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As filed with the Securities and Exchange Commission on April 25, 2011

Registration No. 333-171700

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 6
to
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Kosmos Energy Ltd.
(Exact name of registrant as specified in its charter)
 	 	 	 	 	
Bermuda
(State or other jurisdiction of
Incorporation or organization)	 	1311
(Primary Standard Industrial
Classification Code Number)	 	98-0686001
(I.R.S. Employer
Identification Number)	
Clarendon House
2 Church Street
Hamilton HM 11, Bermuda
(441) 295-5950
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Brian F. Maxted, Chief Executive Officer
c/o Kosmos Energy, LLC
8176 Park Lane, Suite 500
Dallas, TX 75231
(214) 445-9600
(Name, address, including zip code, and telephone number, including area code, of agent for service)
 	 	 	
Copies to:	

Richard D. Truesdell, Jr., Esq.
Davis Polk & Wardwell LLP
450 Lexington Avenue
New York, NY 10017
(212) 450-4000	
 	
David J. Beveridge, Esq.
Shearman & Sterling LLP
599 Lexington Avenue
New York, NY 10022
(212) 848-4000	
Approximate date of commencement of proposed sale to the public:
As soon as practicable after the effective date of this registration statement.

          If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.     o

          If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     o

          If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     o

          If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     o

          Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
 	 	 	 	 	 	 	
Large accelerated filer o	 	Accelerated filer o	 	Non-accelerated filer ý
(Do not check if a
smaller reporting company)	 	Smaller reporting company o	
CALCULATION OF REGISTRATION FEE

 	
Title of each Class of
Security being registered
	 	Amount to be
Registered(1)
	 	Proposed Maximum
Offering Price
Per Share
	 	Proposed Maximum
Aggregate Offering
Price(2)
	 	Amount of
Registration Fee(3)

Common Shares, $0.01 par value per share	 	34,500,000	 	$18.00	 	$621,000,000.00	 	$72,098.10	
 	
(1)
Includes 4,500,000 common shares which may be issued on exercise of a 30-day option granted to the underwriters to cover over-allotments, if any.

(2)
Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(a) under the Securities Act of 1933, as amended.

(3)
A registration fee of $72,098.10 was paid previously based on an estimate of the aggregate offering price.

          The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting offers to buy these securities in any state where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED APRIL 25, 2011

30,000,000 Shares

Kosmos Energy Ltd.

Common Shares

        This is an initial public offering of common shares of Kosmos Energy Ltd. Prior to this offering, there has been no public market for our common shares. The initial public offering price of the common shares is expected to be between $16.00 and $18.00 per share. Our common shares have been approved for listing on the New York Stock Exchange under the symbol "KOS."

        The underwriters have an option to purchase a maximum of 4,500,000 additional common shares from us to cover over-allotments of common shares. The underwriters can exercise this option at any time within 30 days from the date of this prospectus.

        Investing in our common shares involves risks. See "Risk Factors" on page 17.

 	
 
	 	Price to Public
	 	Underwriting
Discounts and
Commissions
	 	Proceeds
to Us

Per Common Share	 	$	 	 	$	 	 	$	 	
 	
Total	 	$	 	 	$	 	 	$	 	
 	
        Delivery of the common shares will be made on or about                    , 2011.

        Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

        Consent under the Exchange Control Act 1972 (and its related regulations) has been obtained from the Bermuda Monetary Authority for the issue and transfer of the common shares to persons resident and non-resident of Bermuda for exchange control purposes provided our common shares remain listed on an appointed stock exchange, which includes the New York Stock Exchange. This prospectus will be filed with the Registrar of Companies in Bermuda in accordance with Bermuda law. In granting such consent and in accepting this prospectus for filing, neither the Bermuda Monetary Authority nor the Registrar of Companies in Bermuda accepts any responsibility for our financial soundness or the correctness of any of the statements made or opinions expressed in this prospectus.

Joint Bookrunning Managers
 	 	 	 	 	
Citi (Global Coordinator)	 	Barclays Capital (Global Coordinator)	 	Credit Suisse	
Joint Lead Managers
 	 	 	 	 	
BNP PARIBAS	 	 	 	SOCIETE GENERALE	
Co-Managers
 	 	 	 	 	 	 	 	 	 	 	
Credit Agricole CIB	
 	 	Howard Weil Incorporated	
 	 	 	 	HSBC	
 	 	 	 	 	 	Jefferies	
 	 	 	 	 	 	 	 	Natixis	
RBC Capital Markets
	
The date of this prospectus is                    , 2011.

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TABLE OF CONTENTS

	 	Page	
PROSPECTUS SUMMARY	 	1	
RISK FACTORS	 	17	
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS	 	46	
DIVIDEND POLICY	 	48	
USE OF PROCEEDS	 	49	
CORPORATE REORGANIZATION	 	50	
CAPITALIZATION	 	51	
DILUTION	 	53	
SELECTED HISTORICAL AND PRO FORMA FINANCIAL INFORMATION	 	54	
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	 	57	
INDUSTRY	 	76	
BUSINESS	 	84	
MANAGEMENT	 	125	
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	 	148	
PRINCIPAL SHAREHOLDERS	 	149	
DESCRIPTION OF SHARE CAPITAL	 	152	
SHARES ELIGIBLE FOR FUTURE SALE	 	158	
CERTAIN TAX CONSIDERATIONS	 	160	
UNDERWRITING	 	163	
LEGAL MATTERS	 	171	
EXPERTS	 	171	
WHERE YOU CAN FIND ADDITIONAL INFORMATION	 	171	
GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS	 	172	
INDEX TO FINANCIAL STATEMENTS	 	F-1	

        We have not authorized anyone to provide any information other than that contained in this document or in any free writing prospectus prepared by or on behalf of us or to which we have referred you. We take no responsibility for, and can provide no assurance as to the reliability of, any other information which others may give you. This document may only be used where it is legal to sell securities. The information in this document may only be accurate on the date of this document.
Dealer Prospectus Delivery Obligation

        Until                    , 2011, all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer's obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

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PROSPECTUS SUMMARY

        This summary highlights certain information appearing elsewhere in this prospectus. As this is a summary, it does not contain all of the information that you should consider in making an investment decision. You should read the entire prospectus carefully, including the information under "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the related notes included in this prospectus, before investing. Unless otherwise stated in this prospectus, references to "Kosmos," "we," "us" or "our company" refer to Kosmos Energy Holdings and its subsidiaries prior to the completion of our corporate reorganization, and Kosmos Energy Ltd. and its subsidiaries as of the completion of our corporate reorganization and thereafter. Although we believe that the estimates and projections included in this prospectus are based on reasonable assumptions, investors should be aware that these estimates and projections are subject to many risks and uncertainties as described in "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements." Unless we tell you otherwise, the information in this prospectus assumes that the underwriters will not exercise their over-allotment option. We have provided definitions for some of the industry terms used in this prospectus in the "Glossary of Selected Oil and Natural Gas Terms" beginning on page 172.

Overview

        We are an independent oil and gas exploration and production company focused on under-explored 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 from the Kingdom of Morocco. This portfolio, assembled by our experienced management and technical teams, will provide investors with differentiated access to both attractive exploration opportunities as well as defined, multi-year visibility in the reserve and production growth of our existing discoveries.

        Following our formation in 2003, we acquired our current exploration licenses and established a new, major oil province in West Africa with the discovery of the Jubilee Field in 2007. This was the first of our seven discoveries offshore Ghana; it was one of the largest oil discoveries worldwide in 2007 and the largest find offshore West Africa in the last decade. Oil production from the Jubilee Field offshore Ghana commenced on November 28, 2010, and we received our first oil revenues in early 2011. We expect gross oil production from the Jubilee Field to reach the design capacity of the floating, production, storage and offloading ("FPSO") facility used to produce from the field of 120,000 barrels of oil per day ("bopd") in the third quarter of 2011. At that rate, the share of this gross oil production net to us is expected to be 28,200 bopd.

