Edgar Filing: Kosmos Energy Ltd.

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2011

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 jurisdictions 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: (214) 445-9600

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 o No x

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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. (Check one):

Large accelerated filer o		Accelerated filer o

Non-accelerated filer x		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 June 1, 2011
Common Shares, $0.01 par value		385,205,198

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KOSMOS ENERGY LTD.

INDEX

	Page
PART I. FINANCIAL INFORMATION

Explanatory Note	1
Glossary and Select Abbreviations	2

Item 1. Financial Statements — Kosmos Energy Holdings
Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010	4
Consolidated Statements of Operations for the three months ended March 31, 2011 and 2010	5
Consolidated Statements of Unit Holdings Equity for the three months ended March 31, 2011	6
Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010	7
Consolidated Statements of Comprehensive Loss for the three months ended March 31, 2011 and 2010	8
Notes to Consolidated Financial Statements	9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3. Quantitative and Qualitative Disclosures about Market Risk	38
Item 4. Controls and Procedures	40

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	41
Item 1A. Risk Factors	41
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 3. Defaults Upon Senior Securities	41
Item 4. (Removed and Reserved)	41
Item 5. Other Information	42
Item 6. Exhibits	42
Signatures	43
Index to Exhibits	44

EXPLANATORY NOTE

Pursuant to the terms of a corporate reorganization that was completed immediately prior to the closing of Kosmos Energy Ltd.’s initial public offering on May 16, 2011, all of the interests in Kosmos Energy Holdings were exchanged for newly issued common shares of Kosmos Energy Ltd. and as a result Kosmos Energy Holdings became wholly owned by Kosmos Energy Ltd. However, as of the date of the unaudited financial statements included in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, our business operated as Kosmos Energy Holdings and its consolidated subsidiaries. Accordingly, the unaudited financial statements included in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 are those of Kosmos Energy Holdings and its consolidated subsidiaries. Other than as indicated under the section “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” of our final prospectus dated May 10, 2011 (the “final prospectus”) and as filed with the Securities and Exchange Commission pursuant to Rule 424(b) of the Securities Act of 1933, as amended, which relate to the Registration Statement on Form S-1 (File No. 333-171700), as amended, all accounting policies in effect for Kosmos Energy Holdings have remained in effect upon completion of the corporate reorganization and are utilized by Kosmos Energy Ltd.

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KOSMOS ENERGY LTD.

GLOSSARY AND SELECT ABBREVIATIONS

The following are abbreviations and definitions of certain terms 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.

“ASC”	Accounting Standards Codification.
“ASU”	Accounting Standards Update.
“Barrel” or “bbl”	A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.
“boe”	Barrels of oil equivalent. Volumes of natural gas are 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.
“Dated Brent”	Refers to a cargo of blended North Sea Brent crude oil that has been assigned a date for loading onto a tanker. Physically, Brent is light but still heavier than West Texas Intermediate crude.
“Development”	The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.
“Development well”	A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
“Drilling and completion costs”	All costs, excluding operating costs, of drilling, completing, testing, equipping and bringing a well into production or plugging and abandoning it, including all costs associated with labor and other construction and installation, location and surface damages, cementing, drilling mud and chemicals, drillstem tests and core analysis, engineering and well site geological expenses, electric logs, plugging back, deepening, rework operations, repairing or performing remedial work of any type, plugging and abandoning.
“Dry hole”	A well that has not encountered a hydrocarbon bearing reservoir.
“E&P”	Exploration and production.
“Exploration well” or “Exploratory well”	A well drilled either (a) in search of a new and as yet undiscovered pool of oil or natural gas or (b) with the hope of significantly extending the limits of a pool already developed.
“FASB”	Financial Accounting Standards Board.
“Field”	A geographical area under which an oil or natural gas reservoir exists in commercial quantities.
“Finding and development costs”	Capital costs incurred in the acquisition, exploration, appraisal and development of proved oil and natural gas reserves divided by proved reserve additions.
“FPSO”	Floating production, storage and offloading vessel.
“Mbbl”	Thousand barrels of oil.
“Mcf”	Thousand cubic feet.
“Mcfpd”	Thousand cubic feet per day.
“Mmbbl”	Million barrels of oil.
“Mmboe”	Million barrels of oil equivalent.
“Mmcf”	Million cubic feet.
“Natural gas”	Natural gas is a combination of light hydrocarbons that, in average pressure and temperature conditions is found in a gaseous state. In nature, it is found in underground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.
“Plan of development”	A written document outlining the steps to develop a field.
“Producing well”	A well that is found to be capable of producing hydrocarbons in sufficient quantities so that proceeds from the sale of such production exceed production expenses and taxes.

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KOSMOS ENERGY LTD.

GLOSSARY AND SELECT ABBREVIATIONS (CONTINUED)

“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).
“Royalty”	A fractional undivided interest in the production of oil and natural gas wells or the proceeds therefrom to be received free and clear of all costs of development, operations or maintenance.
“Working interest”	A percentage of ownership in an oil and gas lease granting its owner the right to explore, drill and produce oil and gas from a tract of property. Working interest owners are obligated to pay a corresponding percentage of the cost of leasing, drilling, producing and operating a well or unit. The working interest also entitles its owner to share in production with other working interest owners based on the percentage of working interest owned.

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KOSMOS ENERGY HOLDINGS

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	March 31,			December 31,
	2011			2010
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	290,704		$	100,415
Restricted cash	—			80,000
Receivables:
Joint interest billings	120,621			124,449
Notes	112,163			113,889
Other	66			615
Inventories	29,558			37,674
Prepaid expenses and other	14,024			13,278
Current deferred tax assets	103,257			89,600
Total current assets	670,393			559,920

Property and equipment:
Oil and gas properties, net of accumulated depletion of $28,119 and $6,430, respectively	1,074,328			989,869
Other property, net of accumulated depreciation of $5,954 and $5,343, respectively	7,947			8,131
Property and equipment - net	1,082,275			998,000

Other assets:
Restricted cash	—			32,000
Long-term receivables - joint interest billings, net of allowance	21,897			21,897
Debt issue costs and other assets, net of accumulated amortization of zero and $32,093, respectively	61,291			78,217
Derivatives	1,455			1,501
Total assets	$	1,837,311		$	1,691,535

Liabilities and unit holdings
Current liabilities:
Current maturities of long-term debt	$	—		$	245,000
Accounts payable	108,169			163,495
Accrued liabilities	41,897			53,208
Derivatives	27,781			20,354
Total current liabilities	177,847			482,057

Long-term liabilities:
Long-term debt	1,300,000			800,000
Derivatives	17,429			15,104
Asset retirement obligations	17,258			16,752
Leasehold improvement allowance	926			1,014
Deferred tax liability	12,513			12,513
Total long-term liabilities	1,348,126			845,383

Convertible preferred units, 100,000,000 units authorized:
Series A - 30,000,000 units issued at March 31, 2011 and December 31, 2010	389,827			383,246
Series B - 20,000,000 units issued at March 31, 2011 and December 31, 2010	577,962			568,163
Series C - 884,956 units issued at March 31, 2011 and December 31,2010	27,564			27,097

Unit holdings:
Common units, 100,000,000 units authorized; 19,090,162 and 19,069,662 issued at March 31, 2011 and Decemeber 31, 2010	516			516
Additional paid-in capital	—			—
Accumulated deficit	(686,577		)	(615,515		)
Accumulated other comprehensive income	2,046			588
Total unit holdings	(684,015		)	(614,411		)
Total liabilities, convertible preferred units and unit holdings	$	1,837,311		$	1,691,535

See accompanying notes.

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KOSMOS ENERGY HOLDINGS

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2011			2010
Revenues and other income:
Oil and gas revenue	$	92,569		$	—
Interest income	2,354			1,167
Other income	487			1,276
Total revenues and other income	95,410			2,443

Costs and expenses:
Oil and gas production	19,995			—
Exploration expenses, including dry holes	8,432			26,179
General and administrative	13,287			10,930
Depletion and depreciation	23,498			512
Amortization - debt issue costs	9,611			5,925
Interest expense	20,258			11,018
Derivatives, net	8,871			12,929
Loss on extinguishment of debt	59,643			—
Other expenses, net	(23		)	(71		)
Total costs and expenses	163,572			67,422

Loss before income taxes	(68,162		)	(64,979		)
Income tax expense (benefit)	(13,511		)	227

Net loss	(54,651		)	(65,206		)

Accretion to redemption value of convertible preferred units	(16,847		)	(15,745		)

Net loss attributable to common unit holders	$	(71,498	)	$	(80,951	)

See accompanying notes.

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KOSMOS ENERGY HOLDINGS

CONSOLIDATED STATEMENTS OF UNIT HOLDINGS EQUITY

(In thousands)

(Unaudited)

											Accumulated
					Additional						Other
	Common Units				Paid-in			Accumulated			Comprehensive
	Units		Amount		Capital			Deficit			Income		Total
Balance as of December 31, 2010	19,070		$	516	$	—		$	(615,515	)	$	588	$	(614,411	)
Issuance of profit units	23		—		—			—			—		—
Relinquishments	(3	)	—		—			—			—		—
Unit-based compensation	—		—		436			—			—		436
Derivatives, net	—		—		—			—			1,458		1,458
Accrete convertible preferred units to redemption amount	—		—		(436		)	(16,411		)	—		(16,847		)
Net loss	—		—		—			(54,651		)	—		(54,651		)
Balance as of March 31, 2011	19,090		$	516	$	—		$	(686,577	)	$	2,046	$	(684,015	)

See accompanying notes.

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KOSMOS ENERGY HOLDINGS

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2011			2010
Operating activities
Net loss	$	(54,651	)	$	(65,206	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and amortization	33,109			6,437
Deferred income taxes	(13,657		)	—
Unsuccessful well costs	3,444			21,960
Derivative related activity	11,256			14,483
Unit-based compensation	436			655
Loss on extinguishment of debt	59,643			—
Other	(88		)	(90		)
Changes in assets and liabilities:
(Increase) decrease in receivables	4,381			(8,066		)
(Increase) decrease in inventories	7,420			(1,958		)
Increase in prepaid expenses and other	(746		)	(6,015		)
Decrease in accounts payable	(55,326		)	(51,069		)
Decrease in accrued liabilities	(5,258		)	(12,157		)
Net cash used in operating activities	(10,037		)	(101,026		)

Investing activities
Oil and gas assets	(115,645		)	(111,247		)
Other property	(427		)	(120		)
Notes receivable	1,726			(24,505		)
Restricted cash	112,000			(110,400		)
Net cash used in investing activities	(2,346		)	(246,272		)

Financing activities
Borrowings under long-term debt	1,393,000			440,000
Payments on long-term debt	(1,138,000		)	—
Debt issue costs	(52,328		)	21
Net cash provided by financing activities	202,672			440,021

Net increase in cash and cash equivalents	190,289			92,723
Cash and cash equivalents at beginning of period	100,415			139,505
Cash and cash equivalents at end of period	$	290,704		$	232,228

Supplemental cash flow information

Cash paid for:
Interest	$	18,527		$	9,238
Income taxes	$	375		$	605

See accompanying notes.

