012, we had $19.4 million and $21.3 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 letters of credit will be satisfied and the cash collateral will be released. As of September 30, 2013 and December 31, 2012, we had $24.6 million and $29.9 million, respectively, of long-term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts.

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Inventories

Inventories consisted of $32.3 million and $33.1 million of materials and supplies and $0.8 million and $0.2 million of hydrocarbons as of September 30, 2013 and December 31, 2012, 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 directly and indirectly 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.

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.

Kosmos Energy Finance International’s following assets and liabilities are shown separately on the face of the consolidated balance sheet as of September 30, 2013 and December 31, 2012: current restricted cash; long-term derivatives assets; long-term debt; and current and long-term derivatives liabilities. At September 30, 2013, Kosmos Energy Finance International had $36.9 million in cash and cash equivalents; $0.4 million in prepaid expenses and other; $0.9 million current derivative assets; $36.2 million deferred financing costs, net; $1.5 million in accrued liabilities and $7.6 million in other long-term liabilities, which are included in the amounts shown on the face of the consolidated balance sheet. At December 31, 2012, Kosmos Energy Finance International had $118.8 million in cash and cash equivalents; $0.2 million in prepaid expenses and other; $42.2 million deferred financing costs, net; $0.5 million in accrued liabilities and $6.6 million in other long-term liabilities, which are included in the amounts shown on the face of the consolidated balance sheet.

3. Property and Equipment

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

	September 30,			December 31,
	2013			2012
	(In thousands)
Oil and gas properties:
Proved properties	$	767,288		$	682,276
Unproved properties	489,874			454,391
Support equipment and facilities	712,415			687,835
Total oil and gas properties	1,969,577			1,824,502
Less: accumulated depletion	(483,353		)	(314,190		)
Oil and gas properties, net	1,486,224			1,510,312

Other property	30,978			27,316
Less: accumulated depreciation	(15,488		)	(11,866		)
Other property, net	15,490			15,450

Property and equipment, net	$	1,501,714		$	1,525,762

We recorded depletion expense of $56.1 million and $61.9 million for the three months ended September 30, 2013 and 2012, respectively and $169.2 million and $123.3 million for the nine months ended September 30, 2013 and 2012, respectively.

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4. Suspended Well Costs

The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the nine months ended September 30, 2013. The table excludes $69.8 million in costs that were capitalized and subsequently expensed during the same period.

	Nine Months Ended September 30, 2013
	(In thousands)
Beginning balance	$	372,492
Additions to capitalized exploratory well costs pending the determination of proved reserves	30,415
Reclassification due to determination of proved reserves	—
Capitalized exploratory well costs charged to expense	(26,997		)
Ending balance	$	375,910

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

	September 30, 2013		December 31, 2012
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	11,470	$	106,635
Exploratory well costs capitalized for a period one to two years	228,842		179,933
Exploratory well costs capitalized for a period three to four years	135,598		85,924
Ending balance	$	375,910	$	372,492
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	8		7

As of September 30, 2013, 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.

Mahogany—Mahogany, a combined area covering parts of the Mahogany East discovery and the Mahogany Deep discovery, was declared commercial in September 2010, and a PoD was submitted to Ghana’s Ministry of Energy as of May 2, 2011. In a letter dated May 16, 2011, the Ministry of Energy did not approve the PoD and requested that the WCTP Block partners take certain steps regarding notifications of discovery and commerciality; and requested other information. The WCTP Block partners believe the combined submission was proper and have held meetings with Ghana National Petroleum Corporation (“GNPC”) which resolved issues relating to the PoD work program. From May 2011, the Ministry of Energy, GNPC and the WCTP Block partners continued working to resolve other differences; however, the WCTP Petroleum Agreement (“PA”) contains specific timelines for PoD approval and discussions, which expired at the end of June 2011. On June 30, 2011, we, as Operator of the WCTP Block and on behalf of the WCTP Block partners, delivered a Notice of Dispute to the Ministry of Energy and GNPC as provided under the WCTP PA, which is the initial step in triggering the formal dispute resolution process under the WCTP PA with the government of Ghana regarding approval of the Mahogany PoD. This Notice of Dispute establishes a process for negotiation and consultation for a period of 30 days (or longer if mutually agreed) among senior representatives from the Ministry of Energy, GNPC and the WCTP Block partners to resolve the matter. We and the WCTP Block partners are in discussions with the Ministry of Energy and GNPC to resolve differences on the PoD.

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 2014. 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 2014. 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.

Akasa Discovery—We have performed a drill stem test and gauge installation on the discovery well and are currently drilling the Akasa-2A appraisal well (see Note 13—Subsequent Events). Following additional appraisal and evaluation, a decision regarding commerciality of the Akasa discovery is expected to be made by the WCTP Block partners in 2014. 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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Tweneboa, Enyenra and Ntomme (“TEN”) Discoveries—In May 2013, the government of Ghana approved the PoD over the TEN discoveries. Development of TEN will include the drilling and completion of up to 24 development wells, half of the wells are designed as producers and the remainder are for water and gas injection to support ultimate field recoveries. The TEN project is expected to deliver first oil in 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 plan to acquire a high resolution seismic survey over the discovery area in 2014. 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 2014. 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. Accounts Payable and Accrued Liabilities

At September 30, 2013 and December 31, 2012, accounts payable of $98.8 million and $128.9 million, respectively, were recorded for invoices received but not paid. Accrued liabilities consisted of the following:

	September 30,		December 31,
	2013		2012
	(In thousands)
Accrued liabilities:
Accrued exploration, development and production	$	65,561	$	20,616
Accrued general and administrative expenses	14,896		5,089
Accrued taxes other than income	15,667		11,124
Accrued derivative settlements	1,465		—
Income taxes	18,277		4,192
	$	115,866	$	41,021

6. Debt

Facility

In March 2011, the Company secured a $2.0 billion commercial debt facility (the “Facility”) from a number of financial institutions and extinguished the then existing commercial debt facilities. The Facility was syndicated to certain participants of the existing facilities, as well as new participants. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of an amendment in November 2012, the total commitments for the Facility were reduced to $1.5 billion.

The Facility provides a revolving-credit and letter of credit facility. The availability period for the revolving-credit facility, as amended in April 2013, expires on December 15, 2014 and the letter of credit sublimit expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on December 15, 2014, outstanding borrowings will also be constrained by an amortization schedule. The final maturity date is March 29, 2018.