        Since our inception, over two-thirds of our exploration and appraisal wells have encountered hydrocarbons in quantities that we believe will ultimately be commercially viable. These successes, all of which are offshore Ghana, include the Jubilee Field, Mahogany East (which includes the Mahogany Deep discovery) and five other discoveries in the appraisal and pre-development stage: Odum, Tweneboa, Enyenra (formerly known as Owo), Teak and Tweneboa Deep. To date we have identified 47 undrilled prospects within our existing license areas, including 18 prospects across three play types offshore Ghana, 10 prospects across three play types in Cameroon and 19 prospects across three play

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types offshore Morocco. The following table summarizes our existing licenses and their current development status.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
License	 	Gross
Acreage	 	Location	 	Discovered
Fields
(Year of Discovery)	 	Wells
Drilled
(Successful/
Total)	 	Number of
Additional
Prospects
Identified	 	Kosmos
Working
Interest	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
West Cape Three Points ("WCTP")(1)	 	 	369,917	 	Gulf of Guinea's	 	Jubilee (2007)(3)	 	 	16/17	 	 	12	 	30.875%(4)	
 	 	 	 	 	 	Tano Basin	 	Odum (2008)	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Mahogany East (2009)	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Teak (2011)	 	 	 	 	 	 	 	 	
Deepwater Tano ("DT")	 	 	
205,345	 	Gulf of Guinea's	 	Jubilee (2007)(3)	 	 	
14/15	 	 	
6	 	
18.000%(5)	
 	 	 	 	 	Tano Basin	 	Tweneboa (2009)	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Enyenra (2010)	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Tweneboa Deep (2011)	 	 	 	 	 	 	 	 	
Cameroon	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Kombe-N'sepe	 	 	747,741	 	Coastal strip of	 	—	 	 	0/1	 	 	6	 	35.000%(6)	
 	 	 	 	 	Douala Basin	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	bordering the Gulf	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	of Guinea	 	 	 	 	 	 	 	 	 	 	
Ndian River(1)	 	 	
434,163	 	Coastal strip of	 	—	 	 	
—	 	 	
4	 	
100.000%(7)	
 	 	 	 	 	Rio del Rey Basin	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	bordering the Gulf	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	of Guinea	 	 	 	 	 	 	 	 	 	 	
Morocco	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Boujdour Offshore(1)	 	 	10,869,654	(2)	Northwest Africa's	 	—	 	 	—	 	 	19	 	75.000%(8)	
 	 	 	 	 	Aaiun Basin	 	 	 	 	 	 	 	 	 	 	

(1)
Kosmos is the operator under these licenses.

(2)
This reflects the acreage covered by the original Boujdour Offshore Petroleum Agreement which expired on February 26, 2011. We have entered a memorandum of understanding with the Office National des Hydrocarbures et des Mines ("ONHYM"), the national oil company of Morocco, to enter a new petroleum agreement covering the highest potential areas of this block under essentially the same terms as the original license. See "Risk Factors—Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects."

(3)
The Jubilee Field straddles the boundary between the WCTP Block and the DT Block offshore Ghana. Consistent with the Ghanaian Petroleum Law, the WCTP and DT Petroleum Agreements and as required by Ghana's Ministry of Energy, in order to optimize resource recovery in this field, we entered into the Unitization and Unit Operating Agreement (the "UUOA") on July 13, 2009 with the Ghana National Petroleum Corporation ("GNPC") and the other block partners in each of these two blocks. The UUOA governs the interests in and development of the Jubilee Field and created the Jubilee Unit from portions of the WCTP Block and the DT Block. Kosmos is the technical operator for development ("Technical Operator") and an affiliate of Tullow Oil plc ("Tullow") is the unit operator ("Unit Operator") of the Jubilee Unit. The Technical Operator plans and executes the development of the unit whereas the Unit Operator manages the day-to-day production operations of the unit. Our unit participation interest in the Jubilee Unit is 23.4913% (subject to potential redetermination among the unit partners in this field; see "Risk Factors—The unit partners' respective interests in the Jubilee Unit are subject to redetermination and our interests in such unit may decrease as a result" and "Business—Material Agreements—Exploration Agreements—Ghana—Jubilee Field Unitization"). The other Jubilee Unit partners include: an affiliate of Tullow with a 34.7047% unit participation interest, an affiliate of Anadarko Petroleum Corp. ("Anadarko") with a 23.4913% unit participation interest, GNPC with a 13.75% unit participation interest, Sabre Oil and Gas Holdings Limited ("Sabre") with a 2.8127% unit participation interest and EO Group Limited ("EO Group") with a 1.75% unit participation interest. GNPC has exercised its option with respect to the Jubilee Unit to acquire an additional paying interest of 3.75% in the unit. These interest percentages give effect to the exercise of that option.

(4)
The other WCTP Block partners include: an affiliate of Anadarko with a 30.875% working interest, an affiliate of Tullow with a 22.896% working interest, GNPC with a 10.0% carried working interest, EO Group with a 3.5% carried working interest and an affiliate of Sabre with a 1.854% working interest. GNPC will be carried through the exploration and development phases and has an option to acquire an additional paying interest of 2.5% in a commercial discovery in the WCTP Block. These interest percentages do not give effect to the exercise of such option.

(5)
The other DT Block partners include: an affiliate of Tullow with a 49.95% working interest, an affiliate of Anadarko with an 18.0% working interest, GNPC with a 10.0% carried working interest and an affiliate of Sabre with a 4.05% working interest. GNPC will be carried through the exploration and development phases and has an option to acquire an additional paying interest of 5.0% in a commercial discovery in the DT Block. These interest percentages do not give effect to the exercise of such option.

(6)
The other Kombe-N'sepe Block partners include: Société Nationale des Hydrocarbures ("SNH"), the national oil company of Cameroon, with a 25.0% working interest and an affiliate of Perenco with a 40.0% working interest. The Republic of Cameroon will back-in for a 60.0% revenue interest and a 50.0% carried paying interest in a commercial discovery on the Kombe-N'sepe Block, with Kosmos then holding a 35.0% interest in the remaining interests of the block partners, which would result in Kosmos holding a 14.0% net revenue interest and a 17.5% paying interest. In addition, Kosmos and its block partners are reimbursed for 100% of the carried costs paid out of 35.0% of the total gross production coming from the Republic of Cameroon's entitlement. This interest percentage does not give effect to this back-in.

(7)
The Republic of Cameroon has an option to acquire an interest of up to 15.0% in a commercial discovery on the Ndian River Block. If the Republic of Cameroon elects to acquire an interest, they will be carried for their share of the exploration and appraisal costs. This interest percentage does not give effect to the exercise of such option.

(8)
ONHYM is the only other Boujdour Offshore Block partner and has a 25% participating interest, which will be carried through the exploration phase.

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        As a result of our exploration and development success, we have an asset portfolio that is well-balanced between producing assets, near-term development projects, medium-term appraisal opportunities and exploration prospects with significant hydrocarbon potential. The Kosmos-led execution of the Jubilee Field Phase 1 Development Plan (the "Jubilee Phase 1 PoD") resulted in the commencement of oil production from the Jubilee Field on November 28, 2010, which we refer to as "first oil." This 42-month timeline from discovery to first oil is a record for a deepwater development at this water depth in West Africa. We believe the Jubilee Field, currently our main development project, will ultimately be developed in four distinct phases to maximize hydrocarbon recovery. We recently submitted a notice to Ghana's Ministry of Energy to declare our second discovery, Mahogany East, commercially viable. Also, we and our WCTP and DT Block partners are currently evaluating appraisal and development plans for the Odum, Tweneboa, Enyenra, Teak and Tweneboa Deep discoveries. We expect these discoveries will provide a continuum of new developments coming on stream from our offshore Ghana assets over the near-to-mid term. These license areas contain prospects with significant hydrocarbon potential which we believe have been de-risked because of their proximity to our other Ghanaian discoveries, with which they share similar geologic characteristics.

        We plan to drill two exploratory wells in Cameroon, one on our Kombe-N'sepe Block, which was spud in early 2011, and the other on our Ndian River Block in early 2012. Our exploration prospects in both Cameroon and Morocco have geologic characteristics similar to those of our license areas in Ghana and we believe these prospects hold significant hydrocarbon potential. Going forward, we intend to use our expertise to selectively acquire additional licenses to maintain an exploration and new ventures portfolio to replace and grow reserves.

Our History

        Kosmos was founded in 2003 when several members of our senior management team, backed by private equity firms Warburg Pincus and The Blackstone Group (together with their respective affiliates, our "Investors"), sought to replicate and build upon the success they had at Triton Energy Ltd. ("Triton") exploring for and developing oil and gas reserves in West Africa's Gulf of Guinea. Africa, the Gulf of Mexico and Brazil are widely recognized as possessing the world's greatest large-scale, deepwater oil resource potential. Among these regions, we believe West Africa possesses some of the world's most prolific and least developed petroleum systems, a highly competitive industry cost structure and supportive governments eager to develop their countries' natural resources.