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KOSMOS ENERGY HOLDINGS

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2011			2010
	(In thousands)
Net loss	$	(54,651	)	$	(65,206	)
Other comprehensive income:
Change in fair value of cash flow hedges	—			(1,097		)
Loss on cash flow hedge included in operations	1,458			1,554
Other comprehensive income	1,458			457
Comprehensive loss	$	(53,193	)	$	(64,749	)

See accompanying notes.

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KOSMOS ENERGY HOLDINGS

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

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 initial public offering on May 16, 2011, all of the interests in Kosmos Energy Holdings were exchanged for newly issued common shares of Kosmos Energy Ltd. and as a result Kosmos Energy Holdings became wholly owned by Kosmos Energy Ltd. However, as of the date of the unaudited financial statements included in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, our business operated as Kosmos Energy Holdings and its consolidated subsidiaries. Accordingly, the unaudited financial statements included in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 are those of Kosmos Energy Holdings and its consolidated subsidiaries. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed March 5, 2004. As a holding company, its management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. Kosmos Energy, LLC is a privately held Texas limited liability company that was formed April 23, 2003. Kosmos Energy, LLC became a wholly owned subsidiary of Kosmos Energy Holdings on March 9, 2004. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Holdings and its wholly owned subsidiaries, unless the context indicates otherwise. We are an independent oil and gas exploration and production company focused on underexplored regions in Africa. Kosmos Energy Holdings transitioned from its development stage to operational activities in January 2011. Accordingly, reporting as a development stage company is no longer deemed necessary.

We have one business segment which is the exploration and production of oil and natural gas.

On August 29, 2003, the founding partners contributed $350 thousand for which they received 350,000 units in Kosmos Energy, LLC. On March 9, 2004, the founding partners exchanged their 350,000 units in Kosmos Energy, LLC for 3,500,000 units in Kosmos Energy Holdings.

On October 9, 2009, upon execution and delivery and per Section 1.4 of the Kosmos Energy Holdings Second Amended and Restated Contribution Agreement, the Company issued a total of 2,500,000 C1 common units (“C1 Common Units”) to the Series C Convertible Preferred investors. The proceeds of $25 million from the November 2, 2009 issuance of Series C Convertible Preferred Units (“Series C”) was allocated on a relative fair value basis between the C1 Common Units and the Series C of $11.8 million and $13.2 million, respectively. See Note 12—Convertible Preferred Units.

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 March 31, 2011, the consolidated results of operations for the three months ended March 31, 2011 and 2010, and consolidated cash flows for the three months ended March 31, 2011 and 2010. 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. 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, 2010 included in our final prospectus.

Basic and diluted net loss per common unit holder is not presented since the ownership structure of the Company is not a common unit of ownership.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Kosmos Energy Holdings and its wholly owned subsidiaries. All intercompany transactions have been eliminated.

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KOSMOS ENERGY HOLDINGS

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.

Cash and Cash Equivalents

Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.

Restricted Cash

At March 31, 2011 and December 31, 2010, Kosmos had a total of zero and $112.0 million, respectively, of restricted cash included in current and long-term assets.

As of December 31, 2010, in accordance with our project financing commercial debt facilities agreement, we had the following types of restricted cash: (1) a balance at all times of not less than $30.0 million is required during the year prior to Project Completion of the Jubilee Field Phase 1 Development (as defined in the agreement); (2) not less than $50.0 million in the Reserve Equity account which may only be withdrawn from the account to pay Jubilee Field Phase 1 costs under certain circumstances, or after Project Completion is available for withdrawal; and (3) not less than $9.0 million in the Stamp Duty Reserve account which may be utilized to meet any payment of stamp duty taxes in Ghana. Additionally, effective December 30, 2010, Kosmos Energy Finance, a wholly owned subsidiary of the Company, provided a $23.0 million cash collateralized irrevocable standby Letter of Credit in respect of Kosmos Energy Ghana HC’s (“Kosmos Ghana”), a wholly owned subsidiary of the Company, Jubilee paying interest share of Tullow Ghana Limited’s (“TGL”) Letter of Credit related to their drilling contract for the “Eirik Raude”. The Letter of Credit expires on September 14, 2011. In March 2011, the restricted cash related to the debt facilities agreement and the cash collateral for the Letter of Credit was released as part of the debt refinancing. The Letter of Credit is collateralized by our available borrowing capacity under the commercial debt facility. See Note 9 — Commercial Debt Facilities.

Receivables

The Company’s receivables consist of joint interest billings, notes and other receivables for which the Company generally does not require collateral security. Receivables from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things. The Company’s allowances for doubtful accounts totaled $39.8 million as of March 31, 2011 and December 31, 2010.

Inventories

Inventories consisted of $18.9 million and $25.2 million of materials and supplies and $10.7 million and $12.5 million of hydrocarbons as of March 31, 2011 and December 31, 2010, respectively. The Company’s materials and supplies inventory is primarily comprised 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 (including depletion) directly and indirectly incurred in bringing the inventory to its existing condition. Selling expenses and general and administration expenses are reported as period costs and excluded from inventory costs.

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KOSMOS ENERGY HOLDINGS

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Exploration and Development Costs

The Company follows the successful efforts method of accounting for costs incurred in oil and natural gas exploration and production operations. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when proved reserves are found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are charged to expense as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed.

During the three months ended March 31, 2011 and 2010, Kosmos recognized exploration expense of $8.4 million and $26.2 million, respectively.

The Company evaluates unproved property periodically for impairment. The majority of these costs is generally related to the acquisition of leasehold costs. The impairment assessment considers results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential future reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time.

Depletion, Depreciation and Amortization

Proved properties and support equipment and facilities are depleted using the unit-of-production method based on estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in discovery of proved reserves and development costs are amortized using the unit-of-production method based on estimated proved developed oil and natural gas reserves.

Depreciation and amortization of other property is computed using the straight-line method over estimated useful lives ranging from three to seven years.

		Years Depreciated
Leasehold improvements		6
Office furniture, fixtures and computer equipment		3 to 7
Vehicles		5

Amortization of debt issue costs is computed using the straight-line method over the life of the related commercial debt facilities.

Capitalized Interest

Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets.

Asset Retirement Obligations

The Company accounts for asset retirement obligations as required by the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long-lived asset with an existing asset retirement obligation is acquired, a liability for that obligation shall be recognized at the asset’s acquisition date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing

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KOSMOS ENERGY HOLDINGS

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

the carrying amount of the related long-lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time as accretion expense in the consolidated statement of operations.

Variable Interest Entity

A variable interest entity (“VIE”), as defined by FASB ASC 810—Consolidation, is an entity that by design has insufficient equity to permit it to finance its activities without additional subordinated financial support or equity holders that lack the characteristics of a controlling financial interest. VIEs are consolidated by the primary beneficiary, which is the entity that has the power to direct the activities of the VIE that most significantly impact the VIE’s performance and will absorb losses, or receive benefits from the VIE that could potentially be significant to the VIE.

Our wholly owned subsidiaries, Kosmos Energy Finance and Kosmos Energy Finance International, meet the definition of a VIE and the Company, which is the ultimate parent of both subsidiaries, is the primary beneficiary. As a result, Kosmos Energy Finance and Kosmos Energy Finance International are consolidated in these financial statements.

As of March 31, 2011 and December 31, 2010, Kosmos Energy Finance had $23.0 and $58.0 million, respectively, included in cash and cash equivalents. Kosmos Energy Finance did not have any other assets or liabilities as of March 31, 2011. This cash was transferred in April 2011 to Kosmos Energy Finance International as a result of the debt refinancing in March 2011. After April 2011, Kosmos Energy Finance will have no financial statement activity in the future. As of December 31, 2010, Kosmos Energy Finance’s other assets and liabilities were shown separately on the face of the consolidated balance sheet in the following line items: current and long-term restricted cash; debt issue costs; long-term derivatives asset; current and long-term debt; and current and long-term derivatives liabilities.

Prior to March 31, 2011, Kosmos Energy Finance International did not have any financial statement activity. Kosmos Energy Finance International’s assets and liabilities are shown separately on the face of the consolidated balance sheet as of March 31, 2011, in the following line items: debt issue costs; long-term derivatives asset; long-term debt; and current and long-term derivatives liabilities. At March 31, 2011, Kosmos Energy Finance International had $239.2 million included in cash and cash equivalents and $1.7 million included in accrued liabilities.

Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. FASB ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long-lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell.

Derivative Instruments and Hedging Activities

We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of deferred premium puts and compound options (calls on puts). We also use interest rate swap contracts to mitigate our exposure to interest rate fluctuations related to our commercial debt facilities. Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We do not apply hedge accounting to our oil derivative contracts. Effective June 1, 2010, we discontinued hedge accounting on our interest rate swap contracts and accordingly the changes in the fair value of the instruments are recognized in income in the period of change. See Note 10—Derivative Financial Instruments.

Estimates of Proved Oil and Natural Gas Reserves

Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are found in the future, estimated reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the Securities and Exchange Commission and the FASB. The accuracy of these reserve estimates is a function of:

· the engineering and geological interpretation of available data;

· estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost;

· the accuracy of various mandated economic assumptions (such as the future prices of oil and natural gas); and

· the judgments of the persons preparing the estimates.

Revenue Recognition

We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. Oil production commenced on November 28, 2010 and we received revenues from oil production in January 2011.

Income Taxes

The Company accounts for income taxes as required by the FASB ASC 740—Income Taxes. Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. See Note 14 — Income Taxes.

Foreign Currency Translation

The U.S. dollar is the functional currency for all of the Company’s foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are de minimis, and as such, the effect of exchange rate changes is not material to any reporting period.

Profit Units

The Company issues common units designated as profit units at various times to employees and certain directors with a threshold value of $0.85 to $90. The Company accounts for these units in accordance with FASB ASC 718—Compensation—Stock Compensation. The fair value of the profit units is expensed and recognized on a straight-line basis over the vesting periods of the awards.

Employees

The majority of our full-time employees were leased through TriNet Acquisition Corp. through September 30, 2010. TriNet Acquisition Corp. administered all salaries, benefits and payment of taxes, and billed Kosmos semimonthly for its cost. This contract was cancelled effective September 30, 2010 at which time all full-time employees previously leased through TriNet Acquisition Corp. became employees of the Company.

Recent Accounting Standards

We have reviewed recently issued accounting pronouncements that became effective during the three months ended March 31, 2011, and have determined that none would have a material impact on our consolidated financial statements.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

3. Notes Receivable

During the quarter ended December 31, 2009, Kosmos entered into four participation agreements totaling $185.0 million with Tullow Group Services Limited (“TGSL”). The participation agreements allowed Kosmos Ghana to participate in TGSL’s advances to MODEC, Inc. (“MODEC”) to fund the construction of the FPSO facility. The FPSO facility is now connected to the Jubilee Field. The amounts loaned to TGSL were recorded as short-term notes receivables and accrued interest at rates between 3.74% and 3.78% per annum. The total participation limit for Kosmos Ghana was $52.1 million, which was fully funded as of December 31, 2009. Also, included in the notes receivable balance at December 31, 2009, was total interest income of $0.2 million for the year then ended. Effective May 7, 2010, the loan agreements and associated participation agreements were deemed paid and terminated under the Advance Payments Agreement discussed below.