In September 2013, as part of the normal borrowing base determination process, the availability under the facility was reduced by $89.6 million to $1.2 billion. As of September 30, 2013, borrowings under the Facility totaled $900.0 million, the undrawn availability under the Facility was $309.5 million, and there were no letters of credit drawn under the facility.

Corporate Revolver

In November 2012, we secured a revolving credit facility (the “Corporate Revolver”). 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 September 30, 2013, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $300.0 million.

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Revolving Letter of Credit Facility

In July 2013, we entered into a revolving letter of credit facility agreement (“LC Facility”). The size of the LC Facility is $100.0 million, with additional commitments up to $50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. The LC Facility provides that we maintain cash collateral in an amount equal to at least 75% of all outstanding letters of credit under the LC Facility, provided that during the period of any breach of certain financial covenants, the required cash collateral amount shall increase to 100%. The fees associated with outstanding letters of credit issued will be 0.5% per annum. The LC Facility has an availability period which expires on June 1, 2016. We may voluntarily cancel any commitments available under the LC Facility at any time. As of September 30, 2013, there were four outstanding letters of credit totaling $29.0 million under the LC Facility.

At September 30, 2013, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:

	Payments Due by Year
	2013(1)		2014		2015		2016		2017		Thereafter
	(In thousands)
Facility(2)	$	—	$	—	$	346,693	$	149,428	$	292,768	$	111,111

(1) Represents payments for the period October 1, 2013 through December 31, 2013.

(2) The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of
September 30, 2013. 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.

Oil Derivative Contracts

The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of September 30, 2013.

			Weighted Average Dated Brent Price per Bbl
Term(1)	Type of Contract	MBbl	Deferred Premium Receivable/ (Payable)			Floor		Ceiling		Call
2013:
October - December	Three-way collars	375	$	(4.82	)	$	95.00	$	105.00	$	125.00
October - December	Three-way collars	253	—			87.50		115.00		135.00
October - December	Three-way collars	250	—			90.00		115.39		135.00
October - December	Three-way collars	250	—			90.08		115.00		135.00
2014:
January - December	Three-way collars	1,500	(1.22		)	85.00		115.00		140.00
January - December	Three-way collars	1,000	—			85.00		115.01		140.00
January - December	Three-way collars	1,000	—			88.09		110.00		125.00
January - December	Three-way collars	1,500	1.15			90.00		113.00		135.00

(1) In October 2013, we entered into put contracts for 1.7 MMBbl from January 2015 through December 2015 with a floor price of $85.00 per Bbl. The put contracts are indexed to Dated Brent prices and have a weighted average deferred premium payable of $3.78 per Bbl.

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Interest Rate Swaps Derivative Contracts

The following table summarizes our open interest rate swaps as of September 30, 2013, 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)
October 2013 — December 2013	$	200,617	1.99	%	6-month LIBOR
January 2014 — December 2014	133,434		1.99	%	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 September 30, 2013 and December 31, 2012 and gain/(loss) from derivatives during the three and nine months ended September 30, 2013 and 2012, respectively:

		Estimated Fair Value Asset (Liability)
		September 30,			December 31,
Type of Contract	Balance Sheet Location	2013			2012
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity(1)	Derivatives assets—current	$	917		$	1,061
Commodity(2)	Derivatives assets—long-term	1,583			—

Derivative liabilities:
Commodity(3)	Derivatives liabilities—current	(6,284		)	(17,005		)
Interest rate	Derivatives liabilities—current	(3,174		)	(3,372		)
Commodity(4)	Derivatives liabilities—long-term	(319		)	(659		)
Interest rate	Derivatives liabilities—long-term	(1,016		)	(2,567		)
Total derivatives not designated as hedging instruments		$	(8,293	)	$	(22,542	)

(1) The commodity derivative asset represents $0.9 million of our oil derivative contracts as of September 30, 2013 and $1.1 million of our provisional oil sales contract as of December 31, 2012. Includes deferred premiums receivable of $1.1 million and zero related to commodity derivative contracts as of September 30, 2013 and December 31, 2012, respectively.

(2) Includes deferred premiums receivable of $0.6 million related to commodity derivative contracts as of September 30, 2013.

(3) Includes zero and $3.4 million, as of September 30, 2013 and December 31, 2012, respectively of cash settlements made on our commodity derivative contracts which were settled in the month subsequent to period end. Also, includes deferred premiums payable of $3.0 million and $7.6 million related to commodity derivative contracts as of September 30, 2013 and December 31, 2012, respectively.

(4) Includes deferred premiums payable of $0.6 million and $2.4 million related to commodity derivative contracts as of September 30, 2013 and December 31, 2012, respectively.

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		Amount of Gain/(Loss)						Amount of Gain/(Loss)
		Three Months Ended September 30,						Nine Months Ended September 30,
Type of Contract	Location of Gain/(Loss)	2013			2012			2013			2012
		(In thousands)
Derivatives in cash flow hedging relationships:
Interest rate(1)	Interest expense	$	405		$	133		$	1,122		$	(295	)
Total derivatives in cash flow hedging relationships		$	405		$	133		$	1,122		$	(295	)

Derivatives not designated as hedging instruments:
Commodity(2)	Oil and gas revenue	$	(554	)	$	11,494		$	(5,220	)	$	15,221
Commodity	Derivatives, net	(7,585		)	(24,529		)	(386		)	(26,407		)
Interest rate	Interest expense	(318		)	(931		)	(268		)	(2,366		)
Total derivatives not designated as hedging instruments		$	(8,457	)	$	(13,966	)	$	(5,874	)	$	(13,552	)

(1) Amounts were reclassified from AOCI into earnings upon settlement.

(2) Amounts represent the mark-to-market portion of our provisional oil sales contracts.

In accordance with the mark-to-market method of accounting, the Company recognizes changes in fair values of its derivative contracts as gains or losses in earnings during the period in which they occur. The fair value of the effective portion of the interest rate derivative contracts on May 31, 2010, is reflected in AOCI and is being transferred to interest expense over the remaining term of the contracts. The Company expects to reclassify $1.5 million of gains from AOCI to interest expense within the next 12 months. See Note 8—Fair Value Measurements for additional information regarding the Company’s derivative instruments.

Offsetting of Derivative Assets and Derivative Liabilities

Our derivative instruments subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of September 30, 2013 and December 31, 2012, 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, there were no material rights of offset available, if an event of default occurred, as of September 30, 2013 and December 31, 2012.