        In the last five years, Africa has entered a new phase in its petroleum history, with numerous large oil and natural gas discoveries made in formerly unexplored and undeveloped regions. The exploration of these regions has been historically constrained by industry assessments of political and technical risk. We intend to leverage our extensive experience in Africa, as well as the experience of our management team prior to forming Kosmos, to successfully manage these risks and profitably produce hydrocarbon resources in these regions.

        We were led to West Africa by our exploration approach, which is deeply grounded in a fundamentals-oriented, geologically based process geared towards the identification of misunderstood, under-explored or overlooked basins, plays and fairways. This process begins with detailed geologic studies that methodically assess a particular region's subsurface in terms of attributes that lead to working petroleum systems. This includes basin-specific modeling to predict oil charge and fluid migration combined with detailed stratigraphic mapping and structural analysis to identify quality reservoir fairways and attractive trapping geometries. This same approach was successfully employed by members of our management team while at Triton.

        In compiling our asset portfolio, we considered exploration opportunities spanning the entire Atlantic margin of Africa, from Morocco to South Africa. Due to our management team's successful exploration history in the Gulf of Guinea in West Africa during their tenure at Triton, our focus was on

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acquiring exploration licenses in the same geographical area. We currently hold five licenses from Ghana, Cameroon and Morocco, and we are the operator under three of these licenses.

        We established a new, major oil province in West Africa with the discovery of the Jubilee Field offshore Ghana in 2007. Subsequently, Kosmos participated in the discovery of five additional discoveries offshore Ghana. Kosmos' leadership of the Jubilee Unit partners enabled the Jubilee Field Phase 1 PoD to be approved by Ghana's Ministry of Energy in July 2009. The Jubilee Phase 1 PoD committed to delivering an approximately $3.3 billion project capable of producing 120,000 bopd. The Kosmos-led execution of the Jubilee Phase 1 PoD resulted in first oil on November 28, 2010. This 42-month timeline from discovery to first oil is a record for a deepwater development at this water depth in West Africa.

        In 2009, Kosmos entered into a commercial agreement to sell our Ghanaian assets to Exxon Mobil Corporation ("ExxonMobil"). On August 16, 2010, ExxonMobil terminated the Sale and Purchase Agreement ("SPA") we had entered with them on June 28, 2010, in accordance with the terms of the SPA. ExxonMobil provided no explanation for the termination and was not contractually obligated to do so under the terms of the SPA. From the date of the commercial agreement with ExxonMobil through December 31, 2010, we have spent approximately $630 million developing Jubilee Phase 1 and de-risking these assets, made the Enyenra, Teak and Tweneboa Deep discoveries offshore Ghana and drilled six successful appraisal wells on our Mahogany East, Odum and Tweneboa discoveries. With regard to the Jubilee Field, our de-risking activities have included the drilling of development wells, successful completion of fabrication, installation, hook-up and commissioning of the Jubilee Phase 1 facilities and initiation of production. With regard to our Ghanaian discoveries, our de-risking activities have included the drilling of successful appraisal wells. With regard to our Ghanaian prospects, these have been partially de-risked due to their similarity and proximity to our existing discoveries.

Our Competitive Strengths

World-class asset portfolio situated along the Atlantic Coast Margin of West Africa

        We targeted the Atlantic margin of Africa as a focus area for exploration following a multi-year assessment of numerous exploration opportunities across a broad region. Our assessment was driven by our interpretation of geological and seismic data and by our internationally experienced technical, operational and management teams.

        We also make an in-depth evaluation of regional political risk, economic conditions and fiscal terms. Ghana, for example, enjoys relative political stability, overall sound economic management, a low crime rate, competitive wages and an educated, English-speaking workforce. The country also scores well among its peers on various measures of corruption, ranking 62 nd  out of 178 countries in Transparency International's 2010 Corruption Perceptions Index, vastly ahead of each of its peers according to a peer group selected by Standard & Poor's. Ghana is also the highest ranked among such peer group in the World Bank's Doing Business 2011 report, at fifth out of 46 sub-Sahara African countries included in such report.

        Our asset portfolio consists of seven discoveries including the Jubilee Field, which was one of the largest oil discoveries worldwide in 2007 and the largest find offshore West Africa in the last decade. Our other discoveries include Mahogany East, Odum, Tweneboa, Enyenra, Teak and Tweneboa Deep offshore Ghana, which have geologic characteristics similar to the Jubilee Field. In addition, we have identified 18 additional prospects offshore Ghana, 10 additional prospects in Cameroon and 19 additional prospects offshore Morocco. We expect to make new discoveries and to define additional prospects as our team continues to develop our current asset portfolio and identify and pursue new high-potential assets.

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Well-defined production and growth plan

        Our plan for developing the Jubilee Field provides visible, near-term cash generation and long-term growth opportunities. We estimate Jubilee Field Phase 1 daily gross production to reach the 120,000 bopd design capacity of the FPSO facility used to produce from the field, in the third quarter of 2011. Within the next few years, we intend to expand upon the Jubilee Field Phase 1 development with three additional phases that are designed to maintain production and cash flow from partially de-risked locations. A phased development program allows us to develop Jubilee Phase 1 on a faster timeline and allowed us to achieve first oil production at an earlier date than traditional development techniques. See "—Our Strategy—Focus on rapidly developing our discoveries to initial production." In addition to Jubilee, we are currently in the development planning stage for Mahogany East, the pre-development planning stage for the Odum discovery, and the appraisal stage for the Tweneboa, Enyenra, Teak and Tweneboa Deep discoveries. We believe these assets provide additional mid-term production and cash flow opportunities to supplement the phased Jubilee Field development.

Significant upside potential from exploratory assets

        Since our inception we have focused on acquiring exploratory licenses in emerging petroleum basins in West Africa. This led to the assembly of a hydrocarbon asset portfolio of five licenses with significant upside potential and attractive fiscal terms. In Ghana, we believe our existing licenses offer substantial opportunities for significant growth in shareholder value as a result of numerous high value exploration prospects that are partially de-risked due to their similarity and proximity to our existing discoveries. We plan to drill two exploratory wells in Cameroon, one on our Kombe-N'sepe Block, which was spud in early 2011, and the other on our Ndian River Block in early 2012.

Oil-weighted asset portfolio in key strategic regions

        Our portfolio of assets consists primarily of oil discoveries and prospects. Oil comprises approximately 94% of our proved reserves that are associated with the Jubilee Field Phase 1 development. Due to its high quality and strategic geographic location, oil from the Jubilee Field is commanding a premium to Dated Brent, its reference commodity price. We expect our other Ghana discoveries and prospects, as well as our Cameroon and Morocco prospects, to maintain a primarily oil-weighted composition. We believe that global petroleum supply and demand fundamentals will continue to provide a strong market for our oil, and therefore we intend to continue targeting oil exploration and development opportunities. Furthermore, our geographic location in West Africa enables broad access to the major consuming markets of North America, Asia and Europe, providing marketing flexibility. The ability to supply oil to global markets with reasonable transportation costs reduces localized supply/demand risks often associated with various international oil markets.

New ventures group focused on expanding our asset portfolio

        Our existing asset portfolio has already delivered large scale drill-bit success in Ghana and provided the opportunity for near- to mid-term reserve and production growth. While substantial exploration potential remains in our portfolio, we are also focused on renewing, replenishing and expanding our prospect inventory through the work of our new ventures group, which is tasked with executing an acquisition program to replicate this success. We believe this will permit timely delivery of further oil and natural gas discoveries for continued long-term reserve and production growth. We aim to leverage our unique exploration approach to maintain our successful track record with these new ventures.