Effective May 7, 2010, TGL, acting on behalf of the Unitization and Unit Operating Agreement (“UUOA”) parties, entered into the Advance Payments Agreement with MODEC related to partially financing the construction of the FPSO facility. The payments limit for the Advance Payments Agreement is $466.3 million of which Kosmos Ghana’s share is $122.2 million. Of the $466.3 million, $341.1 million was deemed to have been advanced from TGL to MODEC. This amount included $188.9 million, principal and interest, related to the loan agreements; $127.3 million representing cash calls made between January 2010 and May 7, 2010, by MODEC to TGL under the Letter of Intent; and $25.0 million representing the payment by TGL on January 15, 2010, to enable MODEC to pay fees in connection with its long-term financing. MODEC is required to repay TGL on the earlier of September 15, 2011 or the date of the first drawdown under MODEC’s long-term financing. Based on the terms of the joint operating agreement for the Jubilee Unit, TGL is required to reimburse us the amounts MODEC reimburses TGL within 10 business days of repayment by MODEC. As of March 31, 2011 and December 31, 2010, Kosmos Ghana’s share of the payments made under the Advance Payments Agreement was $112.2 million and $113.9 million (including accrued interest of $0.3 million), respectively. During the three months ended March 31, 2011 and 2010 we recognized interest income of $1.4 million and zero, respectively.

4. Jubilee Field Unitization

The Jubilee Field in Ghana, discovered by the Mahogany-1 well in June 2007, covers an area within both the West Cape Three Points (“WCTP”) and Deepwater Tano (“DT”) Blocks. Consistent with the Ghanaian Petroleum Law, the WCTP and DT Petroleum Agreements and as required Ghana’s Ministry of Energy, it was agreed the Jubilee Field would be unitized for optimal resource recovery. In late February 2008, the contractors in the WCTP and DT Blocks agreed to an interim unit agreement (“the Pre Unit Agreement”). According to the Pre Unit Agreement, the initial Jubilee Field unit area, which boundary at the time was an approximation of the boundaries of the Jubilee Field, was deemed to consist of 35% of an area from the WCTP Block and 65% of an area from the DT Block. However, the tract participations were allocated 50% for the WCTP Block and 50% for the DT Block pending the drilling results of the Mahogany-2 well. It was announced that the Mahogany-2 well confirmed the Jubilee Field discovery on May 5, 2008. Pursuant to the Pre Unit Agreement, the unit boundaries were modified to include the Mahogany-2 well and the tract participations remained 50% for each block. Pursuant to the Pre Unit Agreement, Kosmos Ghana, TGL, Anadarko WCTP Company, Sabre Oil & Gas Holdings Limited, EO Group Limited (“EO Group”) and Ghana National Petroleum Corporation’s (“GNPC”) unit participating interests were 24.4375%, 36.423%, 24.4375%, 2.952%, 1.75% and 10%, respectively.

Kosmos Ghana and its partners subsequently commenced development operations and negotiated a more comprehensive unit agreement, the UUOA, to unitize the Jubilee Field and govern each party’s respective rights and duties in the Jubilee Unit. On July 13, 2009, the Ministry of Energy provided its written approval of the UUOA. The UUOA was executed by all parties and was effective July 16, 2009, the date the final condition precedent to effectiveness was satisfied. As a result, for the Jubilee Unit, based on existing tract allocations (50% for each Block), and GNPC electing to acquire its additional paying interest under the WCTP and DT Blocks, Kosmos Ghana, TGL, Anadarko WCTP Company, Sabre Oil & Gas Holdings Limited, EO Group and GNPC’s unit participating interest became 23.4913%, 34.7047%, 23.4913%, 2.8127%, 1.75% and 13.75%, respectively. TGL, a subsidiary of Tullow Oil plc, is the Unit Operator, and Kosmos Ghana is the Technical Operator for the development of the Jubilee Unit. The accounting for the Jubilee Unit included in these consolidated financial statements is in accordance with the tract participation stated in the UUOA, which is 50% for the WCTP Block and 50% for the DT Block. Although the Jubilee Field is unitized, Kosmos Ghana’s working interest in each block outside the boundary of the Jubilee Unit area remains the same. Kosmos Ghana remains operator of the WCTP Block outside the Jubilee Unit area.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Pursuant to the requirements of the WCTP and DT Petroleum Agreements, Kosmos Ghana (for the WCTP Block) and TGL (for the DT Block) submitted a declaration of commerciality for each block and a plan for the initial phase of development of the Jubilee Field (“Jubilee PoD”) to Ghana’s Ministry of Energy in late 2008. A declaration of commerciality is a formal designation made pursuant to each of the Petroleum Agreements. Pursuant to discussions among the Jubilee Unit partners, GNPC and the Ministry of Energy, the contractor parties for the two blocks resubmitted a revised Jubilee PoD to GNPC who then submitted it to the Ministry of Energy for approval in April 2009. On July 13, 2009, the Ministry of Energy provided its written approval of the Jubilee Field Phase 1 Development Plan. Jubilee Field development operations are ongoing.

5. Joint Interest Billings

The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. EO Group’s share of costs to first production under the WCTP Petroleum Agreement were paid by Kosmos Ghana. EO Group is required to reimburse Kosmos Ghana for all development costs paid by Kosmos Ghana on EO Group’s behalf. Repayment is expected to be funded through EO Group’s future production revenues. The related receivable became due upon commencement of production. In August 2009, GNPC notified our applicable unit partners and us that it would exercise its right for the applicable contractor group to pay its 2.5% WCTP Block share and 5.0% DT Block share of the Jubilee Field development costs and be reimbursed for such costs plus interest out of a portion of GNPC’s production revenues under the terms of the WCTP Petroleum Agreement and DT Petroleum Agreement, respectively. Oil production from the Jubilee Unit commenced on November 28, 2010. Joint interest billings are classified on the face of the consolidated balance sheets between current and long-term based on when recovery is expected to occur. Long-term balances are shown net of allowances of $39.8 million as of March 31, 2011 and December 31, 2010.

6. Property and Equipment

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

	March 31, 2011			December 31, 2010
	(In thousands)
Oil and gas properties, net:
Proved properties	$	466,704		$	426,831
Unproved properties	248,528			198,149
Support equipment and facilities	387,215			371,319
Less: accumulated depletion	(28,119		)	(6,430		)
	$	1,074,328		$	989,869

As of March 31, 2011 and 2010, the Company has recorded $22.4 million and zero of depletion expense, respectively. The Company had depletion costs of $5.7 million and $6.4 million related to crude oil inventory as of March 31, 2011 and December 31, 2010, respectively.

7. Suspended Well Costs

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or is impaired. The capitalized exploratory well costs are presented in oil and gas properties in the consolidated balance sheets. If the exploratory well is determined to be impaired, the well costs are charged to expense.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The following table reflects the Company’s capitalized exploratory well activities during the three months ended March 31, 2011:

	March 31, 2011
	(In thousands)
Beginning balance (January 1, 2011)	$	167,511
Additions to capitalized exploratory well costs pending the determination of proved reserves	53,842
Reclassification due to determination of proved reserves	—
Capitalized exploratory well costs charged to expense	—
Ending balance (March 31, 2011)	$	221,353

The following table provides aging of capitalized exploratory well costs based on the date the 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:

	March 31, 2011		December 31, 2010
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	90,771	$	49,022
Exploratory well costs capitalized for a period greater than one year	130,582		118,489
Ending balance	$	221,353	$	167,511
Number of projects with exploratory well costs that have been capitalized for more than one year	7		6

As of March 31, 2011, the exploratory well costs capitalized for more than one year since the completion of drilling are the Odum-1, Odum-2, Mahogany-3, Mahogany-4 and Mahogany Deep-2 exploration wells in the WCTP Block and the Tweneboa-1 and Tweneboa-2 wells in the DT Block. All costs incurred are approximately one to three years old.

Odum Discovery—Results of the Odum-2 appraisal well drilled during late 2009 indicate that additional evaluation and studies, including the identification of nearby prospects, is required before making a decision on whether the Odum Field can be declared a commercial discovery. Due to the technical challenges presented by the gravity of the oil encountered to date, development planning is ongoing under Article 8.17 of the WCTP Petroleum Agreement which, in certain circumstances, allows additional time for further evaluation, studies, planning and potential well operations, including exploration activities. Provided the technical solutions can be properly engineered, a declaration of commerciality may be submitted for the Odum discovery by July 2011 with a plan of development submittal within the subsequent six months.

Mahogany East Area—Three appraisal wells, Mahogany-4, Mahogany-5 and Mahogany Deep-2, have been drilled and suspended. The Mahogany Deep reservoir and the reservoirs encountered in the appraisal section of the Mahogany-3 well will be included in the Mahogany East Field. The Mahogany East Area was declared commercial on September 6, 2010, and a plan of development was submitted to Ghana’s Ministry of Energy as of May 2, 2011. The plan of development is being reviewed by Ghana’s Ministry of Energy.

Tweneboa Discovery—Two appraisal wells, Tweneboa-2 and Tweneboa-3, have been drilled and suspended. A decision regarding commerciality of the Tweneboa discovery is expected to be made by the DT block partners by 2012 following additional appraisal, drilling and evaluation. A plan of development would be prepared for submission to Ghana’s Ministry of Energy within six months after such a declaration.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

8. Accounts Payable and Accrued Liabilities

At March 31, 2011 and December 31, 2010, $108.2 million and $163.5 million were recorded for invoices received but not paid, respectively. Accrued liabilities were $41.9 million and $53.2 million at March 31, 2011 and December 31, 2010, respectively. Accrued liabilities consist of the following:

	March 31, 2011		December 31, 2010
	(In thousands)
Accrued liabilities:
Accrued exploration and development	$	17,147	$	26,843
Accrued general and administrative expenses	22,095		23,393
Accrued debt issue costs	541		—
Taxes other than income	1,959		1,936
Accrued interest	—		655
Income taxes	155		381
	$	41,897	$	53,208

9. Commercial Debt Facilities

In March 2011, the Company secured a commercial debt facility (“the Facility”) from a number of financial institutions for up to $2.0 billion. The funds will be used to support our oil and gas exploration, appraisal and development program and corporate activities and to refinance existing debt facilities. The loan commitment may be increased up to a maximum of $3.0 billion if the lenders increase their loan commitments or if loan commitments of new financial institutions are added. The existing debt facilities were repaid and terminated in connection with the closing of the Facility in March 2011.

As part of the refinancing of our existing debt facilities in March 2011, we recorded a $59.6 million loss on the extinguishment of debt. Additionally, we have $61.3 million of debt issue costs related to the Facility, which will be amortized over the term of the Facility.

Interest expense was $15.6 million and $7.7 million (net of capitalized interest of $1.2 million and $1.7 million) and commitment fees were $2.3 million and $1.8 million for the three months ended March 31, 2011 and 2010, respectively.

The Facility includes a syndicate of institutions. BNP Paribas SA is the Facility Agent and Security Agent, Société Générale, London Branch is the Lead Technical and Modeling Bank, Crédit Agricole Corporate and Investment Bank is the Co-Technical and Modeling Bank and HSBC Bank plc is the Co-Technical Bank. The Facility has a final maturity date of March 29, 2018.