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 September 30, 2013 and December 31, 2012, 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)
September 30, 2013
Assets:
Commodity derivatives	$	—	$	2,500		$	—	$	2,500
Liabilities:
Commodity derivatives	—		(6,603		)	—		(6,603		)
Interest rate derivatives	—		(4,190		)	—		(4,190		)
Total	$	—	$	(8,293	)	$	—	$	(8,293	)

December 31, 2012
Assets:
Commodity derivatives	$	—	$	1,061		$	—	$	1,061
Liabilities:
Commodity derivatives	—		(17,664		)	—		(17,664		)
Interest rate derivatives	—		(5,939		)	—		(5,939		)
Total	$	—	$	(22,542	)	$	—	$	(22,542	)

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 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 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 puts and compound options. 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 Long-Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $13.8 million and $19.4 million during the three months ended September 30, 2013 and 2012, respectively, and $50.8 million and $58.2 million during the nine months ended September 30, 2013 and 2012, respectively. The tax benefit resulting from equity-based compensation expense

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for the three months ended September 30, 2013 and 2012 was $4.8 million and $6.7 million, respectively, and for the nine months ended September 30, 2013 and 2012 was $17.4 million and $20.2 million, respectively. Additionally, we expensed a tax shortfall (the difference between the estimated tax deduction on the grant date and the actual tax deduction on the vest date) of $6.9 million and $7.4 million during the nine months ended September 30, 2013 and 2012, respectively. No shortfall occurred during the three months ended September 30, 2013 and 2012.

The following table reflects the outstanding restricted stock awards as of September 30, 2013:

			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, 2012	9,898		$	16.92	3,534		$	12.93
Granted	351		10.73		—		—
Forfeited	(462	)	16.51		(93	)	12.45
Vested	(3,358	)	17.26		—		—
Outstanding at September 30, 2013	6,429		16.44		3,441		12.94

The following table reflects the outstanding restricted stock units as of September 30, 2013:

			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, 2012	1,023		$	10.59	825		$	15.81
Granted	1,512		10.80		1,074		15.44
Forfeited	(133	)	10.53		(73	)	15.74
Vested	(225	)	10.51		—		—
Outstanding at September 30, 2013	2,177		10.75		1,826		15.60

As of September 30, 2013, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $144.7 million over a weighted average period of 2.20 years. At September 30, 2013, the Company had approximately 5.5 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 used to estimate the grant-date fair value 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 used to estimate the grant-date fair value 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 $34.2 million and $25.9 million for the three months ended September 30, 2013 and 2012, respectively, and was $124.6 million and $64.7 million for the nine months ended September 30, 2013 and 2012, respectively. The income tax provision consists of U.S. 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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Bermuda	$	(5,880	)	$	(2,316	)	$	(19,320	)	$	(8,735	)
United States	2,740			3,145			8,014			9,492
Foreign—other	(7,124		)	(11,156		)	40,664			(34,661		)
Income (loss) before income taxes	$	(10,264	)	$	(10,327	)	$	29,358		$	(33,904	)

Our effective tax rate for the three months ended September 30, 2013 and 2012 is (333)% and (251)%, respectively. For the nine months ended, September 30, 2013 and 2012, our effective tax rate is 424% and (191)%. The effective tax rate for the United States is approximately 42% and 43% for the three months ended September 30, 2013 and 2012, respectively, and 125% and 116% for the nine months ended September 30, 2013 and 2012, respectively. The high effective tax rates in the United States are due to the effect of tax shortfalls related to equity-based compensation. The effective tax rate for Ghana is approximately 36% and 39% for the three months ended September 30, 2013 and 2012, respectively, and 36% and 37% for the nine months ended September 30, 2013 and 2012, respectively. Our other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate, or we have experienced losses in those countries and have a full valuation allowance reserved against the corresponding net deferred tax assets.

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 2009 through 2012 and to Texas margin tax examinations for the tax years 2008 through 2012. In addition, the Company is open to income tax examinations for years 2004 through 2012 in Ghana.

As of September 30, 2013, 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 has not accrued any material amounts to date.

11. Net Income (Loss) Per Share

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(In thousands, except per share data)
Numerator:
Net income (loss)	$	(44,488	)	$	(36,250	)	$	(95,210	)	$	(98,634	)
Less: Basic income allocable to participating securities(1)	—			—			—			—
Basic net income (loss) allocable to common shareholders	(44,488		)	(36,250		)	(95,210		)	(98,634		)
Diluted adjustments to income allocable to participating securities(1)	—			—			—			—
Diluted net income (loss) allocable to common shareholders	$	(44,488	)	$	(36,250	)	$	(95,210	)	$	(98,634	)
Denominator:
Weighted average number of shares used to compute net income (loss) per share:
Basic	377,654			373,448			376,509			371,140
Restricted stock awards and units(1)(2)	—			—			—			—
Diluted	377,654			373,448			376,509			371,140
Net income (loss) per share:
Basic	$	(0.12	)	$	(0.10	)	$	(0.25	)	$	(0.27	)
Diluted	$	(0.12	)	$	(0.10	)	$	(0.25	)	$	(0.27	)

(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

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undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income (loss) per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses and, therefore, are excluded from the basic net income (loss) per common share calculation in periods we are in a net loss position.

(2) We excluded outstanding restricted stock awards and units of 13.9 million and 17.1 million for the three months ended September 30, 2013 and 2012, respectively, and 13.9 million and 17.1 million for the nine months ended September 30, 2013 and 2012, 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 consolidated financial statements; 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 scheduled for completion in June 2014 and 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.

The estimated future minimum commitments under this contract as of September 30, 2013, are:

	Payments Due By Year(1)
	Total		2013(2)		2014		2015		2016		2017		Thereafter
	(In thousands)

Atwood Achiever drilling rig contract (3)	$	651,525	$	—	$	90,440	$	217,175	$	217,770	$	126,140	$	—

(1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator, excludes commitments for development activities under our petroleum contracts where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts and farm-in agreements.

(2) Represents payments for the period from October 1, 2013 through December 31, 2013.

(3) Commitments calculated using a day rate of $595,000 and an estimated rig delivery date of August 1, 2014.