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Seasoned and incentivized management and technical team with demonstrable track record of performance and value creation

        We are led by an experienced management team with a track record of successful exploration and development and public shareholder value creation. Our management team's average experience in the energy industry is over 20 years. Members of the senior management team successfully worked together both at and since their tenure at Triton, where they contributed to transforming Triton into one of the largest internationally focused independent oil and gas companies headquartered in the United States, prior to the sale of Triton to Hess Corporation ("Hess") for approximately $3.2 billion in 2001. Members of our management and senior technical team participated in discovering and developing multiple large scale upstream projects around the world, including the deepwater Ceiba Field, which was developed on budget and in record time offshore Equatorial Guinea, in West Africa in 2000. In the course of this work, the team acquired a track record for successful identification, acquisition and development of large offshore oil fields, and has been involved in discovering and developing over five billion barrels of oil equivalent ("Bboe"). We believe our unique experience, industry relationships, and technical expertise have been critical to our success and are core competitive strengths.

        Furthermore, our management team has considerable experience in managing the political risks present when operating in developing countries, including working with the host governments to achieve mutually beneficial results, while at all times protecting the company's rights and asserting investors' interests.

        Our management team currently owns and will continue to own a significant direct ownership interest in us immediately following the completion of this offering. We believe our management team's direct ownership interest as well as their ability to increase their holdings over time through our long-term incentive plan aligns management's interests with those of our shareholders. This long-term incentive plan will also help to attract and retain the talent to support our business strategy.

Strong financial position

        Since inception we have been backed by our Investors, namely Warburg Pincus and The Blackstone Group, each supporting our initial growth with substantial equity investments. Each Investor will retain a significant interest in Kosmos following this offering. With the proceeds from this offering, our cash on hand and our commercial debt commitments, we believe we will possess the necessary financial strength to implement our business strategy through 2013. As of December 31, 2010, we had approximately $212 million of total cash on hand, including $112 million of restricted cash, and $205 million of committed undrawn capacity under our previous commercial debt facilities. In March 2011 we entered into a new $2.0 billion commercial debt facility, which may be increased to $3.0 billion upon us obtaining additional commitments. At March 31, 2011 we had $1.3 billion outstanding, $151 million of availability and $700 million of committed undrawn capacity under such facility. In addition, we have demonstrated the ability to raise capital, having secured commitments for approximately $1.05 billion of private equity funding in the last seven years and recently put in place the $2.0 billion commercial debt facility. Furthermore, we received our first oil revenues in early 2011 from the Jubilee Field, and accordingly a portion of these revenues will be used to fund future exploration and development activities.

Our Strategy

        In the near-term, we are focused on maximizing production from the Jubilee Field Phase 1 development, as well as accelerating the development of our other discoveries. Longer term, we are focused on the acquisition, exploration, appraisal and development of existing and new opportunities in Africa, including identifying, capturing and testing additional high-potential prospects to grow reserves and production. By employing our competitive advantages, we seek to increase net asset value and

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deliver superior returns to our shareholders. To this end, our strategy includes the following components:

Grow proved reserves and production through accelerated exploration, appraisal and development

        In the near-term, we plan to develop and produce our current discoveries offshore Ghana, including Jubilee and Mahogany East, and upon a declaration of commerciality and approval of a plan of development, Odum, Tweneboa, Enyenra, Teak and Tweneboa Deep. Additionally, we plan to drill-out our portfolio of exploration prospects offshore Ghana, which have been partially de-risked by our successful drilling program to date. If successful, these prospects will deliver proved reserve and production growth in the medium term. In the longer term, we plan to drill-out our existing prospect inventory on our other licenses in West Africa and to replicate our exploratory success through new ventures in other regions of the African continent.

Apply our technically-driven culture, which fosters innovation and creativity, to continue our successful exploration and development program

        We differentiate ourselves from other E&P companies through our approach to exploration and development. Our senior-most geoscientists and development engineers are pivotal to the success of our business strategy. We have created an environment that enables them to focus their knowledge, skills and experience on finding and developing oil fields. Culturally, we have an open, team-oriented work environment that fosters both creative and contrarian thinking. This approach allows us to fully consider and understand risk and reward and to deliberately and collectively pursue strategies that maximize value. We used this philosophy and approach to unlock the Tano Basin offshore Ghana, a significant new petroleum system that the industry previously did not consider either prospective or commercially viable.

Focus on rapidly developing our discoveries to initial production

        We focus on maximizing returns through phasing the appraisal and development of discoveries. There are numerous benefits to pursuing a phased development strategy to support our production growth plan. Importantly, a phased development strategy provides for first oil production earlier than what would otherwise be possible using traditional development techniques, which are disadvantaged by more time-consuming, costly and sequential appraisal and pre-development activities. This approach optimizes full-field development and maximizes net asset value by refining appraisal and development plans based on experience gained in initial phases and by leveraging existing infrastructure as we implement subsequent phases of development. Other benefits include minimizing upfront capital costs, reducing execution risks through smaller initial infrastructure requirements, and enabling cash flow from the initial phase of production to fund a portion of capital costs for subsequent phases.

        First oil from the Jubilee Field commenced on November 28, 2010 and we received our first oil revenues in early 2011. This development timeline from discovery to first oil is significantly less than the industry average of seven to ten years and is a record for a deepwater development at this water depth in West Africa. This condensed timeline reflects the lessons learned by members of our seasoned management while at Triton and during their time at other major deepwater operators. At Triton, the team took the 50,000 bopd Ceiba Field offshore Equatorial Guinea from discovery to first oil in fourteen months. Additionally, members of our development team have led other larger scale deepwater developments, such as Neptune and Mensa in the U.S. Gulf of Mexico. These experiences drove the 42-month record timeline from discovery to first oil achieved by the significantly larger Jubilee Field Phase 1 development.

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Identify, access and explore emerging exploratory regions and hydrocarbon plays

        Our management and exploration team have demonstrated an ability to identify regions and hydrocarbon plays that will yield multiple large commercial discoveries. We will continue to utilize our systematic and proven geologically focused approach to emerging petroleum systems where source rocks and reservoirs have been established by previous drilling and where seismic data suggests hydocarbon accumulations are likely to exist, but where commercial discoveries have yet to be made. We believe this approach reduces the exploratory risk in poorly understood, under-explored or otherwise overlooked hydrocarbon basins that offer significant oil potential. This was the case with respect to the Late Cretaceous stratigraphy of West Africa, the niche in which we chose to build our asset portfolio between 2004 and 2006. Our licenses in Ghana, Cameroon and Morocco share similar geologic characteristics focused on untested structural-stratigraphic traps. This exploration focus has proved successful, with the discovery of the Jubilee Field ushering in a new level of industry interest in Late Cretaceous petroleum systems across the African continent, including play types that had previously been largely ignored.

        This approach and focus, coupled with a first-mover advantage, provide a competitive advantage in identifying and accessing new strategic growth opportunities. We expect to continue to seek new opportunities where oil has not been discovered or produced in meaningful quantities by leveraging the skills of our experienced technical team. This includes our existing areas of interest as well as selectively expanding our reach into other locations in Africa or beyond that offer similar geologic characteristics.

Acquire additional exploration assets

        We intend to utilize our experience and expertise and leverage our reputation and relationships to selectively acquire additional exploration licenses and maintain a portfolio of undrilled exploration prospects. We plan to farm-in to new venture opportunities as well as to undertake exploration in emerging basins, plays and fairways to enhance and optimize our position in Africa. In addition, we plan to expand our geographic footprint in a focused and systematic fashion. Consistent with this strategy, we also evaluate potential corporate acquisition opportunities as a source of new ventures to replenish and expand our asset portfolio.

Jubilee Phase 1 Reserve and Development Information

        Jubilee Field Phase 1 is the first of our discoveries to have been determined to have proved reserves. As of December 31, 2010, Netherland, Sewell & Associates, Inc. ("NSAI"), our independent reserve engineers, evaluated the Jubilee Field Phase 1 development to hold gross proved reserves of 250 Mmboe. We currently hold a 23.4913% unit participation interest in this development (subject to any redetermination among the unit partners in this field. See "Risk Factors—The unit partners' respective interests in the Jubilee Unit are subject to redetermination and our interests in such unit may decrease as a result" and "Business—Material Agreements—Exploration Agreements—Ghana—Jubilee Field Unitization"). NSAI estimated our net proved reserves to be approximately 56 Mmboe as of December 31, 2010, consisting of approximately 93% oil. All of our proved reserves are currently located in the Jubilee Field Phase 1 development. Our other discoveries outside of the Jubilee Field Phase 1, including Mahogany East, Odum, Tweneboa, Enyenra, Teak, Tweneboa Deep and other Jubilee Field phases, do not yet have approved plans of development ("PoDs") and therefore cannot be classified as proved reserves.