The interest is the aggregate of the applicable margin (3.25% to 4.75%, depending on the amount of the Facility that is being utilized and the length of time that has passed from the date the Facility was entered into); LIBOR; and mandatory cost (if any, as defined in the Facility). Interest on each loan is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). Kosmos pays commitment fees on the undrawn and unavailable portion of the total commitments. Commitment fees for the lenders are equal to 40% per annum of the then-applicable respective margin when a commitment is available for utilization and, equal to 20% per annum of the then-applicable respective margin when a commitment is not available for utilization.

The Facility provides a revolving-credit and letter of credit facility for an availability period which expires on May 15, 2014 (in the case of the revolving-credit facility) and on the final maturity date (in the case of the letter of credit facility). The available facility amount is subject to borrowing base constraints and is also constrained by the amortization schedule (once repayments under the Facility begin in June 2014). As of May 15, 2014, outstanding borrowings will be subject to an amortization schedule. The first required payment is due on June 15, 2014, subject to the level of outstanding borrowings.

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

as part of a forecast that is prepared by and agreed on by Kosmos and the Technical and Modeling Banks. The formula to calculate the borrowing base amount is based, in part, on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages. As of March 31, 2011, borrowings against the Facility totaled $1.3 billion. As of March 31, 2011, the undrawn availability under the Facility was an additional $128.0 million, net of a $23.0 million Letter of Credit related to the drilling contract for the Eirik Raude Rig (see Note 2 — Accounting Policies) which is secured by our available borrowing capacity. Total committed undrawn capacity provided for in the Facility is $700 million, which will be available to Kosmos should the borrowing base increase.

If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over assets held by the group.

As of March 31, 2011, we were in compliance with the financial covenants contained in the Facility, which require the maintenance of:

· the field life cover ratio, not less than 1.30x; and

· the loan life cover ratio, not less than 1.10x,

in each case, as calculated on the basis of all available information. The “field life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of net cash flow through the depletion of the Jubilee Field plus the net present value of 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. 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 commercial debt 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.

At March 31, 2011, the scheduled maturities of debt during the next five years and thereafter are as follows:

	Payments Due by Year
	2011 (1)		2012		2013		2014		2015		Thereafter
	(In thousands)
Commercial debt facility(2)	$	—	$	—	$	—	$	—	$	300,000	$	1,000,000

(1) Represents payments for the period April 1, 2011 through December 31, 2011.

(2) The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of March 31, 2011. 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.

10. Derivative Financial Instruments

The Company uses 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.

The Company applies the provisions of the FASB ASC 815—Derivatives and Hedging, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. The Company does not apply hedge accounting treatment to its oil derivative contracts and, therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts, are shown in our statement of operations.

Effective June 1, 2010, the Company discontinued hedge accounting on all interest rate derivative instruments. Therefore, the Company recognizes, from that date forward, changes in the fair value of the instruments in income during the period of change. The effective portions of the discontinued hedges as of May 31, 2010, are included in accumulated other comprehensive income or loss (“AOCI(L)”), in the equity section of the accompanying consolidated balance sheets, and are being transferred to earnings when the hedged transaction is recognized in earnings. Any ineffective portion of the mark-to-market gain or loss was recognized in earnings.

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KOSMOS ENERGY HOLDINGS

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Oil Derivative Contracts

In 2010, we entered into various oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production. These contracts have consisted of deferred premium puts and compound options (calls on puts).

The Company manages market and counterparty credit risk in accordance with policies and guidelines approved by the Board. In accordance with these policies and guidelines, the Company’s management determines the appropriate timing and extent of derivative transactions. We have included an estimate of nonperformance risk in the fair value measurement of our commodity derivative contracts as required by the FASB ASC 820—Fair Value Measurements and Disclosures. At March 31, 2011, the net liability of commodity derivative contracts was reduced by $1.1 million for estimated nonperformance risk.

The following table sets forth, as of March 31, 2011, the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per bbl for those contracts:

Type of Contract and Period	bbl/day	Weighted Average Floor Price		Weighted Average Deferred Premium/bbl
Deferred Premium Puts
July 2011 - December 2011	11,332	$	72.01	$	8.90
January 2012 - December 2012	4,625	62.74		7.04
January 2013 - December 2013	2,515	61.73		7.32
Compound Options (calls on puts)
July 2012 - December 2012(1)	5,399	66.48		6.73
January 2013 - June 2013(1)	3,855	66.48		7.10

(1) The calls expire June 29, 2012, and have a weighted average premium of $4.82/bbl.

Interest Rate Swaps Derivative Contracts

In 2010, Kosmos entered into derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt to a weighted average fixed rate. The following table summarizes our open interest rate swaps as of March 31, 2011:

Termination Date	Notional Amount		Fixed Rate		Floating Rate
	(In thousands)
June 2014	$	77,500	0.98	%	6-month LIBOR
June 2015	75,000		1.34	%	6-month LIBOR
June 2016	161,250		2.22	%	6-month LIBOR
June 2016	161,250		2.31	%	6-month LIBOR

Effective June 1, 2010, the Company discontinued hedge accounting on all existing interest rate derivative instruments. Prior to June 1, 2010, any ineffectiveness on the interest rate swaps was immaterial; therefore, no amount was recorded in earnings for ineffectiveness. We have included an estimate of nonperformance risk in the fair value measurement of our interest rate derivative contracts as required by the FASB ASC 820—Fair Value Measurements and Disclosures. At March 31, 2011, the net liability of interest rate derivative contracts was reduced by $0.2 million for estimated nonperformance risk.

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KOSMOS ENERGY HOLDINGS

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The following tables disclose the Company’s derivative instruments as of March 31, 2011 and December 31, 2010:

		Estimated Fair Value
		Asset (Liability)
		March 31,			December 31,
Type of Contract	Balance Sheet Location	2011			2010
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative asset:
Commodity	Derivatives assets - current	$	—		$	—
Interest rate	Derivatives assets - current	—			—
Commodity	Derivatives assets - noncurrent	—			—
Interest rate	Derivatives assets - noncurrent	1,455			1,501

Derivative liability:
Commodity	Derivatives liabilities - current	(20,257		)	(13,979		)
Interest rate	Derivatives liabilities - current	(7,524		)	(6,375		)
Commodity	Derivatives liabilities - long-term	(16,933		)	(14,340		)
Interest rate	Derivatives liabilities - long-term	(496		)	(764		)

Total derivatives not designated as hedging instruments		$	(43,755	)	$	(33,957	)

		Amount of Gain/(Loss)
		Three Months Ended
		March 31,
Type of Contract	Location of Gain/(Loss)	2011			2010
		(In thousands)
Derivatives in cash flow hedging relationships:
Interest rate	AOCI(L)	$	—		$	457
Interest rate(1)	Interest expense	(1,458		)	(1,554		)
Total derivatives in cash flow hedging relationships		$	(1,458	)	$	(1,097	)

Derivatives not designated as hedging instruments:
Commodity	Derivatives, net	$	(8,871	)	$	(12,929	)
Interest rate	Interest expense	(927		)	—
Total derivatives not designated as hedging instruments		$	(9,798	)	$	(12,929	)

(1) Amounts were reclassified from AOCI(L) into earnings.

The fair value of the effective portion of the derivative contracts on May 31, 2010, is reflected in AOCI(L) and is being transferred to interest expense over the remaining term of the contracts. In accordance with the mark-to-market method of accounting, the Company will recognize all future changes in fair values of its derivative contracts as gains or losses in earnings during the period in which they occur. The Company expects to reclassify $1.7 million of AOCI(L) losses to interest expense within the next 12 months. See Note 13—Fair Value Measurements for additional information regarding the Company’s derivative instruments.

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KOSMOS ENERGY HOLDINGS

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

11. Asset Retirement Obligations

The following table summarizes the changes in the Company’s asset retirement obligations:

	March 31, 2011
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	16,752
Liabilities incurred during period	—
Revisions in estimated retirement obligations	—
Liabilities settled during period	—
Accretion expense	506
Ending asset retirement obligations	$	17,258

The Ghanaian legal and regulatory regime regarding oil field abandonment and other environmental matters is evolving. Currently, no Ghanaian environmental regulations expressly require that companies abandon or remove offshore assets although under international industry standards we would do so. The Petroleum Law provides for restoration that includes removal of property and abandonment of wells, but further states the manner of such removal and abandonment will be as provided in the Regulations; however, such Regulations have not been promulgated. Under the Environmental Permit for the Jubilee Field, issued to TGL, a decommissioning plan will be prepared and submitted to the Ghana Environmental Protection Agency. ASC 410 requires the Company to recognize this liability in the period in which the liability was incurred. We have recorded an asset retirement obligation for fields that have commenced production, including wells in progress in such fields. Accordingly, the Company recognized a liability in the quarterly period ending December 31, 2010, related to our asset retirement obligations.

12. Convertible Preferred Units

On February 11, 2004, under the Kosmos Energy Holdings Contribution Agreement, Kosmos received provisional commitments of up to $300.0 million from Warburg Pincus, The Blackstone Group, the management group, certain accredited employee investors and directors to pursue the acquisition, exploration and development of oil and gas ventures in West Africa. For each $10 contribution, one Series A Convertible Preferred Unit (“Series A”) was issued. Contributions began on March 9, 2004.

On June 18, 2008, under the Kosmos Energy Holdings Amended and Restated Contribution Agreement, Kosmos secured an additional provisional commitment of up to $500.0 million from Warburg Pincus, The Blackstone Group, the management group, certain accredited employee investors and directors. For each $25 contribution, one Series B Convertible Preferred Unit (“Series B”) was issued. Contributions began on November 3, 2008.

On October 9, 2009, under the Kosmos Energy Holdings Second Amended and Restated Contribution Agreement, Kosmos secured an additional provisional commitment of up to $250.0 million from Warburg Pincus, The Blackstone Group, the management group, certain accredited employee investors and directors. For each $28.25 contribution, one Series C was issued. Contributions began on November 2, 2009. Upon execution and delivery and per Section 1.4 of the Kosmos Energy Holdings Second Amended and Restated Contribution Agreement, the Company issued a total of 2,500,000 C1 Common Units to the Series C investors. The proceeds from the Series C issuance were allocated on a relative fair value basis between the Series C and the C1 Common Units, which created a discount on the Series C of approximately $11.8 million. The discount on the Series C has been recorded as of December 31, 2010, the date at which a determination was made that it was probable that an exchange of securities for common shares would occur.