13. Subsequent Events

In October 2013, we entered into three farm-out agreements with BP plc (“BP”) covering three blocks in the Agadir Basin, offshore Morocco. Under the terms of the agreements, BP will acquire a non-operating interest in each of the Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks. BP will fund Kosmos’ share of the cost of one exploration well in each of the three blocks, subject to a maximum spend of $120.0 million per well, and pay its proportionate share of any well costs above the maximum spend. In the event a second exploration well is drilled in any block, BP will pay 150% of its share of costs subject to a maximum spend of $120.0 million per well. BP shall also pay $36.3 million for their share of past costs. Completion of the transactions is subject to customary closing conditions, including Moroccan Government approvals. After completing the transaction, our participating interests will be 30.0%, 29.925% and 30.0% in the Essaouira, Foum Assaka and Tarhazoute Offshore blocks, respectively, and we will remain the operator.

In October 2013, we entered into a farm-out agreement with Capricorn Exploration & Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”), covering the Cap Boujdour Contract Area, offshore Western Sahara. Under the terms of the agreement, Cairn will acquire a 20% non-operated interest in the exploration permits comprising the Cap Boujdour Contract Area. Cairn will pay 150% of its share of costs of a 3D seismic survey and one exploration well capped at $125.0 million. In the event the exploration well is successful, Cairn will pay 200% of its share of costs on two appraisal wells capped at $100.0 million per well. Additionally, Cairn will contribute $12.3 million towards our future costs. Completion of the transaction is subject to customary closing conditions, including Moroccan Government approvals. After completing the transaction, our participating interest in the Cap Boujdour Contract Area will be 55.0% and we will remain the operator.

Drilling of the Akasa-2A appraisal well on the WCTP Block was completed in October 2013. The Akasa-2A appraisal well did not encounter oil or gas reserves sufficient to be utilized as a producing well. Accounting rules require that the costs associated with the Akasa-2A appraisal well be impaired, which are $11.5 million and included in exploration expenses in the accompanying consolidated statement of operations. We estimate we will incur an additional $8.9 million of related well costs, which will be expensed as incurred.

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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, 2012, 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

Debt

Our $2.0 billion commercial debt facility (“Facility”) provides a revolving-credit and letter of credit facility. The availability period for the revolving-credit facility, as amended in April 2013, expires on December 15, 2014 and the letter of credit sublimit expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on December 15, 2014, outstanding borrowings will also be constrained by an amortization schedule. The final maturity date is March 29, 2018.

In September 2013, as part of the normal borrowing base determination process, the availability under the facility was reduced $89.6 million to $1.2 billion. As of September 30, 2013, borrowings under the Facility totaled $900.0 million, the undrawn availability under the Facility was $309.5 million and there were no letters of credit drawn under the facility.

In July 2013, we entered into a revolving letter of credit facility agreement (“LC Facility”). The size of the LC Facility is $100.0 million, with additional commitments up to $50.0 million being available if the existing lender increases its commitments or if commitments from new financial institutions are added. The LC Facility provides that we shall maintain cash collateral in an amount equal to at least 75% of all outstanding letters of credit under the LC Facility, provided that during the period of any breach of certain financial covenants, the required cash collateral amount shall increase to 100%. The fees associated with outstanding letters of credit issued will be 0.5% per annum. The LC Facility has an availability period which expires on June 1, 2016. We may voluntarily cancel any commitments available under the LC Facility at any time. As of September 30, 2013, there were four outstanding letters of credit totaling $29.0 million under the LC Facility.

Ghana

We previously received an approval for the Phase 1A PoD of the Jubilee Field, and production from Phase 1A commenced in late 2012. The Phase 1A program includes the drilling of up to eight additional wells consisting of up to five production wells and three water injection wells. Four wells, three producers and one injector, are online. Program execution is expected to be completed in the latter part of 2014.

Drilling of the Akasa-2A appraisal well on the WCTP Block was completed in October 2013. We believe that the well successfully identified the down dip water contact associated with the Akasa-1 discovery as intended. Should the Akasa discovery progress to a development, the Akasa-2A appraisal well is expected to be utilized in the development as a water injector well. However, since the Akasa-2A appraisal well did not encounter oil or gas reserves sufficient to be utilized as a producing well, accounting rules require that the costs associated with the Akasa-2A appraisal well be impaired. As such, $11.5 million is included in exploration expenses in the accompanying consolidated statement of operations for the three and nine months ended September 30, 2013. We estimate we will incur an additional $8.9 million of related well costs, which will be expensed as incurred.

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Cameroon

In July 2013, we informed the government of Cameroon that we do not intend to enter into the next phase of our petroleum contracts in Cameroon and expect to relinquish our rights to the blocks.

Ireland

In July 2013, Ireland granted us Frontier Exploration Licenses 1-13, 2-13, and 3-13 pursuant to Licensing Options 11/5, 11/7 and 11/8. We commenced a 3D seismic program of approximately 5,000 square kilometers over these blocks in July 2013, which was completed in October 2013.

Mauritania

In June 2013, we commenced a 3D seismic program of approximately 10,300 square kilometers over portions of Blocks C8 and C12 which is expected to be completed in the fourth quarter of 2013.

Morocco

In January 2013, we closed on an agreement to acquire an additional 37.5% participating interest in the Essaouira Offshore Block from Canamens Energy Morocco SARL, one of our block partners. Certain governmental approvals and processes are still required to be completed before this acquisition is effective.

In August 2013, final government approvals and processes were completed for the acquisition of the additional 18.75% participating interest in the Foum Assaka Block in the Agadir Basin offshore Morocco from Pathfinder, a wholly owned subsidiary of Fastnet, one of our block partners.

In October 2013, Kosmos executed a petroleum agreement with the Office National des Hydrocarbures et des Mines (“ONHYM”), the national oil company of the Kingdom of Morocco, covering the Tarhazoute Offshore block, to which the Company previously held certain exploration rights under a 2011 reconnaissance contract. Under the terms of the petroleum contract, the Company is the operator of the Tarhazoute Offshore block. ONHYM holds a 25% carried interest in the block through the exploration period. The initial exploration period will last for two years and six months and will commence from the date specified in the exploration permits, which have yet to be finalized with the Government of Morocco and ONHYM. The exploration period may be extended for additional exploration extension periods of two years and six months and three years respectively. In the event of commercial success, the Company has the right to develop and produce oil or gas for a period of 25 years from the grant of an exploitation concession from the Government of Morocco, which may be extended for an additional period of 10 years under certain circumstances. The petroleum contract is subject to customary government approvals.

We are filing our new petroleum contract for the Tarhazoute Offshore block as well as our existing petroleum contracts to which we are a party and which have not otherwise been previously filed as exhibits to this Quarterly Report on Form 10-Q.