        The Jubilee Field Phase 1 development employs safe, industry standard deepwater equipment with conventional "off-the-shelf" technologies. We believe such technologies and development infrastructure meet industry safety standards and have been consistently used in deepwater oilfield development, with appropriate advancements in recent years. The Jubilee Field Phase 1 development was designed to

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provide suitable flexibility and expandability in order to minimize capital expenditures associated with subsequent phases of development. The FPSO facility used at the field was delivered and moored to the seabed in July 2010. Planning is underway for the development of additional reservoirs and subsequent phases of the Jubilee Field.

        Our drilling rigs, the Atwood Hunter and the Deepwater Millenium along with the Eirik Raude, once the drilling and completion activity associated with the Jubilee Field Phase 1 development is complete, will test other high-potential identified prospects and appraise our other discoveries offshore Ghana. Additionally we will work with our block partners, GNPC and Ghana's Ministry of Energy to advance PoDs for approval for the staged and timely development of the Mahogany East, Odum, Tweneboa, Enyenra, Teak and Tweneboa Deep discoveries over the next three years.

Discovery Information

        Information about our discoveries is summarized in the following table.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discoveries	 	License	 	Kosmos
Working
Interest	 	Block Operator(s)	 	Stage	 	Type	 	Expected
Year of PoD
Submission	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Jubilee Field Phase 1(1)(2)	 	WCTP/DT(3)	 	 	23.4913%	(5)	Tullow/Kosmos(6)	 	Production	 	Deepwater	 	 	2008	(2)	
 	Jubilee Field subsequent phases(2)	 	WCTP/DT(3)	 	 	23.4913%	(5)	Tullow/Kosmos(6)	 	Development	 	Deepwater	 	 	2011	 	
 	Mahogany East	 	WCTP(4)	 	 	30.8750	%	Kosmos	 	Development planning	 	Deepwater	 	 	2011	 	
 	Odum	 	WCTP(4)	 	 	30.8750	%	Kosmos	 	Development planning	 	Deepwater	 	 	2011	 	
 	Teak	 	WCTP(4)	 	 	30.8750	%	Kosmos	 	Appraisal	 	Deepwater	 	 	2013	 	
 	Tweneboa	 	DT(4)	 	 	18.0000	%	Tullow	 	Appraisal	 	Deepwater	 	 	2012	(7)	
 	Enyenra	 	DT(4)	 	 	18.0000	%	Tullow	 	Appraisal	 	Deepwater	 	 	2013	 	
 	Tweneboa Deep	 	DT(4)	 	 	18.0000	%	Tullow	 	Appraisal	 	Deepwater	 	 	2014	 	

(1)
For information concerning our estimated proved reserves in the Jubilee Field as of December 31, 2010, see "Business—Our Reserves."

(2)
The Jubilee Phase 1 PoD was submitted to Ghana's Ministry of Energy on December 18, 2008 and was formally approved on July 13, 2009. The Jubilee Phase 1 PoD details the necessary wells and infrastructure to develop the UM3 and LM2 reservoirs. Oil production from the Jubilee Field offshore Ghana commenced on November 28, 2010, and we received our first oil revenues in early 2011. We intend to submit or amend PoDs for other reservoirs within the unit for subsequent Jubilee Field phases to Ghana's Ministry of Energy for approval in order to extend the production plateau of the Jubilee Field.

(3)
The Jubilee Field straddles the boundary between the WCTP Block and the DT Block offshore Ghana. Consistent with the Ghanaian Petroleum Law, the WCTP and DT Petroleum Agreements and as required by Ghana's Ministry of Energy, in order to optimize resource recovery in this field, we entered into the UUOA on July 13, 2009 with GNPC and the other block partners of each of these two blocks. The UUOA governs the interests in and development of the Jubilee Field and created the Jubilee Unit from portions of the WCTP Block and the DT Block.

(4)
GNPC has the option to acquire additional paying interests in a commercial discovery on the WCTP Block and the DT Block of 2.5% and 5.0%, respectively. In order to acquire the additional paying interest, GNPC must notify the contractor of its intention to acquire such interest within sixty to ninety days of the contractor's notice to Ghana's Ministry of Energy of a commercial discovery. These interest percentages do not give effect to the exercise of such options.

(5)
These interest percentages are subject to redetermination of the working interests in the Jubilee Field pursuant to the terms of the UUOA. See "Risk Factors—The unit partners' respective interests in the Jubilee Unit are subject to redetermination and our interests in such unit may decrease as a result" and "Business—Material Agreements—Exploration Agreements—Ghana—Jubilee Field Unitization." GNPC has exercised its options, with respect to the Jubilee Unit, to acquire an additional unitized paying interest of 3.75% in the Jubilee Field. The Jubilee Field interest percentages give effect to the exercise of such option.

(6)
Kosmos is the Technical Operator and Tullow is the Unit Operator of the Jubilee Unit. See "Business—Material Agreements—Exploration Agreements—Ghana—Jubilee Field Unitization."

(7)
Appraisal of the Tweneboa oil and gas condensate reservoirs is expected to continue through 2011. As outlined by the petroleum agreement covering the DT Block, a submission of a PoD would be required for an oil development by 2012, while the submission of a PoD related to a natural gas development would be required by 2013.

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Prospect Information

        Information about our prospects is summarized in the following table.
 	 	 	 	 	 	 	 	 	 	 	 	 	
Prospect	 	License	 	Kosmos
Working
Interest (%)	 	Block
Operator	 	Type	 	Projected
Spud Year(4)	
Ghana(1)	 	 	 	 	 	 	 	 	 	 	 	
 	Banda Campanian	 	WCTP	 	 	30.875	 	Kosmos	 	Deepwater	 	2011(5)	
 	Banda Cenomanian	 	WCTP	 	 	30.875	 	Kosmos	 	Deepwater	 	2011(5)	
 	Makore	 	WCTP	 	 	30.875	 	Kosmos	 	Deepwater	 	2011	
 	Odum East	 	WCTP	 	 	30.875	 	Kosmos	 	Deepwater	 	2012	
 	Sapele	 	WCTP	 	 	30.875	 	Kosmos	 	Deepwater	 	2012	
 	Funtum	 	WCTP	 	 	30.875	 	Kosmos	 	Deepwater	 	2012	
 	Assin	 	WCTP	 	 	30.875	 	Kosmos	 	Deepwater	 	2012	
 	Okoro	 	WCTP	 	 	30.875	 	Kosmos	 	Deepwater	 	Post 2012	
 	Late Cretaceous WCTP Play (4 identified targets)	 	WCTP	 	 	30.875	 	Kosmos	 	Deepwater	 	Post 2012	
 	Walnut	 	DT	 	 	18.000	 	Tullow	 	Deepwater	 	2012	
 	DT Sapele	 	DT	 	 	18.000	 	Tullow	 	Deepwater	 	2012	
 	Wassa	 	DT	 	 	18.000	 	Tullow	 	Deepwater	 	Post 2012	
 	Adinkra	 	DT	 	 	18.000	 	Tullow	 	Deepwater	 	Post 2012	
 	Oyoko	 	DT	 	 	18.000	 	Tullow	 	Deepwater	 	Post 2012	
 	Ananta	 	DT	 	 	18.000	 	Tullow	 	Deepwater	 	Post 2012	
Cameroon(2)	 	 	 	 	 	 	 	 	 	 	 	
 	N'gata	 	Kombe-N'sepe	 	 	35.000	 	Perenco	 	Onshore	 	2011(6)	
 	N'donga	 	Kombe-N'sepe	 	 	35.000	 	Perenco	 	Onshore	 	Post 2012	
 	Disangue	 	Kombe-N'sepe	 	 	35.000	 	Perenco	 	Onshore	 	Post 2012	
 	Pongo Songo	 	Kombe-N'sepe	 	 	35.000	 	Perenco	 	Onshore	 	Post 2012	
 	Bonongo	 	Kombe-N'sepe	 	 	35.000	 	Perenco	 	Onshore	 	Post 2012	
 	Coco East	 	Kombe-N'sepe	 	 	35.000	 	Perenco	 	Onshore	 	Post 2012	
 	Liwenyi	 	Ndian River	 	 	100.000	 	Kosmos	 	Onshore	 	2012	
 	Liwenyi South	 	Ndian River	 	 	100.000	 	Kosmos	 	Onshore	 	Post 2012	
 	Meme	 	Ndian River	 	 	100.000	 	Kosmos	 	Onshore	 	Post 2012	
 	Bamusso	 	Ndian River	 	 	100.000	 	Kosmos	 	Onshore	 	Post 2012	
Morocco(3)	 	 	 	 	 	 	 	 	 	 	 	
 	Gargaa	 	Boujdour Offshore	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Argane	 	Boujdour Offshore	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Safsaf	 	Boujdour Offshore	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Aarar	 	Boujdour Offshore	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Zitoune	 	Boujdour Offshore	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Al Arz	 	Boujdour Offshore	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Felline	 	Boujdour Offshore	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Nakhil	 	Boujdour Offshore	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Barremian Tilted Fault Block Play (11 identified structures)	 	Boujdour Offshore	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	

(1)
GNPC has the option to acquire additional paying interests in a commercial discovery on the WCTP Block and the DT Block of 2.5% and 5.0%, respectively. In order to acquire the additional paying interests, GNPC must notify the contractor of its intention to do so within sixty to ninety days of the contractor's notice to Ghana's Ministry of Energy of a commercial discovery. These interest percentages do not give effect to the exercise of such options.