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KOSMOS ENERGY HOLDINGS

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

As of March 31, 2011, Series A, Series B and Series C contributions and the accumulated preferred return were as follows (in thousands, including unit data):

	Warburg Pincus		The Blackstone Group		Other Investors			Total
Series A:
2004 Issuance of 1,100 units	$	5,958	$	4,875	$	167		$	11,000
2005 Retirement of 6 units	—		—		(63		)	(63		)
2005 Issuance of 3,100 units	16,551		13,542		907			31,000
2006 Retirement of 9 units	—		—		(85		)	(85		)
2006 Issuance of 2,010 units	10,775		8,815		510			20,100
2007 Issuance of 10,505 units	56,506		46,232		2,310			105,048
2008 Issuance of 13,300 units	71,508		58,508		2,984			133,000
Accumulated preferred return	48,296		39,516		2,015			89,827
Total Issuances—Series A	$	209,594	$	171,488	$	8,745		$	389,827
Series B:
2008 Issuance of 7,986 units	$	107,718	$	88,132	$	3,806		$	199,656
2009 Issuances of 12,014 units	161,576		132,199		6,569			300,344
Accumulated preferred return	41,989		34,355		1,618			77,962
Total Issuances—Series B	$	311,283	$	254,686	$	11,993		$	577,962
Series C:
November 2, 2009 Issuance of 885 units	$	7,126	$	5,830	$	288		$	13,244
Accretion	6,325		5,175		256			11,756
Accumulated preferred return	1,379		1,129		56			2,564
Total Issuances—Series C	$	14,830	$	12,134	$	600		$	27,564

Under the Fourth Amended and Restated Operating Agreement of Kosmos Energy Holdings, as amended, (the “Agreement”) governing the Company, the holders of the Series A, Series B and Series C (collectively, “Convertible Preferred Units”) would receive distributions, if any, equal to the “Accreted Value” of the units, prior to any distributions to the common unit holders. The Accreted Value is defined in the Agreement as the unit purchase price plus the preferred return amount per unit equal to 7% of the Accreted Value per annum (compounded quarterly) for the first nine years after the year of our initial operating agreement and 14% of the Accreted Value per annum (compounded quarterly) thereafter, unless a monetization event (as defined in the Agreement) occurs at which time the preferred return would revert to 7%. The holders of the Convertible Preferred Units will receive the accumulated preferred return upon the consummation of a “Qualified Public Offering” as defined in the Agreement. The accumulated preferred return on the Convertible Preferred Units has been recorded through March 31, 2011. The amount was applied to additional paid-in capital first, with the remaining amount applied to the accumulated deficit.

Distributions to the unit holders would be made in the following order of priority. First, the entire preferred return amount related to the Convertible Preferred Units; then, the purchase price for each Convertible Preferred Unit would be distributed to the Convertible Preferred Unit holders. Any remaining amounts would be distributed to all unit holders in accordance with their respective percentage interests provided the threshold value of the unit was met. The Series A threshold value is zero; therefore, these units would begin participation immediately. The Series B and Series C threshold values are $15 and $18.25, respectively. The common units’ threshold values are zero for the management units, $18.25 for the C1 Common Units and range from $0.85 to $90 for the profit units. Such units would begin participation in any distribution after their respective threshold value was met.

Upon and immediately prior to the consummation of a Qualified Public Offering, each outstanding Common Unit and each outstanding Convertible Preferred Unit would be exchanged (at values determined in the Agreement) into common shares of the “IPO Corporation,” as defined in the Agreement. Each preferred share of the IPO Corporation would be exchanged for common shares of the IPO Corporation equal to the accreted value at the option of the unit holders plus common shares of the IPO Corporation based on the provisions of the Agreement. The Convertible Preferred Units are classified as mezzanine equity as the Company cannot solely control the type of consideration issuable on the exchange and the Convertible Preferred Unit holders control the Company’s Board of Managers. See Note 16 — Subsequent Events.

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KOSMOS ENERGY HOLDINGS

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

13. Fair Value Measurements

In accordance with the FASB 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. These two types of inputs are further prioritized into the following fair value input hierarchy:

· Level 1—quoted prices for identical assets or liabilities in active markets.

· Level 2—quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means.

· Level 3—unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2011 and December 31, 2010, 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)
March 31, 2011
Assets:
Money market accounts	$	19,558	$	—		$	—	$	19,558
Interest rate derivatives	—		1,455			—		1,455
Liabilities:
Commodity derivatives	—		(37,190		)	—		(37,190		)
Interest rate derivatives	—		(8,020		)	—		(8,020		)
Total	$	19,558	$	(43,755	)	$	—	$	(24,197	)

December 31, 2010
Assets:
Money market accounts	$	18,056	$	—		$	—	$	18,056
Interest rate derivatives	—		1,501			—		1,501
Liabilities:
Commodity derivatives	—		(28,319		)	—		(28,319		)
Interest rate derivatives	—		(7,139		)	—		(7,139		)
Total	$	18,056	$	(33,957	)	$	—	$	(15,901	)

All fair values have been adjusted for nonperformance risk resulting in a decrease of the commodity derivative liabilities of approximately $1.1 million and a decrease of the interest rate derivatives of approximately of $0.2 million as of March 31, 2011. When the accumulated net present value for all of the derivative contracts with a counterparty are in an asset position, the Company uses the counterparty’s credit default swap (“CDS”) rates to estimate non-performance risk. When the

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KOSMOS ENERGY HOLDINGS

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

accumulated net present value for all derivative contracts for a counterparty are in a liability position, the Company uses its internal rate of borrowing to estimate our non-performance risk.

The following table presents the carrying amounts and fair values of the Company’s financial instruments as of March 31, 2011 and December 31, 2010:

	March 31, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Assets:
Money market accounts	$	19,558	$	19,558	$	18,056	$	18,056
Interest rate derivatives	$	1,455	$	1,455	$	1,501	$	1,501
Liabilities:
Commodity derivatives	$	37,190	$	37,190	$	28,319	$	28,319
Interest rate derivatives	$	8,020	$	8,020	$	7,139	$	7,139

The book values of cash and cash equivalents, joint interest billings, notes 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 commercial debt facilities approximates fair value since they are subject to short-term floating interest rates that approximate the rates available to the Company for those periods. The Company’s long-term receivables after allowance approximate fair value.

Commodity Derivatives

The Company’s commodity derivatives represent crude oil deferred premium puts and compound options for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to the Company’s 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 is 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. The Company’s commodity derivative liability measurements represent Level 2 inputs in the hierarchy priority. See Note 10—Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.

Interest Rate Derivatives

As of March 31, 2011 and December 31, 2010 the Company had interest rate swaps with notional amounts of $475.0 million, 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. The Company’s interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy priority.

14. Income Taxes

The income tax provision (benefit) for the three months ended March 31, 2011 and 2010 was $(13.5) million and $227 thousand, respectively. The income tax provision consists of U.S. and Ghanaian income and Texas margin taxes.

Due to the operating losses incurred since inception, the Company did not record an income tax benefit related to the losses incurred in Cameroon. A valuation allowance has been recorded against the Cameroon net deferred tax asset of $25.4 million.

The Company entered into a Petroleum Agreement in Morocco in 2006 with the Moroccan government with respect to the Boujdour Offshore Block. On September 17, 2010, the Company entered a memorandum of understanding with the

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KOSMOS ENERGY HOLDINGS

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Moroccan government to enter into a new petroleum agreement covering the highest potential areas of the block under essentially the same terms as the original license. The Agreement provides for a tax holiday, at a 0% tax rate, for a period of 10 years beginning on the date of first production from the Boujdour Offshore Block. The Company currently has recorded deferred tax assets of $7.1 million, recorded at the Moroccan statutory rate of 30%, with an offsetting valuation allowance of $7.1 million. When the Company enters into the tax holiday period (when production begins) it will re-evaluate its deferred tax position and at such time may reduce the statutory rate applied to the deferred tax assets in Morocco to the extent those deferred tax assets are realized within the tax holiday period.

The Company’s Ghanaian deferred tax asset was $91.1 million and $77.5 million as of March 31, 2011 and December 31, 2010, respectively. The Company considered the following positive evidence in concluding that its Ghana deferred tax asset as of March 31, 2011 and December 31, 2010 would be recognized in the future:

· The commencement of oil production on November 28, 2010. Equipment and infrastructure was fully in place in the fourth quarter of 2010 immediately prior to production commencing, and the November 2010 successful commencement of production confirmed our expectations that these assets could be utilized to successfully produce from the field with an economical cost structure.

· The recognition of our first revenues from oil production in January 2011. The Company was a development stage entity as of December 31, 2010, but upon recognition of our first revenues in January 2011, is no longer categorized as such.

· The existence of significant proved reserves that have been independently verified.

· The Company produces a commodity (crude oil) with observable market demand capable of purchasing all barrels produced. Prices for oil can be estimated through forward pricing curves.

· The ability to recover our deferred tax assets based on our projections of taxable income for 2011 and future years. Production volumes utilized in our projection are based on our proved reserve estimates, which have been independently verified and our schedule for production which has been approved by the Jubilee Unit partners and, to date, has matched actual production volumes achieved since first oil production commencement on November 28, 2010. Such schedule anticipates that the FPSO producing from the field will reach its maximum production capacity during 2011. Prices have been estimated based on prices utilized to calculate our standardized measure as of December 31, 2010. Additionally, we have estimated our expenses based on current contracts and cost structures in place.

· The excess of appreciated asset value over the tax basis of our Ghanaian net assets of an amount sufficient to realize the deferred tax asset. Our estimates of the excess of the appreciated asset value were based upon the independently verified reserve report, third party offers for our Ghana assets, and other market indicators.

· We tested the sensitivity of our projection of taxable income to changes in production volumes and prices, which indicated that future taxable income was sufficient to recover the deferred tax assets under various scenarios.

· There is an unlimited NOL carryforward period under Ghanaian tax law, which provides flexibility in utilization of the net operating loss.

The Company has no material unrecognized income tax benefits.

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 it operates. The Company is open to U.S. federal income tax examinations for tax years 2007 through 2010, and to foreign income tax examinations for the tax years 2004 through 2010. In addition, the Company is open to Texas tax examinations for the tax years 2006 through 2010.

The Company’s policy is to recognize probable interest and penalties related to income tax matters in income tax expense, but has had no need to accrue any to date.

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KOSMOS ENERGY HOLDINGS

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

15. Commitments and Contingencies

On June 23, 2008, Kosmos Ghana signed an offshore drilling contract with Alpha Offshore Drilling Services Company, a wholly owned subsidiary of Atwood Oceanics, Inc., for the semi-submersible drilling rig “Atwood Hunter.” Noble Energy EG Ltd. (“Noble”) also is a party to the contract. The rated water depth capability of the “Atwood Hunter” is currently 5,000 feet. The initial rig rate was $538 thousand per day and is subject to annual adjustments for cost increases. Effective, July 27, 2009 and 2010, the rig rate was adjusted to $543 thousand per day and $546 thousand per day, respectively. The contract, as amended, is for 1,152 days, with Kosmos Ghana and Noble allotted 797 days and 355 days, respectively. Kosmos Ghana and TGL entered into a rig and services sharing agreement on October 18, 2009, for use of the “Atwood Hunter” across WCTP and DT Blocks during part of Kosmos Ghana’s allocated rig time. The future minimum commitments under this contract as of March 31, 2011, are: 2011—$89.5 million; and 2012—$133.1 million.

16. Subsequent Events

Completion of Initial Public Offering and Corporate Reorganization

Kosmos Energy Ltd. completed its initial public offering on May 16, 2011. Our estimated net proceeds from the sale of 33,000,000 common shares in this offering after underwriting discounts and commissions and offering expenses is approximately $552.9 million. The underwriters have a 30-day option to purchase up to 4,950,000 additional common shares from Kosmos Energy Ltd. at the initial public offering price less underwriting discounts and commissions. If the underwriter’s over-allotment option is exercised in full, we estimate that our net proceeds will be approximately $636.6 million.