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Suriname

In August 2013, we completed a 2D seismic program of approximately 1,400 line kilometers over a portion of Block 42, outside of the existing 3D seismic survey.

Results of Operations

All of our production-related results, as presented in the table below, represent operations from the Jubilee Field in Ghana. Certain operating results and statistics for the three and nine months ended September 30, 2013 and 2012, are included in the following table:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(In thousands, except per barrel data)
Sales volumes:
MBbl	1,912		1,985		5,847		3,913

Revenues:
Oil sales	$	215,169	$	222,375	$	636,648	$	450,360
Average sales price per Bbl	112.52		112.01		108.88		115.08

Costs:
Oil production, excluding workovers	$	13,026	$	16,936	$	39,145	$	33,595
Oil production, workovers	19,550		27,937		40,506		38,196
Total oil production costs	$	32,576	$	44,873	$	79,651	$	71,791

Depletion	$	56,094	$	61,913	$	169,163	$	123,256

Average cost per Bbl:
Oil production, excluding workovers	$	6.82	$	8.53	$	6.69	$	8.58
Oil production, workovers	10.22		14.07		6.93		9.76
Total oil production costs	17.04		22.60		13.62		18.34

Depletion	29.33		31.18		28.93		31.50
Oil production cost and depletion costs	$	46.37	$	53.78	$	42.55	$	49.84

The following table shows the number of wells in the process of being drilled or are in active completion stages, and the number of wells suspended or waiting on completion as of September 30, 2013:

					Wells Suspended or
	Actively Drilling or Completing				Waiting on Completion
	Exploration		Development		Exploration		Development
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Ghana
West Cape Three Points	1	0.31	—	—	8	2.47	—	—
Deepwater Tano	—	—	—	—	1	0.18	—	—
TEN	—	—	—	—	12	2.16	—	—
Jubilee Unit	—	—	1	0.24	—	—	1	0.24
Total	1	0.31	1	0.24	21	4.81	1	0.24

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

Three months ended September 30, 2013 compared to three months ended September 30, 2012

	Three Months Ended September 30,						Increase
	2013			2012			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	215,169		$	222,375		$	(7,206	)
Interest income	77			137			(60		)
Other income	133			725			(592		)
Total revenues and other income	215,379			223,237			(7,858		)
Costs and expenses:
Oil and gas production	32,576			44,873			(12,297		)
Exploration expenses	78,038			38,127			39,911
General and administrative	35,646			39,898			(4,252		)
Depletion and depreciation	58,367			63,794			(5,427		)
Amortization—deferred financing costs	2,786			2,194			592
Interest expense	8,781			20,213			(11,432		)
Derivatives, net	7,585			24,529			(16,944		)
Other expenses, net	1,864			(64		)	1,928
Total costs and expenses	225,643			233,564			(7,921		)
Loss before income taxes	(10,264		)	(10,327		)	63
Income tax expense	34,224			25,923			8,301
Net loss	$	(44,488	)	$	(36,250	)	$	(8,238	)

Oil and gas revenue. Oil and gas revenue decreased by $7.2 million during the three months ended September 30, 2013 as compared to the three months ended September 30, 2012. The decrease is primarily due to the slight decrease in sales volumes during the three months ended September 30, 2013 as compared to three months ended September 30, 2012.

Oil and gas production. Oil and gas production costs decreased by $12.3 million during the three months ended September 30, 2013 as compared to the three months ended September 30, 2012. The decrease is primarily due to a reduction in well workover costs and non-routine operating costs in the three months ended September 30, 2013 as compared to the three months ended September 30, 2012.

Exploration expenses. Exploration expenses increased by $39.9 million during the three months ended September 30, 2013, as compared to the three months ended September 30, 2012. During the three months ended September 30, 2013, we incurred $59.9 million for seismic costs primarily for Mauritania and Ireland and $13.2 million for unsuccessful well for the Ghana Akasa-2 appraisal well and the Cameroon Sipo-1 exploration well. During the three months ended September 30, 2012, we incurred $32.8 million for seismic costs primarily for Suriname.

General and administrative. General and administrative costs decreased by $4.3 million during the three months ended September 30, 2013, as compared to the three months ended September 30, 2012. Total non-cash general and administrative costs were $13.8 million and $19.4 million for the three months ended September 30, 2013 and 2012, respectively, which was primarily related to equity-based compensation.

Depletion and depreciation. Depletion and depreciation decreased $5.4 million during the three months ended September 30, 2013, as compared with the three months ended September 30, 2012 primarily due to the slight decrease in barrels lifted.

Interest expense. Interest expense decreased $11.4 million during the three months ended September 30, 2013, as compared with the three months ended September 30, 2012, primarily due to an accrual for transaction taxes during the three months ended September 30, 2012 and decreases in our outstanding debt balance and in the mark-to-market loss on our interest rate swaps during the three months ended September 30, 2013.

Derivatives, net. During the three months ended September 30, 2013 and 2012, we recorded losses of $7.6 million and $24.5 million, respectively, on our outstanding hedge positions. The losses recorded were a result of an increase in oil prices during the respective periods.

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Income tax expense. The Company’s effective tax rates for the three months ended September 30, 2013 and 2012 were (333)% and (251)%, respectively. The large effective tax rates for the periods presented are due to losses 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 $8.3 million during the three months ended September 30, 2013, as compared with September 30, 2012, primarily due to an increase in pre-tax income from our Ghanaian subsidiary.

Nine months ended September 30, 2013 compared to nine months ended September 30, 2012

	Nine Months Ended September 30,						Increase
	2013			2012			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	636,648		$	450,360		$	186,288
Interest income	191			1,165			(974		)
Other income	708			930			(222		)
Total revenues and other income	637,547			452,455			185,092
Costs and expenses:
Oil and gas production	79,651			71,791			7,860
Exploration expenses	194,384			96,134			98,250
General and administrative	118,787			112,558			6,229
Depletion and depreciation	175,578			128,442			47,136
Amortization—deferred financing costs	8,269			6,582			1,687
Interest expense	27,789			43,717			(15,928		)
Derivatives, net	386			26,407			(26,021		)
Other expenses, net	3,345			728			2,617
Total costs and expenses	608,189			486,359			121,830
Income (loss) before income taxes	29,358			(33,904		)	63,262
Income tax expense	124,568			64,730			59,838
Net loss	$	(95,210	)	$	(98,634	)	$	3,424

Oil and gas revenue. Oil and gas revenue increased $186.3 million during the nine months ended September 30, 2013, as compared with the nine months ended September 30, 2012. The increase is primarily due to having six liftings of oil during the nine months ended September 30, 2013 as compared to having four liftings of oil during the nine months ended September 30, 2012. This increase is partially offset by a lower realized price per barrel during the nine months ended September 30, 2013.