(2)
The Republic of Cameroon will back-in for a 60.0% revenue interest and a 50.0% carried paying interest in a commercial discovery on the Kombe-N'sepe Block, with Kosmos then holding a 35.0% interest in the remaining interests of the block partners. This would result in Kosmos holding a 14.0% net revenue interest and a 17.5% paying interest. The Republic of Cameroon has an option to acquire an interest of up to 15.0% in a commercial discovery on the Ndian River Block. These interest percentages do not give effect to the exercise of such options.

(3)
We have not yet made a decision as to whether or not to drill our Moroccan prospects. We have entered a memorandum of understanding with ONHYM to enter a new license covering the highest potential areas of this block under essentially the same terms as the original license. If we decide to continue into the drilling phase of such license, we anticipate that the first well to drill within the Boujdour Offshore Block will be post 2012.

(4)
See "Risk Factors—Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling" and "Risk Factors—Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects."

(5)
The Banda-1 exploration well was spud in mid 2011 and is currently drilling both the Banda Campanian and Banda Cenomanian prospects.

(6)
The N'gata-1 exploration well was spud in early 2011 and is currently being drilled.

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Recent Events

        In April 2011, it was announced that the "Tweneboa-4" appraisal well in the DT Block had successfully encountered gas condensate in the western extent of the Tweneboa discovery. Results of drilling, wireline logs and samples of reservoir fluids show the well encountered 59 feet (18 meters) of net gas-condensate pay in high quality stacked reservoir sandstones which are in communication with both the Tweneboa-1 and Tweneboa-2 wells.

        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 accordion accessible upon receiving additional commitments. Along with the proceeds of this offering, these funds will support our share of the Jubilee Field 1 development, appraisal of additional discoveries and ongoing exploration activities on new and existing licenses.

        In March 2011, it was announced that the "Teak-2" appraisal well had successfully appraised our Teak discovery on the WCTP Block. Results of drilling, wireline logs and samples of reservoir fluids confirm that the Teak-2 well has 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 over 4 miles (7 km) 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 distal portion of a deeper Turonian-age fan where 16 feet (5 meters) of gas-condensate sandstones were intersected confirming the existence of hydrocarbons in the Tweneboa Deep prospect. Notice of the discovery of Tweneboa Deep was submitted to GNPC in late April 2011.

        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 after the company's Mahogany-1 exploration well, which discovered the Jubilee Field on the WCTP Block in 2007.

        In February 2011, we announced that Chris Tong has been appointed to the Kosmos board of directors, subject to certain corporate formalities (which have since been completed).

        In January 2011, we announced that the "Tweneboa-3" appraisal well in the DT Block had successfully confirmed the Greater Tweneboa Area's (comprising the Tweneboa-1 and Tweneboa-2 oil and gas-condensate fields and the neighboring Enyenra light oil field (formerly known as the Owo Field)) resource base potential. 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.

        In January 2011, we announced that John R. Kemp III had been named Chairman and Brian F. Maxted, one of the founding partners of Kosmos, had been promoted from Chief Operating Officer to President and Chief Executive Officer and made a member of the Kosmos board of directors, following the retirement of James C. Musselman, Kosmos' former Chairman and Chief Executive Officer.

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        In September 2010, we announced that the Owo-1ST appraisal sidetrack well had successfully confirmed a significant column of high quality, light oil in the Enyenra Field, which lies wholly within the DT Block. The results of drilling, wireline logs and reservoir fluid samples show the Owo-1ST appraisal sidetrack well penetrated net oil pay of approximately 63 feet (19 meters) in two zones of high-quality stacked reservoir sandstones. In addition, the Owo-1ST encountered approximately 52 feet (16 meters) of natural gas condensate in two new pools not previously encountered.

        In September 2010, we announced our second declaration of commerciality in Ghana with Mahogany East in the WCTP Block and are currently performing a Front End Engineering and Design ("FEED") study for final selection of the development concept to be included in a PoD submission. As operator of Mahogany East, we intend to submit a PoD for the field to Ghana's Ministry of Energy in 2011, with the potential to achieve first production from the development in early 2014.

        In August 2010, we announced the execution of definitive documentation to increase our commercial debt facilities by $350 million, raising the total amount of our debt commitments to $1.25 billion.

        In July 2010, Tullow announced that the "Owo-1" exploration well had successfully discovered hydrocarbons in the Enyenra Field in the DT Block. The results of drilling, wireline logs and reservoir fluid samples showed the Owo-1 exploration well encountered hydrocarbon-bearing net pay of approximately 174 feet (53 meters) in two zones of high-quality stacked reservoir sandstones.

        In May 2010, we drilled the "Mahogany-5" appraisal well, the final appraisal well for Mahogany East. Such field lies wholly within the WCTP Block and has previously been appraised by the "Mahogany-3", "Mahogany-4" and "Mahogany Deep-2" wells.

        In January 2010, we announced that the "Tweneboa-2" well in the DT Block had successfully appraised our Tweneboa discovery. The results of drilling, wireline logs and reservoir fluid samples confirmed the well has a gross hydrocarbon column of approximately 502 feet (153 meters) and penetrated combined net hydrocarbon-bearing pay of at least 105 feet (32 meters) in stacked sandstone reservoirs.

        In December 2009, we announced that the "Odum-2" well in the WCTP Block had successfully appraised the "Odum-1" oil discovery with drilling, wireline logs and reservoirs fluid samples showed the well penetrated new hydrocarbon-bearing net pay of approximately 66 feet (20 meters) in high-quality stacked sandstone reservoirs over a gross interval of approximately 597 feet (182 meters).

Risks Associated with our Business

        There are a number of risks you should consider before buying our common shares. These risks are discussed more fully in the section entitled "Risk Factors" beginning on page 17 of this prospectus. These risks include, but are not limited to:

•
We have limited proved reserves and areas that we decide to drill may not yield oil and natural gas in commercial quantities or quality, or at all;

•
We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects;

•
Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business;

•
A substantial or extended decline in both global and local oil and natural gas prices may adversely affect our business, financial condition and results of operations;

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•
Our operations may be adversely affected by political and economic circumstances in the countries in which we operate;

•
We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult; and

•
Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms in the future, which may in turn limit our ability to develop our exploration, appraisal, development and production activities.

Corporate Information

        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. Kosmos Energy Holdings was formed as an exempted company limited by guarantee on March 5, 2004 pursuant to the laws of the Cayman Islands. Pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the closing of this offering, all of the interests in Kosmos Energy Holdings will be exchanged for newly issued common shares of Kosmos Energy Ltd. and as a result Kosmos Energy Holdings will become wholly-owned by Kosmos Energy Ltd.

        We maintain a registered office in Bermuda at Clarendon House, 2 Church Street, Hamilton HM 11, Bermuda. The telephone number of our registered offices is (441) 295-5950. Our U.S. subsidiary maintains its headquarters at 8176 Park Lane, Suite 500, Dallas, Texas 75231 and its telephone number is (214) 445-9600. Our web site is www.kosmosenergy.com . The information on our web site does not constitute part of this prospectus.