Contemporaneous with Kosmos Energy Ltd.’s initial public offering, the holders of the Convertible Preferred Units and common units of Kosmos Energy Holdings, including (i) profit units issued to management and employees in connection with our corporate reorganization, and (ii) all unvested profit units, were exchanged into common shares based on the pre-offering equity value of such interests. This results in the Series A, Series B and Series C Preferred Units and the common units being exchanged into 163,048,228; 109,837,843; 4,811,757; and 63,478,643 common shares of Kosmos Energy Ltd., respectively, or 341,176,471 common shares in the aggregate. The 341,176,471 common shares included 10,109,217 restricted shares issued to management and employees in connection with our corporate reorganization. The common shares have one vote per share and a par value of $0.01. As a result of this corporate reorganization, Kosmos Energy Holdings is now wholly owned by Kosmos Energy Ltd.

Morocco License

In May 2011, the Company entered into a Petroleum Agreement with the Office National des Hydrocarbures et des Mines (ONHYM), the national oil company of Morocco, covering the Foum Assaka area offshore the Kingdom of Morocco. The agreement will become effective when the final approval is obtained from the government of Morocco, expected to be within 60 days. The Company will have a 37.5% participating interest in the agreement, with ONHYM having a 25% participating interest and a private company holding the remaining 37.5% participating interest. ONHYM’s 25% participating interest will be carried through the exploration phase.

Tullow Oil plc Acquisition of EO Group

On May 26, 2011, Tullow Oil plc announced it entered into a conditional agreement to acquire EO Group’s entire interest offshore Ghana; being a 3.5% interest in the WCTP Petroleum Agreement. The agreement is conditional on the receipt of various consents and approvals, including from the Government of Ghana. If the transaction closes, we will receive full repayment of the long-term joint interest billing receivable related to Jubilee Field development costs paid on EO Group’s behalf; and the related allowance of $39.8 million would be reversed.

Restricted Stock Awards Under the Long-term Incentive Plan

Subsequent to the completion of our initial public offering in May 2011, the Company granted 11,028,727 restricted stock awards to management and employees under our long-term incentive plan. The awards will vest ratably over a four year period.

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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, 2010, included in our final prospectus along with the section Management’s Discussion and Analysis of financial condition and Results of Operations contained in such final prospectus. Any terms used but not defined in the following discussion have the same meaning given to them in the final prospectus. 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 final prospectus, along with “Forward-Looking Information” at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are an independent oil and gas exploration and production company focused on underexplored regions in Africa. Our current asset portfolio includes world-class discoveries and partially de-risked exploration prospects offshore the Republic of Ghana, as well as exploration licenses with significant hydrocarbon potential onshore the Republic of Cameroon and offshore the Kingdom of Morocco. This portfolio, assembled by our experienced management and technical teams, provides investors with differentiated access to both high-impact exploration opportunities as well as defined, multi-year visibility in the reserve and production growth of our existing discoveries.

Kosmos Energy Holdings transitioned from its development stage to operational activities in January 2011. Accordingly, reporting as a development stage company is no longer deemed necessary.

First Quarter 2011 Highlights

In March 2011, we executed definitive documentation to replace our previous commercial debt facilities with a new $2.0 billion commercial debt facility, with an additional $1.0 billion of uncommitted capacity accessible upon receiving additional commitments. As of March 31, 2011, the availability under our commercial debt facility was $128.0 million, net of a $23.0 million Letter of Credit secured by our available borrowing capacity, with $700 million of committed undrawn capacity provided for in the Facility (the difference is the result of borrowing base constraints). These funds, along with our estimated net proceeds from our initial public offering, after underwriting discounts and commissions and offering expenses, of $552.9 million, will support our share of the Jubilee Field Phase 1 development, appraisal of additional discoveries and ongoing exploration activities on new and existing licenses.

Ghana — Jubilee Field

In January 2011, we recognized revenues of $92.6 million on our first lifting of 989 Mbbls of oil from our Jubilee Field Phase 1 production. Our average realized price per barrel was $93.56. Our second lifting of 995.7 Mbbls occurred in April 2011.

As of March 31, 2011, a total of 16 development wells had been drilled during Jubilee Field Phase 1 development. The Jubilee Field Phase 1 development plan specifies a total of 17 wells to be drilled. Nine wells are currently on-line, with the remainder of the wells to be completed during 2011.

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One producing well and two water injector wells were placed in service during the first quarter of 2011. In addition, the first of two gas injector wells was placed in service in April 2011. Early performance data support our strategy to maintain reservoir pressure through gas and water injection and is consistent with our production expectations.

Ghana — exploration and appraisal activity

In February 2011, we announced that the Teak-1 exploration well had made a hydrocarbon discovery on the WCTP Block. Results of drilling, wireline logs and reservoir fluid samples show the Teak-1 well penetrated net oil-and-gas-bearing pay of 239 feet (73 meters) in five Campanian and Turonian zones of high-quality stacked reservoir sandstones consisting of 154 feet (47 meters) of gas and gas-condensate and 85 feet (26 meters) of oil. This is the second-highest net pay count encountered by any well on Kosmos’ WCTP or DT Blocks since the company’s Mahogany-1 exploration well discovered the Jubilee Field on the WCTP Block in 2007.

In March 2011, it was announced that the Teak-2 well had successfully encountered hydrocarbons in the Teak 2 fault block on the WCTP Block. Results of drilling, wireline logs and samples of reservoir fluids confirm that the Teak-2 well penetrated net oil and gas-condensate bearing pay of 89 feet (27 meters) in five Campanian and Turonian zones consisting of 62 feet (19 meters) of net gas-condensate pay, 23 feet (7 meters) of net oil pay and 3 feet (1 meter) of undetermined hydrocarbon pay.

In March 2011, we announced that the Enyenra-2A appraisal well had confirmed a downdip extension of the Enyenra Field which was discovered by the Owo-1 exploration well drilled on the DT Block. The Enyenra-2A well, located more than 4 miles (7 kilometers) to the south of the Owo-1 well, encountered oil and gas-condensate in high-quality stacked sandstone reservoirs. Results of drilling, wireline logs, reservoir fluid samples and pressure data show that the Enyenra-2A well intersected 69 feet (21 meters) of oil in the upper channel and 36 feet (11 meters) of oil in the lower channel. The Enyenra-2A well also tested a portion of a deeper reservoir where 16 feet (5 meters) of gas-condensate sandstones were intersected suggesting the existence of hydrocarbons in the Tweneboa Deep prospect.

In January 2011 and April 2011, respectively, the Tweneboa-3 and Tweneboa-4 appraisal wells in the DT Block successfully confirmed the Greater Tweneboa Area’s resource base potential. The Greater Tweneboa Area comprises the Tweneboa-1 and Tweneboa-2 oil and gas-condensate fields and the neighboring Enyenra light oil field (formerly known as the Owo Field). The results of drilling, wireline logs and reservoir fluid samples show the Tweneboa-3 appraisal well encountered approximately 29 feet (9 meters) of gas-condensate pay before the well was sidetracked. The sidetrack encountered approximately 112 feet (34 meters) of net gas-condensate pay in high-quality stacked reservoir sandstones in two zones. The Tweneboa-4 appraisal well, which was in process of drilling as of March 31, 2011, encountered approximately 59 feet (18 meters) of net gas-condensate pay in high-quality stacked reservoir sandstones.

In June 2011, we announced that the Banda-1 exploration well had made a hydrocarbon discovery on the WCTP Block. Results of drilling, wireline logs and reservoir fluid samples show the Banda-1 well penetrated net oil-bearing pay of 3 meters (10 feet).

Cameroon

The N’gata exploration well was spud on March 5, 2011. This exploration well is expected to reach its final target by July 2011.

Morocco

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Results of Operations

Certain of our operating results and statistics for the comparative first quarters of 2011 and 2010 are included in the following table:

	Three Months Ended March 31,
(In thousands, except per barrel data)	2011		2010
Production volumes:
Mbbls	989		—

Revenues:
Oil sales	$	92,569	$	—
Average sales price per bbl	93.56		—

Costs:
Oil production	$	19,995	$	—
Depletion	22,385		—
Average oil production cost per bbl	20.21		—
Average depletion cost per bbl	22.62		—
Average oil production cost and depletion per bbl	42.83		—

The following table shows the number of wells in the process of drilling or in active completion stages, and the number of wells suspended or awaiting completion as of March 31, 2011:

	Wells in the Process of Drilling or				Wells Suspended or
	in Active Completion				Awaiting Completion
	Exploration		Development		Exploration		Development
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Ghana
West Cape Three Points	1	0.31	—	—	7	2.16	4	0.94
Deepwater Tano	1	0.18	1	0.23	5	0.90	3	0.70
Cameroon
Kombe-N’sepe	1	0.35	—	—	—	—	—	—

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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 March 31, 2011 vs. March 31, 2010

	Three Months Ended March 31,						Increase
	2011			2010			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	92,569		$	—		$	92,569
Interest income	2,354			1,167			1,187
Other income	487			1,276			(789		)
Total revenues and other income	95,410			2,443			92,967
Costs and expenses:
Oil and gas production	19,995			—			19,995
Exploration expenses, including dry holes	8,432			26,179			(17,747		)
General and administrative	13,287			10,930			2,357
Depletion and depreciation	23,498			512			22,986
Amortization—debt issue costs	9,611			5,925			3,686
Interest expense	20,258			11,018			9,240
Derivatives, net	8,871			12,929			(4,058		)
Loss on extinguishment of debt	59,643			—			59,643
Other expenses, net	(23		)	(71		)	48
Total costs and expenses	163,572			67,422			96,150
Loss before income taxes	(68,162		)	(64,979		)	(3,183		)
Income tax expense (benefit)	(13,511		)	227			(13,738		)
Net loss	$	(54,651	)	$	(65,206	)	$	10,555

Oil and gas revenue. During the three months ended March 31, 2011, we recorded oil and gas revenue of $92.6 million due to our first lifting of oil from our Jubilee Field Phase 1 production. We lifted and sold approximately 989 Mbbls at an average realized price per barrel of $93.56.

Oil and gas production. During the three months ended March 31, 2011, we recorded oil and gas production costs of $20.0 million due to our first lifting of oil from our Jubilee Field Phase 1 production. Our average production cost per barrel was $20.21.

Exploration expenses. Exploration expenses decreased $17.7 million during the three months ended March 31, 2011, as compared with the three months ended March 31, 2010. During the three months ended March 31, 2011, we incurred $4.1 million for seismic costs for Ghana and $2.8 million of additional unsuccessful well costs related to the Cameroon Mombe-1 well. During the three months ended March 31, 2010, the Company incurred $22.0 million of unsuccessful well costs related to the Ghana Dahoma-1 well and $3.9 million for seismic costs for Cameroon and Ghana.

General and administrative. General and administrative costs increased $2.4 million during the three months ended March 31, 2011, as compared with the three months ended March 31, 2010, due to increases in professional fees and expenses and travel expenses, partially offset by increases in capitalized technical service fees.

Depletion and depreciation. Depletion and depreciation increased $23.0 million during the three months ended March 31, 2011, as compared with the three months ended March 31, 2010, due to the first lifting of oil from our Jubilee Field Phase 1 production.