Oil and gas production. Oil and gas production costs increased $7.9 million during the nine months ended September 30, 2013, as compared with the nine months ended September 30, 2012. The increase is primarily due to an increase in routine operating expenses related to the increase in production volumes and liftings during the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012. In addition, higher workover and rig equipment costs were incurred during 2013 as compared to 2012.

Exploration expenses. Exploration expenses increased $98.3 million during the nine months ended September 30, 2013, as compared with the nine months ended September 30, 2012. During the nine months ended September 30, 2013, the Company incurred $97.2 million of unsuccessful well and other related costs primarily related to the Cameroon Sipo-1 exploration well, the Ghana Sapele-1 exploration well, and the Ghana Akasa-2 appraisal well and $84.9 million for seismic costs primarily for Mauritania, Ireland, Morocco and new ventures. During the nine months ended September 30, 2012, we incurred $66.2 million for seismic costs for Suriname, Morocco, Ghana and Cameroon and $19.4 million of unsuccessful well costs, primarily related to the Ghana Teak-4A appraisal well.

General and administrative. General and administrative costs increased $6.2 million during the nine months ended September 30, 2013, as compared with the nine months ended September 30, 2012, due to an increase in headcount. Total non-cash general and administrative costs were $50.8 million and $58.2 million for the nine months ended September 30, 2013 and 2012, respectively, which was primarily related to equity-based compensation.

Depletion and depreciation. Depletion and depreciation increased $47.1 million during the nine months ended September 30, 2013, as compared with the nine months ended September 30, 2012. The increase is primarily due to depletion recognized related to the sale of six liftings of oil during the nine months ended September 30, 2013 as compared to four liftings of oil during the nine months ended September 30, 2012.

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Interest expense. Interest expense decreased $15.9 million during the nine months ended September 30, 2013, as compared with the nine months ended September 30, 2012, primarily due to reduced transaction taxes during the nine months ended September 30, 2012, decreases in our outstanding debt balance and in the mark-to-market loss on our interest rate swaps during the nine months ended September 30, 2013.

Derivatives, net. During the nine months ended September 30, 2013 and 2012, we recorded a loss of $0.4 million and $26.4 million, respectively, on our outstanding hedge positions. The losses recorded were a result of an increase in oil prices during the respective periods.

Income tax expense. The Company’s effective tax rates for the nine months ended September 30, 2013 and 2012 were 424% and (191%), respectively. The large effective tax rates for the periods presented are due to losses incurred in jurisdictions in which we are not subject to taxes and, therefore, do not generate any income tax benefits as well as 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 $59.8 million during the nine months ended September 30, 2013, as compared with September 30, 2012, 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 to meet our ongoing liquidity requirements.

Significant Sources of Capital

Facility

Corporate Revolver

In November 2012, we secured the 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 by additional commitments from existing and new financial institutions. As of September 30, 2013, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $300.0 million.

Revolving Letter of Credit Facility

In July 2013, we entered into a revolving LC Facility. The size of the LC Facility is $100.0 million, with additional commitments up to $50.0 million being available if the existing lender increases its commitments or if commitments from new financial institutions are added. The LC Facility provides that we shall maintain cash collateral in an amount equal to at least 75% of all outstanding letters of credit under the LC Facility, provided that during the period of any breach of certain financial covenants, the required cash collateral amount shall increase to 100%. The fees associated with outstanding letters of credit issued will be 0.5% per annum. The LC Facility has an availability period which expires on June 1, 2016. We may voluntarily cancel any commitments available under the LC Facility at any time. As of September 30, 2013, there were four outstanding letters of credit totaling $29.0 million under the LC Facility.

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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:

· complete our 2013 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 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.

2013 Capital Program

Our estimate for the 2013 capital program remains at $560.0 million. The 2013 capital expenditure budget consists of:

· approximately 50% for developmental related expenditures offshore Ghana; and

· approximately 50% 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 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 September 30, 2013:

	September 30, 2013
	(In thousands)
Cash and cash equivalents	$	440,267
Drawings under the Facility	900,000
Net debt	459,733

Availability under the Facility	$	309,504
Availability under the Corporate Revolver	300,000
Available borrowings plus cash and cash equivalents	1,049,771

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Cash Flows

	Nine Months Ended September 30,
	2013			2012
	(In thousands)
Net cash provided by (used in):
Operating activities	$	281,349		$	150,110
Investing activities	(240,950		)	(304,800		)
Financing activities	(115,296		)	(118,752		)

Operating activities. Net cash provided by operating activities for the nine months ended September 30, 2013 was $281.3 million compared with net cash provided by operating activities for the nine months ended September 30, 2012 of $150.1 million. The increase in cash provided by operating activities in the nine months ended September 30, 2013 when compared to the same period in 2012 was primarily due to an increase in oil and gas revenues offset by a negative change in working capital items.

Investing activities. Net cash used in investing activities for the nine months ended September 30, 2013 was $241.0 million compared with net cash used in investing activities for the nine months ended September 30, 2012 of $304.8 million. The decrease in cash used in investing activities in the nine months ended September 30, 2013 when compared to the same period in 2012 was primarily attributable to a decrease in expenditures for oil and gas assets and the release of restricted cash during 2013.

Financing activities. Net cash used in financing activities for the nine months ended September 30, 2013 was $115.3 million compared with net cash used in financing activities for the nine months ended September 30, 2012 of $118.8 million. The cash used in financing activities in the nine months ended September 30, 2013 was consistent with the prior period.

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of September 30, 2013:

	Payments Due By Year(3)
	Total		2013(4)		2014		2015		2016		2017		Thereafter
	(In thousands)
Facility(1)	$	900,000	$	—	$	—	$	346,693	$	149,428	$	292,768	$	111,111
Interest payments on long-term debt(2)	147,468		11,237		47,858		39,494		25,167		21,957		1,755
Operating leases	22,205		1,562		4,306		3,502		3,158		3,223		6,454
Atwood Achiever drilling rig contract(5)	651,525		—		90,440		217,175		217,770		126,140		—

(1) The estimated repayments of debt are based on the level of borrowings and the available borrowing base as of September 30, 2013. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of September 30, 2013, 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.