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The Offering

Issuer	 	Kosmos Energy Ltd.	
Common shares offered by us	 	30,000,000 common shares	
Common shares to be issued and outstanding after this offering	 	371,176,471 common shares	
Over-allotment option	 	We have granted to the underwriters an option, exercisable upon notice to us, to purchase up to 4,500,000 additional common shares at the offering price to cover over-allotments, if any, for a period of 30 days from the date of this prospectus.	
Use of Proceeds	 	We intend to use the net proceeds from this offering and other resources available to us to fund our capital expenditures, and in particular our exploration and appraisal drilling program and development activities through 2013 and associated operating expenses, the payment of $15.0 million to GNPC upon successful completion of this offering, and for general corporate purposes. See "Use of Proceeds" on page 49 of this prospectus for a more detailed description of our intended use of the proceeds from this offering.	
Listing	 	Our common shares have been approved for listing on the New York Stock Exchange (the "NYSE") under the symbol "KOS." Shortly after the closing of this offering, we intend to apply to list our common shares on the Ghana Stock Exchange (the "GSE"), although there can be no assurance that this listing will be completed in a timely manner, or at all.	
        Except as otherwise indicated, all information in this prospectus assumes:

•
the completion, simultaneously with or prior to the closing of this offering, of our corporate reorganization pursuant to which all of the interests of Kosmos Energy Holdings will be exchanged for common shares of Kosmos Energy Ltd. and as a result Kosmos Energy Holdings will become wholly owned by Kosmos Energy Ltd.;

•
an initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price range set forth on the cover page of this prospectus. In the event that the initial public offering price in this offering is less than $17.00 per common share, the aggregate number of common shares issuable as a result of the exchange of the Series A Preferred Units of Kosmos Energy Holdings will be increased and the aggregate number of common shares issuable as a result of the exchange of the Series B and Series C Preferred Units and the Common Units of Kosmos Energy Holdings will be decreased. The exact amount of any such adjustments, if any, will be based on the actual per share initial public offering price. However, any such adjustments will not result in any change to the aggregate number of common shares issuable in exchange for preferred units, nor any change in the aggregate number of common shares issued and outstanding after this offering (other than any increase or decrease resulting from the elimination of fractional shares); and

•
no exercise of the underwriters' over-allotment option to purchase additional common shares.

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

        The summary historical financial data set forth below should be read in conjunction with the sections entitled "Corporate Reorganization", "Selected Historical and Pro Forma Financial Information" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and with Kosmos Energy Holdings' financial statements and the notes to those financial statements included elsewhere in this prospectus. Kosmos Energy Holdings has been a development stage company. The consolidated statements of operations and cash flows for the years ended December 31, 2006, 2007, 2008, 2009 and 2010 and for the period April 23, 2003 (Inception) through December 31, 2010, and the consolidated balance sheets as of December 31, 2005, 2006, 2007, 2008, 2009 and 2010 were derived from Kosmos Energy Holdings' audited consolidated financial statements. The summary unaudited pro forma financial data set forth below is derived from Kosmos Energy Holdings' audited consolidated financial statements appearing elsewhere in this prospectus and is based on assumptions and includes adjustments as explained in the notes to the tables.

Consolidated Statements of Operations Information:

	 	 

	 	 
	 	 
	 	Period
April 23, 2003
(Inception)
through
December 31
2010	 	 	
 
	 	Year Ended December 31	 	 	 	 	 	
 
	 	2006	 	2007	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands, except per share data)

Revenues and other income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas revenue	 	$	—	 	$	—	 	$	—	 	$	—	 	$	—	 	$	—	 	 	 	
 	Interest income	 	 	445	 	 	1,568	 	 	1,637	 	 	985	 	 	4,231	 	 	9,142	 	 	 	
 	Other income	 	 	3,100	 	 	2	 	 	5,956	 	 	9,210	 	 	5,109	 	 	26,699	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total revenues and other income	 	 	3,545	 	 	1,570	 	 	7,593	 	 	10,195	 	 	9,340	 	 	35,841	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Exploration expenses, including dry holes	 	 	9,083	 	 	39,950	 	 	15,373	 	 	22,127	 	 	73,126	 	 	166,450	 	 	 	
 	General and administrative	 	 	9,588	 	 	18,556	 	 	40,015	 	 	55,619	 	 	98,967	 	 	236,165	 	 	 	
 	Depletion, depreciation and amortization	 	 	401	 	 	477	 	 	719	 	 	1,911	 	 	2,423	 	 	6,505	 	 	 	
 	Amortization—debt issue costs	 	 	—	 	 	—	 	 	—	 	 	2,492	 	 	28,827	 	 	31,319	 	 	 	
 	Interest expense	 	 	—	 	 	8	 	 	1	 	 	6,774	 	 	59,582	 	 	66,389	 	 	 	
 	Derivatives, net	 	 	—	 	 	—	 	 	—	 	 	—	 	 	28,319	 	 	28,319	 	 	 	
 	Equity in losses of joint venture	 	 	9,194	 	 	2,632	 	 	—	 	 	—	 	 	—	 	 	16,983	 	 	 	
 	Doubtful accounts expense	 	 	—	 	 	—	 	 	—	 	 	—	 	 	39,782	 	 	39,782	 	 	 	
 	Other expenses, net	 	 	7	 	 	17	 	 	21	 	 	46	 	 	1,094	 	 	1,949	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total costs and expenses	 	 	28,273	 	 	61,640	 	 	56,129	 	 	88,969	 	 	332,120	 	 	593,861	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Loss before income taxes	 	 	(24,728	)	 	(60,070	)	 	(48,536	)	 	(78,774	)	 	(322,780	)	 	(558,020	)	 	 	
 	Income tax expense (benefit)	 	 	—	 	 	718	 	 	269	 	 	973	 	 	(77,108	)	 	(75,148	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(24,728	)	$	(60,788	)	$	(48,805	)	$	(79,747	)	$	(245,672	)	$	(482,872	)	 	 	
Accretion to redemption value of convertible preferred units	 	 	(4,019	)	 	(8,505	)	 	(21,449	)	 	(51,528	)	 	(77,313	)	 	(165,262	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss attributable to common unit holders	 	$	(28,747	)	$	(69,293	)	$	(70,254	)	$	(131,275	)	$	(322,985	)	$	(648,134	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pro forma net loss (unaudited)(1):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pro forma basic and diluted net loss per common share(2)	 	 	 	 	 	 	 	 	 	 	 	            	 	$	(0.75	)	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pro forma weighted average number of shares used to compute pro forma net loss per common share, basic and diluted(3)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	325,799	 	 	 	 	 	 	

(1)
Pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the closing of this offering, all of the interests in Kosmos Energy Holdings will be exchanged for newly issued common shares of Kosmos Energy Ltd. based on these interests' relative rights as set forth in Kosmos Energy Holdings' current operating agreement. This includes convertible preferred units of Kosmos Energy Holdings which are

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redeemable upon the consummation of a qualified public offering (as defined in the current operating agreement) into common shares of Kosmos Energy Ltd. based on the pre-offering equity value of such interests.(2)
Any stock options, restricted share units and share appreciation rights that are out of the money will be excluded as they will be anti-dilutive.

(3)
The weighted average common shares outstanding have been calculated as if the ownership structure resulting from the corporate reorganization was in place since inception.

Consolidated Balance Sheets Information:

	 	As of December 31	 	Pro Forma as
Adjusted as of
December 31
2010(1)	 	 	
 
	 	2006	 	2007	 	2008	 	2009	 	2010	 	 	 	 	
 
	 	(In thousands)
	 	(Unaudited)
	 	 	
Cash and cash equivalents	 	$	9,837	 	$	39,263	 	$	147,794	 	$	139,505	 	$	100,415	 	$	100,415	 	 	
Total current assets	 	 	10,334	 	 	65,960	 	 	205,708	 	 	256,728	 	 	559,920	 	 	559,920	 	 	
Total property and equipment	 	 	1,567	 	 	18,022	 	 	208,146	 	 	604,007	 	 	998,000	 	 	998,000	 	 	
Total other assets	 	 	3,704	 	 	3,393	 	 	1,611	 	 	161,322	 	 	133,615	 	 	133,615	 	 	
Total assets	 	 	15,605	 	 	87,375	 	 	415,465	 	 	1,022,057	 	 	1,691,535	 	 	1,691,535	 	 	
Total current liabilities	 	 	1,436	 	 	28,574	 	 	68,698	 	 	139,647	 	 	482,057	 	 	482,057	 	 	
Total long-term liabilities	 	 	—	 	 	—	 	 	444	 	 	287,022	 	 	845,383	 	 	845,383	 	 	
Total convertible preferred units	 	 	61,952	 	 	167,000	 	 	499,656	 	 	813,244	 	 	978,506	 	 	—	 	 	
Total unit holdings/shareholders' equity	 	 	(47,783	)	 	(108,199	)	 	(153,333	)	 	(217,856	)	 	(614,411	)	 	364,095	 	 	
Total liabilities, convertible preferred units and unit holdings/shareholders' equity	 	 	15,605	 	 	87,375	 	 	415,465	 	 	1,022,057	 	 	1,691,535	 	 	1,691,535	 	 	

(1)
Includes the effect of our corporate reorganization and the effect of this offering as described in "Corporate Reorganization," "Capitalization" and "Dilution."