Amortization—debt issue costs and Loss on extinguishment of debt. During the three months ended March 31, 2011, we incurred approximately $52.3 million of debt issue costs as part of the acquisition of the Facility, in addition to our

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existing unamortized debt issue costs of $68.6 million. As a result of the debt refinance, we recorded a $59.6 million loss on the extinguishment of debt. The remaining costs were capitalized and will be amortized over the term of the Facility. The related amortization of debt issue costs increased by $3.7 million during the three months ended March 31, 2011, as compared to the three months ended March 31, 2010, due to the amortization of the fees that were capitalized in connection with the amendment of our previous commercial debt facilities in August 2010 and additional draws on those debt facilities during 2010.

Interest expense. Interest expense increased $9.2 million during the three months ended March 31, 2011, as compared with the three months ended March 31, 2010, primarily due to higher average outstanding debt during the three months ended March 31, 2011.

Derivatives, net. Derivatives, net decreased $4.1 million during the three months ended March 31, 2011, as compared with March 31, 2010 due to the unrealized change in fair value of the commodity derivative instruments.

Income tax expense (benefit). We had an income tax benefit of $13.5 million during the three months ended March 31, 2011, as compared to an income tax expense of $0.2 million for the three months ended March 31, 2010, due to the release of the Ghana valuation allowance at December 31, 2010. This release was warranted as it was determined it is more likely than not that Kosmos Ghana will utilize its net deferred tax asset due to the commencement of oil production in November 2010 and future projected taxable income to be generated from oil sales.

Liquidity and Capital Resources

As we have, until recently, been a development stage entity, we are actively engaged in an ongoing process to anticipate and meet our funding requirements related to exploring for and developing oil and natural gas resources in Africa. We have historically secured funding from equity commitments and commercial debt facilities to meet our ongoing liquidity requirements. In addition, we received our first oil revenues in January 2011 from Jubilee Field Phase 1 production. Accordingly, the cash generated from our operating activities will provide an additional source of future funding. We believe that our available cash, together with the net proceeds from our initial public offering and borrowings under our commercial debt facilities, will be sufficient to meet our operating needs, service our existing debt, finance internal growth and fund capital expenditures through 2013.

Significant Sources of Capital

In March 2011, the Company secured a commercial debt facility from a number of financial institutions for up to $2.0 billion. The funds will be used to support our oil and gas exploration, appraisal and development program and corporate activities and to refinance existing debt facilities. The loan commitment may be increased up to a maximum of $3.0 billion if the lenders increase their loan commitments or if loan commitments of new financial institutions are added. The existing debt facilities were repaid and terminated in connection with the closing of the Facility in March 2011.

The interest is the aggregate of the applicable margin (3.25% to 4.75%, depending on the amount of the Facility that is being utilized and the length of time that has passed from the date the Facility was entered into); LIBOR; and mandatory cost (if any, as defined in the Facility). Interest on each loan is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). Kosmos pays commitment fees on the undrawn and unavailable portion of the total commitments. Commitment fees for the lenders are equal to 40% per annum of the then-applicable respective margin when a commitment is available for utilization, and equal to 20% per annum of the then-applicable respective margin when a commitment is not available for utilization.

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Kosmos has the right to cancel all the undrawn commitments under the Facility. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined each year on June 15 and December 15 as part of a forecast that is prepared by and agreed on by Kosmos and the Technical and Modeling Banks. The formula to calculate the borrowing base amount is based, in part, on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages. As of March 31, 2011, borrowings against the Facility totaled $1.3 billion. As of March 31, 2011, the undrawn availability under the Facility was an additional $128.0 million, net of a $23.0 million Letter of Credit related to the drilling contract for the Eirik Raude Rig (see Note 2 — Accounting Policies), which is secured by our available borrowing capacity. Total committed undrawn capacity provided for in the Facility is $700 million, which will be available to Kosmos should the borrowing base increase.

As of March 31, 2011, we were in compliance with the financial covenants contained in the Facility, which requires the maintenance of:

· the field life cover ratio, not less than 1.30x; and

· the loan life cover ratio, not less than 1.10x,

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 current exploration and appraisal drilling program through 2011 in our offshore Ghana licenses;

· drill one exploration well in Cameroon;

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

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

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

Oil production from the Jubilee Field commenced on November 28, 2010, and we received our first oil revenues of $92.6 million in January 2011. We expect gross oil production from the Jubilee Field to reach the design capacity of the FPSO facility into which oil from the field is being produced. We expect the production rate to reach 120,000 bopd (28,200 bopd net to Kosmos) during 2011.

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 working 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 or development efforts more rapidly than we presently

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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.

Furthermore, if MODEC, the contractor for the FPSO we are using to produce hydrocarbons from the Jubilee Field, is unable to secure long-term financing for the cost of this FPSO in order to repay amounts originally loaned by us and certain other Jubilee Unit partners under an Advance Payments Agreement (of which we are not a signatory, as TGL entered into such agreement as Unit Operator of the Jubilee Unit) and a construction loan from third parties for the financing of the construction of this FPSO, the Jubilee Unit partners may need to directly purchase the FPSO or find an alternative funding source or buyer. MODEC is required to repay amounts advanced on the earlier of September 15, 2011 or the date of the first drawdown under MODEC’s long-term financing. Based on the terms of the joint operating agreement for the Jubilee Unit, TGL is required to reimburse us the amounts MODEC reimburses to TGL within 10 business days of repayment by MODEC. The Advance Payments Agreement grants to the Jubilee Unit partners the option to purchase the FPSO from MODEC on or before that same date at a discount to the FPSO’s market value. We have a letter agreement with certain of our partners in which they agree that should they be required to purchase the vessel they will use all reasonable endeavors to lease it back to the Jubilee Unit partners on similar terms to the current lease governing the use of the vessel. Should we elect to participate in any purchase of the vessel, our share of the remaining balance of cost to make such purchase is an amount up to approximately $120.0 million.

We estimate we will incur approximately $500.0 million of capital expenditures for the year ending December 31, 2011. This capital expenditure budget consists of:

· $175.0 million for development in Ghana;

· $225.0 million for exploration and appraisal in Ghana;

· $30.0 million for exploration and appraisal in Cameroon;

· $30.0 million for new ventures to expand our license portfolio (including geological and geophysical expenses); and

· $40.0 million in unallocated funds that are available for additional drilling and licensing costs and activities.

The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our drilling results. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil and natural gas and the prices we receive from the sale of these commodities, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, and the actual cost of exploration, appraisal and development of our oil and natural gas assets.

The following table presents our liquidity and financial position as of March 31, 2011 and June 1, 2011:

(In thousands)	March 31, 2011		June 1, 2011

Cash	$	290,704	887,549
Drawings under the commercial debt facility	1,300,000		1,300,000
Net Debt	1,009,296		412,451

Total of unused borrowing base (1)	128,000		128,000
Unused borrowing base plus cash	418,704		1,015,549

(1) Net of a Letter of Credit for $23.0 million which is secured by our available borrowing capacity at March 31, 2011 and at June 1, 2011.

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Cash Flows

	Three Months Ended March 31,
	2011			2010
	(In thousands)
Net cash provided by (used in):
Operating activities	$	(10,037	)	$	(101,026	)
Investing activities	(2,346		)	(246,272		)
Financing activities	202,672			440,021

Operating activities. Net cash used in operating activities for the three months ended March 31, 2011 was $10.0 million compared with net cash used in operating activities for the three months ended March 31, 2010 of $101.0 million. The decrease in cash used in the three months ended March 31, 2011 compared with the same period in 2010 was primarily due to our first lifting of oil from the Jubilee Field Phase 1 production and working capital changes.

Investing activities. Net cash used in investing activities for the three months ended March 31, 2011 was $2.3 million compared with net cash used in investing activities for the three months ended March 31, 2010 of $246.3 million. The decrease in cash used in the three months ended March 31, 2011 compared with the same period in 2010 was primarily attributable to changes in restricted cash. During the three months ended March 31, 2010, we set aside $110.4 million of restricted cash to primarily support our drilling activities. During the three months ended March 31, 2011, we released $112.0 million of the restricted cash.

Financing activities. Net cash provided by financing activities for the three months ended March 31, 2011 was $202.7 million compared with net cash provided by financing activities for the three months ended March 31, 2010 of $440.0 million. The decrease in cash provided in the three months ended March 31, 2011 compared with the same period in 2010 was due to lower net borrowings of $185.0 million on the commercial bank facilities and a $52.3 million increase in cash used for debt issue costs.

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of March 31, 2011:

	Payments Due By Year(3)
	Total		2011(4)		2012		2013		2014		2015		Thereafter
	(In thousands)
Drilling rig contract(1)	$	222,613	$	89,482	$	133,131	$	—	$	—	$	—	$	—
Operating leases	6,060		1,214		1,636		1,660		1,168		382		—
Commercial debt facility(2)	1,300,000		—		—		—		—		300,000		1,000,000
Interest payments on commercial debt facility	517,121		40,750		63,957		80,552		98,318		104,242		129,302

(1)		Does not include any well commitments we may have under our oil and natural gas licenses.
(2)		The amounts included in the table above represent principal maturities only. The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of March 31, 2011. 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.
(3)		Does not include purchase commitments for jointly owned fields and facilities where we are not the operator.
(4)		Represents payments for the period April 1, 2011 through December 31, 2011.

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The following table presents maturities by expected maturity dates under the commercial debt facility, the weighted average interest rates expected to be paid on the commercial debt 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 debt issue costs.

	Year Ending December 31,																		Asset
	April 1 Through December 31, 2011			2012			2013			2014			2015			Thereafter			(Liability) Fair Value at March 31, 2011
	(In thousands, except percentages)
Variable rate debt:
Commercial debt facility maturities	$	—		$	—		$	—		$	—		$	300,000		$	1,000,000		$	(1,300,000	)
Weighted average interest rate	4.18		%	4.92		%	6.20		%	7.56		%	8.27		%	9.40		%
Interest rate swaps
Notional debt amount(1)	$	161,250		$	138,073		$	91,683		$	47,033		$	16,875		$	6,250		$	(3,326	)
Fixed rate payable	2.22		%	2.22		%	2.22		%	2.22		%	2.22		%	2.22		%
Variable rate receivable(2)	0.48		%	1.03		%	2.33		%	3.36		%	4.18		%	4.68		%
Notional debt amount(1)	$	161,250		$	138,073		$	91,683		$	47,033		$	16,875		$	6,250		$	(3,722	)
Fixed rate payable	2.31		%	2.31		%	2.31		%	2.31		%	2.31		%	2.31		%
Variable rate receivable(2)	0.48		%	1.03		%	2.33		%	3.36		%	4.18		%	4.68		%
Notional debt amount(1)	$	77,500		$	63,625		$	19,057		$	1,868		$	—		$	—		$	8
Fixed rate payable	0.98		%	0.98		%	0.98		%	0.98		%
Variable rate receivable(2)	0.48		%	1.03		%	2.33		%	3.14		%
Notional debt amount(1)	$	75,004		$	50,942		$	24,680		$	38,434		$	23,137		$	—		$	475
Fixed rate payable	1.34		%	1.34		%	1.34		%	1.34		%	1.34		%
Variable rate receivable(2)	0.48		%	1.03		%	2.33		%	3.36		%	4.00		%

(1) Represents weighted average notional contract amounts of interest rate derivatives.

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

Off-Balance Sheet Arrangements

As of March 31, 2011, we did not have any off-balance sheet arrangements.