(3) 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 and farm-in agreements.

(4) Represents payments for the period from October 1, 2013 through December 31, 2013.

(5) Commitments calculated using a day rate of $595,000 and an estimated rig delivery date of August 1, 2014.

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.

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	October 1 Through December 31,			Years Ending December 31,															Liability Fair Value at September 30,
	2013(1)			2014			2015			2016			2017			Thereafter			2013
	(In thousands, except percentages)
Variable rate debt:
Facility(2)	$	—		$	—		$	346,693		$	149,428		$	292,768		$	111,111		$	(900,000	)
Weighted average interest rate(3)	3.43		%	3.94		%	4.56		%	5.70		%	7.05		%	7.68		%
Interest rate swaps:
Notional debt amount(4)	$	—		$	47,033		$	16,875		$	6,250		$	—		$	—		$	(1,746	)
Fixed rate payable				2.22		%	2.22		%	2.22		%
Variable rate receivable(5)				0.47		%	0.83		%	1.46		%
Notional debt amount(4)	$	—		$	47,033		$	16,875		$	6,250		$	—		$	—		$	(1,846	)
Fixed rate payable				2.31		%	2.31		%	2.31		%
Variable rate receivable(5)				0.47		%	0.83		%	1.46		%
Notional debt amount(4)	$	—		$	1,868		$	—		$	—		$	—		$	—		$	(74	)
Fixed rate payable				0.98		%
Variable rate receivable(5)				0.53		%
Notional debt amount(4)	$	—		$	38,434		$	23,137		$	—		$	—		$	—		$	(524	)
Fixed rate payable				1.34		%	1.34		%
Variable rate receivable(5)				0.47		%	0.68		%

(1) The interest rate swaps’ variable rate receivable for the period October 1 through December 31, 2013 locked on June 26, 2013, therefore the notional amounts are not subject to changes in interest rates.

(2) 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 September 30, 2013. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of September 30, 2013, there were no borrowings under the Corporate Revolver.

(3) 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.

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

(5) 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 September 30, 2013, 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, derivatives 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, 2012.

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

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

· our ability to find, acquire or gain access to other discoveries and prospects and to successfully develop 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, Cameroon, Ireland, Mauritania, Morocco 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 risks and other operational and environmental hazards;

· current and future government regulation of the oil and gas industry;

· 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;

· the availability and cost of financing and refinancing our indebtedness;

· the amount of collateral, if any, 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.

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

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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 and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8. Financial Statements and Supplementary Data—Note 2—Accounting Policies, Note 10—Derivative Financial Information and Note 11—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 nine months ended September 30, 2013:

	Derivative Contracts Assets (Liabilities)
	Commodities			Interest Rates			Total
	(In thousands)
Fair value of contracts outstanding as of December 31, 2012	$	(16,603	)	$	(5,939	)	$	(22,542	)
Changes in contract fair value	(5,606		)	(268		)	(5,874		)
Contract maturities	18,106			2,017			20,123
Fair value of contracts outstanding as of September 30, 2013	$	(4,103	)	$	(4,190	)	$	(8,293	)

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.

Commodity Price Sensitivity

The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of September 30, 2013:

			Weighted Average Dated Brent Price per Bbl
Term (1)	Type of Contract	MBbl	Deferred Premium Receivable/ (Payable)			Floor		Ceiling		Call		Asset (Liability) Fair Value at September 30, 2013(2)
2013:
October—December	Three-way collars	375	$	(4.82	)	$	95.00	$	105.00	$	125.00	$	(3,245	)
October—December	Three-way collars	253	—			87.50		115.00		135.00		(115		)
October—December	Three-way collars	250	—			90.00		115.39		135.00		(91		)
October—December	Three-way collars	250	—			90.08		115.00		135.00		(102		)
2014:
January—December	Three-way collars	1,500	(1.22		)	85.00		115.00		140.00		(1,999		)
January—December	Three-way collars	1,000	—			85.00		115.01		140.00		(131		)
January—December	Three-way collars	1,000	—			88.09		110.00		125.00		(535		)
January—December	Three-way collars	1,500	1.15			90.00		113.00		135.00		2,115

(2) Fair values are based on the average forward Dated Brent oil prices on September 30, 2013 which by year are: 2013—$107.57, 2014—$102.77 and 2015 — $97.38. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on October 28, 2013 market quotes by year are: 2013—$109.05, 2014—$105.31 and 2015 — $99.30.

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.

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Interest Rate Sensitivity

At September 30, 2013, we had indebtedness outstanding under the Facility of $900.0 million, of which $699.4 million bore interest at floating rates. The interest rate on this indebtedness as of September 30, 2013 was approximately 3.4%. If LIBOR changed by 10% at this level of floating rate debt, our cash paid for interest would increase or decrease by $0.1 million per year on the Facility. We pay commitment fees on the $309.5 million of undrawn availability and $290.5 million of unavailable commitments 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 September 30, 2013, the fair market value of our interest rate swaps was a net liability of approximately $4.2 million. If LIBOR increased by 10%, we estimate the liability would decrease to approximately $4.1 million, and if LIBOR decreased by 10%, we estimate the liability would increase to approximately $4.3 million.

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 September 30, 2013, 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

There have been no material changes from the risk factors disclosed in “Item 1A. Risk Factors” section of our annual report on Form 10-K.

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.

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 September 30, 2013. 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 September 30, 2013, as the case may be, additional reportable transactions may be disclosed by such companies.

As of April 1, 2013, funds affiliated with The Blackstone Group (“Blackstone”) held approximately 29% of our outstanding common shares. We are also a party to a shareholders agreement with Blackstone pursuant to which, among other things, Blackstone currently has the right to designate three members of our board of directors. Accordingly, Blackstone may be deemed an “affiliate” of us, both currently and during the fiscal quarter ended September 30, 2013.

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 are controlled by Blackstone, we may be considered an “affiliate” of Travelport for the purposes of Section 13(r) of the Exchange Act.

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Travelport Disclosure:

Quarter ended September 30, 2013

“As part of our global business in the travel industry, we provide certain passenger travel related GDS and Airline IT Solutions services to Iran Air. We also provide certain Airline IT Solutions services to Iran Air Tours. All of these services are either exempt from applicable sanctions prohibitions pursuant to a statutory exemption in the International Emergency Economic Powers Act permitting transactions ordinarily incident to travel or, to the extent not otherwise exempt, specifically licensed by the U.S. Office of Foreign Assets Control (“OFAC”). 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.