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. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations in our final prospectus, which summarizes these accounting policies. Additionally, our accounting policy for income taxes is discussed below.

Income Taxes. We account for income taxes as required by the FASB ASC 740—Income Taxes. We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal, state and international tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to realize or utilize our deferred tax assets. If realization is not more likely than not, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in no benefit for the deferred tax amounts. As of December 31, 2010, we

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have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. If our estimates and judgments regarding our ability to realize our deferred tax assets change, the benefits associated with those deferred tax assets may increase or decrease in the period our estimates and judgments change.

Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.

The Company had net deferred tax assets in Ghana totaling approximately $91.1 million and $77.5 million at March 31, 2011 and December 31, 2010, respectively. Prior to the commencement of production from the Jubilee Field on November 28, 2010, the Company maintained a full valuation allowance against its net deferred tax asset. However, at December 31, 2010, the Company determined that it was more likely than not that the deferred tax asset for its Ghana operations would be recognized, resulting in the valuation allowance no longer being necessary. Therefore, we released the $20.6 million deferred tax asset valuation allowance and recognized $56.9 million of deferred tax assets generated during 2010. The factors that the Company considered are discussed below. Based on these factors, the Company concluded that many of the considerations that previously led to the need for a valuation allowance related to the Ghana deferred tax assets was not required as of December 31, 2010.

In determining that a valuation allowance was not needed for the Ghanaian deferred tax assets at December 31, 2010 we considered the requirements of ASC 740, including that all evidence, both positive and negative, should be considered to determine whether, based on all the weight of the available evidence, it is more-likely-than-not a deferred tax asset will or will not be realized. If it is more-likely-than-not that the deferred tax asset will be realized, a valuation allowance is not needed. In performing this assessment for the Ghanaian deferred tax assets, the Company determined that the factors that led to the creation of deferred tax assets while operating as a development stage entity changed significantly when the Company moved into the production phase. Accordingly, the Company believes that, considering the facts and circumstances, the negative evidence of the cumulative losses incurred during the development stage is overcome by the following positive evidence relating to the Company’s ability to more-likely-than-not realize the deferred tax assets in Ghana:

· The existence of significant proved reserves that have been independently verified.

· The Company produces a commodity (crude oil) with observable market demand capable of purchasing all barrels produced. Prices for oil can be estimated through forward pricing curves.

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Our projection of taxable income is based on a per barrel price of $79.35, which is also used to calculate our standardized measure, and our production forecast, which is based on our proved reserve estimates and our schedule for production. Based on this projection, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2012. Assuming a 25% decrease in prices or volumes, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2013. Assuming a 25% decrease in prices and volumes, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2015. Assuming a decrease in the price of oil to $50 per barrel and no change in anticipated production volumes, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2015. A $50 per barrel price represents an average price per barrel lower than the average price during 2008 and 2009 when oil prices sustained substantial price declines and a 57% decrease from the Dated Brent price of $116.95 per barrel on March 31, 2011. Conversely, assuming a 25% increase in prices (or $99.19 per barrel which would still be less than the $116.95 per barrel price of Dated Brent on March 31, 2011, the date of our financial statements for the three months ended March 31, 2011 included herein) and no change in volume, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2011.

· There is an unlimited net operating loss carryforward period under Ghanaian tax law, which provides flexibility in utilization of the net operating loss.

ASC 740 provides a more-likely-than-not standard in evaluating whether a valuation allowance is necessary after weighing all of the available evidence. Using the more-likely-than-not standard and weighing all available positive and negative evidence, the Company concluded that the positive evidence outweighs the negative evidence of cumulative losses incurred during the development stage. Accordingly, we determined that it is more likely than not that the deferred tax asset for our Ghanaian operations would be recognized as of March 31, 2011 and December 31, 2010.

Effective January 1, 2009, we adopted the provisions of the FASB ASC 740—Income Taxes which clarifies the accounting for and disclosure of uncertainty in tax positions. Additionally, this standard provides guidance on the recognition, measurement, derecognition, classification and disclosure of tax positions and on the accounting for related interest and penalties. As a result of this adoption, we recognize accrued interest and penalties related to unrecognized tax benefits as a component of income tax expense.

Cautionary Note Regarding Forward-looking Statements

This Quarterly Report on Form 10-Q contains estimates and forward-looking statements, principally in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our estimates and forward-looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in our final prospectus, may adversely affect our results as indicated in forward-looking statements. You should read this Quarterly Report on Form 10-Q, the final prospectus 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;

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· termination of or intervention in concessions, rights or authorizations granted by the Ghanaian, Cameroon or Moroccan governments or national oil companies, or any other federal, state or local governments, 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 the terms under which such financing may be available;

· the volatility of oil and natural gas prices;

· the availability and cost 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 and processing problems;

· military operations, terrorist acts, wars or embargoes;

· the cost and availability of adequate insurance coverage;

· our vulnerability to severe weather events; and

· other risk factors discussed in the “Risk Factors” section of the final prospectus.

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. Quantitative and Qualitative 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 they are indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage ongoing market risk exposures. We enter into market-risk sensitive instruments for purposes other than speculation.

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The following table reconciles the changes that occurred in fair values of our open derivative contracts during the three months ending March 31, 2011:

	Derivative Contracts Assets (Liabilities)
	Commodities			Interest Rates			Total
	(In thousands)
Fair value of contracts outstanding as of December 31, 2010	$	(28,319	)	$	(5,638	)	$	(33,957	)
Changes in contract fair value	(8,871		)	(2,652		)	(11,523		)
Contract maturities (settlements)	—			1,725			1,725
Fair value of contracts outstanding as of March 31, 2011	$	(37,190	)	$	(6,565	)	$	(43,755	)

Commodity Derivative Instruments

In 2010, we entered into various oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production. These contracts consisted of deferred premium puts and compound options (calls on puts).

We manage and control market and counterparty credit risk in accordance with policies and guidelines approved by the Kosmos Board of Directors. In accordance with these policies and guidelines, our executive management determines the appropriate timing and extent of derivative transactions. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification. See Note 10—Derivative Financial Instruments in our consolidated financial statements for a description of the accounting procedures we follow relative to our derivative financial instruments.

Commodity Price Sensitivity

The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of March 31, 2011:

	Bbl/day	Weighted Average Floor Price		Weighted Average Deferred Premium/bbl		Liability Fair Value at March 31, 2011
Oil derivatives:
Deferred premium puts
July 2011 – December 2011	11,332	$	72.01	$	8.90
January 2012 – December 2012	4,625	$	62.74	$	7.04
January 2013 – December 2013	2,515	$	61.73	$	7.32
Total fair value deferred premium puts(1)						$	31,160
Compound options (calls on puts)(2)
July 2010 – December 2012	5,399	$	66.48	$	6.73
January 2013 – June 2013	3,855	$	66.48	$	7.10
Total fair value compound options(1)						$	6,030

(1)		Fair values are based on the average forward Dated Brent oil prices on March 31, 2011 which by year are: 2011 - $116.03; 2012 - $112.34 and 2013 - $108.52. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on June 1, 2011 market quotes by year are: 2011- $113.15; 2012 - $110.65 and 2013 - $107.24.
(2)		The calls expire June 29, 2012 and have a weighted average premium of $4.82/bbl.

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Interest Rate Sensitivity

At March 31, 2011, we had indebtedness outstanding under our commercial debt facility of $1.3 billion, of which $825.0 million bore interest at floating rates. The weighted average annual interest rate incurred on this indebtedness for the three months ended March 31, 2011, was approximately 7.1%. If LIBOR increased 10% at this level of floating rate debt, we would incur an additional $0.2 million of interest expense per year on our commercial debt facility.

As of March 31, 2011, the fair market value of our interest rate swaps was a net liability of approximately $6.6 million. If LIBOR increased 10%, we estimate the liability would decrease to approximately $5.0 million, and if LIBOR decreased 10%, we estimate the liability would increase to approximately $8.2 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. Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2011, to provide reasonable assurance that the information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities Exchange Commission’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate 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 during the quarter ended March 31, 2011 that have 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

We are not currently party to any litigation or legal proceedings with respect to the Company’s operations that management believes, based on advice of legal counsel, will either individually or in the aggregate have a materially adverse impact on the Company’s financial condition, results of operations or cash flows. However, from time to time we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, environmental, safety and health matters. It is not presently possible to determine whether any such matters will have a material adverse effect on our consolidated financial position, results of operations, or liquidity.

Item 1A. Risk Factors

There have been no material changes from the risk factors previously disclosed in the final prospectus other than as follows:

We will not have a license for the Foum Assaka Offshore Block offshore Morocco and we will not be able to commence our exploration, development and production operations on this block until the Foum Assaka Petroleum Agreement governing our interests in such block is successfully negotiated and executed.

On May 4, 2011, we entered into the Foum Assaka Petroleum Agreement with Pathfinder Hydrocarbon Ventures Limited and ONHYM. We are currently negotiating definitive agreements, including the final Foum Assaka Petroleum Agreement, which will govern the exploration, development and production operations on the Foum Assaka Offshore Block, with the Moroccan Minister for Energy and the Minister of Finance. Our Foum Assaka Offshore Block award will not be final and we will not have a license for the Foum Assaka Offshore Block unless and until this Petroleum Agreement is successfully negotiated and executed by the Moroccan Minister for Energy and the Minister of Finance. As certain terms of Foum Assaka Offshore Block award have not been finalized, there is a risk that the Foum Assaka Petroleum Agreement will not be executed and that we may be unable to enforce any contractual rights we have in the Foum Assaka Offshore Block and we will not be able to commence our exploration, development and production operations on the Foum Assaka Offshore Block. Further, if the Foum Assaka Offshore Petroleum Agreement is executed later than we expect, our planned 2011 activities offshore Morocco could be delayed.

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

Our initial public offering of common shares was effected through a Registration Statement on Form S-1 (File No. 333-171700) that was declared effective by the SEC on May 10, 2011, which (combined with the Registration Statement on Form S-1 (File No. 333-174116)) registered an aggregate of 37,950,000 of our common shares. 33,000,000 of the common shares registered were sold at a price to the public of $18.00 per share. The offering closed on May 16, 2011. The underwriters have an over-allotment option to purchase 4,950,000 additional common shares within 30 days of May 10, 2011.

Net proceeds of the offering (assuming the underwriters do not exercise their over-allotment option) received are expected to be approximately $552.9 million, after deducting underwriting discounts and commissions and estimated offering expenses (yet to be finally determined).

There has been no material change in our planned use of proceeds from the initial public offering from that described in our final prospectus dated May 10, 2011 and filed with the Securities and Exchange Commission pursuant to Rule 424(b).

Item 3. Defaults Upon Senior Securities

None.

Item 4. (Removed and Reserved)

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Item 5. Other Information.

There have been no material changes required to be reported under this Item that have not previously been disclosed in the final prospectus.

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 Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereto duly authorized.

		Kosmos Energy Ltd.
		(Registrant)

Date	June 6, 2011	/s/ W. GREG DUNLEVY
		W. Greg Dunlevy
		Chief Financial Officer and Executive Vice President (Principal Financial Officer)

Table of Contents

INDEX OF EXHIBITS

Exhibit Number		Description of Document
31.1*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.