Quarter ended June 30, 2013

“As part of our global business in the travel industry, we provide certain passenger travel related GDS and airline IT Solutions services to Iran Air. We also provide certain airline IT Solutions services to Iran Air Tours. All of these services are either exempt from applicable sanctions prohibitions pursuant to a statutory exemption in the International Emergency Economic Powers Act permitting transactions ordinarily incident to travel or, to the extent not otherwise exempt, specifically licensed by the U.S. Office of Foreign Assets Control (“OFAC”). 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.

Prior to and during the reporting period, we also provided airline IT Solutions services to Syrian Arab Airlines. These services were generally understood to be permissible under the same statutory travel exemption. The services were terminated following the May 2013 action by OFAC to designate this airline as a Specially Designated Global Terrorist pursuant to the Global Terrorism Sanctions Regulations.

The gross revenue and net profit attributable to these activities in the quarter ended June 30, 2013 were approximately $248,000 and $176,000, respectively.”

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.

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	November 5, 2013	/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*		Multi-Currency Revolving Letter of Credit Facility Agreement, dated as of July 3, 2013, among Kosmos Energy Credit International, as Original Borrower, Kosmos Energy Ltd., as Original Guarantor, and Societe Generale, London Branch, as Original Lender, Facility Agent, Security Agent and Account Bank.

10.2*		Charge on Cash Deposits and Account Bank Agreement, dated as of July 3, 2013, among Kosmos Energy Credit International and Societe Generale, London Branch, as Security Agent.

10.3*		Letter of Resignation from John R. Kemp III, dated as of July 18, 2013.

10.4*		Amendment No. 2, effective as of January 1, 2013, to Consulting Agreement between Kosmos Energy Ltd. and John R. Kemp III

10.5*		Amendment No. 3, effective as of October 1, 2013, to Consulting Agreement between Kosmos Energy Ltd. and John R. Kemp III

10.6*		Offer Letter, dated November 22, 2011, between Kosmos Energy, LLC and Darrell McKenna

10.7*		Offer Letter, dated March 2, 2012, between Kosmos Energy, LLC and Tyner Gaston

10.8*		Offer Letter, dated May 16, 2012, between Kosmos Energy, LLC and Paul Nobel

10.9*		Form of RSU Award Agreement (Directors — Service-Vesting)

10.10*		Form of RSU Award Agreement (Employees —Service-Vesting)

10.11*		Form of RSU Award Agreement (Employees —Performance-Vesting)

10.12*		Petroleum Agreement Regarding the Exploration for Exploitation of Hydrocarbons among Office National Des Hydrocarbures Et Des Mines acting on behalf of the Kingdom of Morocco, Kosmos Energy Deepwater Morocco and Canamens Energy Morocco SARL in the area of interest named “Essaouira Offshore” dated September 9, 2011

10.13*		Deed of Assignment in Petroleum Agreement for the Exploration for and Exploitation of Hydrocarbons in the zone of interest named “Essaouira Offshore” between Canamens Energy Morocco SARL and Kosmos Energy Deepwater Morocco dated December 19, 2012

10.14*		Petroleum Agreement Regarding the Exploration for Exploitation of Hydrocarbons among Office National Des Hydrocarbures Et Des Mines acting on behalf of the Kingdom of Morocco, Kosmos Energy Deepwater Morocco and Pathfinder Hydrocarbon Ventures Limited in the area of interest named “Foum Assaka Offshore” dated May 4, 2011

10.15*		Deed of Assignment in Petroleum Agreement for the Exploration for and Exploitation of Hydrocarbons in the zone of interest named “Foum Assaka Offshore” between Pathfinder Hydrocarbon Ventures Limited and Kosmos Energy Deepwater Morocco dated June 11, 2012

10.16*		Petroleum Agreement Regarding the Exploration for Exploitation of Hydrocarbons among Office National Des Hydrocarbures Et Des Mines acting on behalf of the Kingdom of Morocco and Kosmos Energy Deepwater Morocco in the area of interest named “Tarhazoute Offshore” dated October 10, 2013

10.17*		Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy Mauritania (Bloc C8) dated April 5, 2012

10.18*		Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy Mauritania (Bloc C12) dated April 5, 2012

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10.19*		Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy Mauritania (Bloc C13) dated April 5, 2012

10.20*		Production Sharing Contract for Petroleum Exploration, Development and Production relating to Block 42 Offshore Suriname between Staatsolie Maatshappij Suriname N.V. and Kosmos Energy Suriname dated December 13, 2011

10.21*		Production Sharing Contract for Petroleum Exploration, Development and Production relating to Block 45 Offshore Suriname between Staatsolie Maatshappij Suriname N.V. and Kosmos Energy Suriname dated December 13, 2011

10.22*		Deed of Assignment and Transfer relating to Blocks 42 and 45 Offshore Suriname between Kosmos Energy Suriname and Chevron Suriname Exploration Limited dated May 31, 2012

10.23*		Irish Continental Shelf — Petroleum Exploration License No. 1/13 (Frontier) between the Minister for Communications, Energy and Natural Resources, Ireland, and Kosmos Energy Ireland and Antrim Exploration (Ireland) Ltd dated August 28, 2013

10.24*		Irish Continental Shelf — Petroleum Exploration License No. 2/13 (Frontier) between the Minister for Communications, Energy and Natural Resources, Ireland, and Kosmos Energy Ireland and Europa Oil and Gas (Holdings) Plc. dated August 23, 2013

10.25*		Irish Continental Shelf — Petroleum Exploration License No. 3/13 (Frontier) between the Minister for Communications, Energy and Natural Resources, Ireland, and Kosmos Energy Ireland and Europa Oil and Gas (Holdings) Plc. dated August 23, 2013

10.26*		Licensing Terms for Offshore Oil and Gas Exploration, Development and Production 2007, relating to the Petroleum Exploration Licenses No. 1/13, No. 2/13 and No. 3/13 offshore Ireland

10.27*		Petroleum Agreement Regarding the Exploration for Exploitation of Hydrocarbons between Office National Des Hydrocarbures Et Des Mines acting on behalf of the State and Kosmos Energy Offshore Morocco HC in the area of interest named “Cap Boujdour Offshore” dated July 7, 2011

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.