Consolidated Statements of Cash Flows Information:

	 	 

	 	 
	 	 
	 	Period
April 23, 2003
(Inception)
through
December 31
2010	 	 	
 
	 	Year Ended December 31	 	 	 	 	 	
 
	 	2006	 	2007	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands)

Net cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	$	(9,617	)	$	(17,386	)	$	(65,671	)	$	(27,591	)	$	(191,800	)	$	(331,009	)	 	 	
Investing activities	 	 	(14,663	)	 	(58,161	)	 	(156,882	)	 	(500,393	)	 	(589,975	)	 	(1,329,026	)	 	 	
Financing activities	 	 	19,768	 	 	104,973	 	 	331,084	 	 	519,695	 	 	742,685	 	 	1,760,450	 	 	 	
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RISK FACTORS

        An investment in our common shares involves a high degree of risk. You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this prospectus, including the consolidated financial statements and the related notes appearing at the end of this prospectus, before deciding to invest in our common shares. If any of the following risks actually occurs, our business, business prospects, financial condition, results of operations or cash flows could be materially adversely affected. In any such case, the trading price of our common shares could decline, and you could lose all or part of your investment. The risks below are not the only ones facing our company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us. This prospectus also contains forward-looking statements, estimates and projections that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements as a result of specific factors, including the risks described below.
Risks Relating to Our Business

We have limited proved reserves and areas that we decide to drill may not yield oil and natural gas in commercial quantities or quality, or at all.

        We have limited proved reserves. The majority of our oil and natural gas portfolio consists of discoveries without approved PoDs and with limited well penetrations, as well as identified yet unproven prospects based on available seismic and geological information that indicates the potential presence of hydrocarbons. However, the areas we decide to drill may not yield oil or natural gas in commercial quantities or quality, or at all. Most of our current discoveries and prospects are in various stages of evaluation that will require substantial additional analysis and interpretation. Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. Exploratory wells have been drilled on a limited number of our prospects and while we have drilled appraisal wells on all of our discoveries, additional wells may be required to fully appraise these discoveries. Accordingly, we do not know if any of our discoveries or prospects will contain oil or natural gas in sufficient quantities or quality to recover drilling and completion costs or to be economically viable. Even if oil or natural gas is found on our discoveries or prospects in commercial quantities, construction costs of gathering lines, subsea infrastructure and floating production systems and transportation costs may prevent such discoveries or prospects from being economically viable, and approval of PoDs by various regulatory authorities, a necessary step in order to designate a discovery as "commercial," may not be forthcoming. Additionally, the analogies drawn by us using available data from other wells, more fully explored discoveries or producing fields may not prove valid with respect to our drilling prospects. We may terminate our drilling program for a discovery or prospect if data, information, studies and previous reports indicate that the possible development of a discovery or prospect is not commercially viable and, therefore, does not merit further investment. If a significant number of our discoveries or prospects do not prove to be successful, our business, financial condition and results of operations will be materially adversely affected.

        The deepwater offshore Ghana, an area in which we focus a substantial amount of our exploration, appraisal and development efforts, has only recently been considered potentially economically viable for hydrocarbon production due to the costs and difficulties involved in drilling for oil at such depths and the relatively recent discovery of commercial quantities of oil in the region. Likewise, the deepwater offshore Morocco has not yet proved to be an economically viable production area as to date there has not been a commercially successful discovery or production in this region. We have limited proved reserves and we may not be successful in developing additional commercially viable production from our other discoveries and prospects in Africa.

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We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects.

        In this prospectus we provide numerical and other measures of the characteristics, including with regard to size and quality, of our discoveries and prospects. These measures may be incorrect, as the accuracy of these measures is a function of available data, geological interpretation and judgment. To date, a limited number of our prospects have been drilled. Any analogies drawn by us from other wells, discoveries or producing fields may not prove to be accurate indicators of the success of developing proved reserves from our discoveries and prospects. Furthermore, we have no way of evaluating the accuracy of the data from analog wells or prospects produced by other parties which we may use.

        It is possible that few or none of our wells to be drilled will find accumulations of hydrocarbons in commercial quality or quantity. Any significant variance between actual results and our assumptions could materially affect the quantities of hydrocarbons attributable to any particular prospect. In this prospectus, we refer to the "mean" of the estimated data. This measurement is statistically calculated based on a range of possible outcomes of such estimates, with such ranges being particularly large in scope. Therefore, there may be large discrepancies between the mean estimate provided in this prospectus and our actual results.

Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.

        Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services or unanticipated geologic conditions. Before a well is spud, we incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Drilling may be unsuccessful for many reasons, including geologic conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Exploratory wells bear a much greater risk of loss than development wells. In the past we have experienced unsuccessful drilling efforts; having drilled one dry hole on a license area we previously held in Benin and two dry holes on our current license areas in Ghana, and also having drilled one well in Nigeria and one in Cameroon, both of which encountered hydrocarbons in sub-commercial quantities and accordingly were not subsequently developed. Furthermore, the successful drilling of a well does not necessarily result in the commercially viable development of a field. A variety of factors, including geologic and market-related, can cause a field to become uneconomic or only marginally economic. Many of our prospects that may be developed require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. The successful drilling of a single well may not be indicative of the potential for the development of a commercially viable field. In Africa we face higher above-ground risks necessitating higher expected returns, the requirement for increased capital expenditures due to a general lack of infrastructure and underdeveloped oil and gas industries, and increased transportation expenses due to geographic remoteness, which either require a single well to be exceptionally productive, or the existence of multiple successful wells, to allow for the development of a commercially viable field. See "—Our operations may be adversely affected by political and economic circumstances in the countries in which we operate." Furthermore, if our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

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Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

        Our management team has identified and scheduled drilling locations on our license areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including the availability of equipment and capital, approval by block partners and regulators, seasonal conditions, oil prices, assessment of risks, costs and drilling results. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this prospectus as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. As such, our actual drilling activities may be materially different from our current expectations, which could adversely affect our results of operations and financial condition.

Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects.

        In order to protect our exploration and production rights in our license areas, we must meet various drilling and declaration requirements. In general, unless we make and declare discoveries within certain time periods specified in our various petroleum agreements and licenses, our interests in the undeveloped parts of our license areas may lapse. Should the prospects we have identified in this prospectus under the license agreements currently in place (or, with respect to the Boujdour Offshore Block, expected to be entered shortly) yield discoveries, we cannot assure you that we will not face delays in drilling these prospects or otherwise have to relinquish these prospects. The costs to maintain licenses over such areas may fluctuate and may increase significantly since the original term, and we may not be able to renew or extend such licenses on commercially reasonable terms or at all. Our actual drilling activities may therefore materially differ from our current expectations, which could adversely affect our business.

        Regarding our licenses in Ghana, the petroleum agreement covering the WCTP Block (the "WCTP Petroleum Agreement") extends for a period of 30 years from its effective date; however, in July 2011, the end of the exploration phase, we are required to relinquish the parts of the WCTP Block that we have not declared a discovery area or a development area over. We and the other block partners have a right to negotiate a new petroleum agreement with respect to these undeveloped parts of the WCTP Block, but we cannot assure you that any such new agreement will either be entered into or be on the same terms as the current WCTP Petroleum Agreement. The petroleum agreement covering the DT Block (the "DT Petroleum Agreement") also extends for a period of 30 years from its effective date and contains similar relinquishment provisions to the WCTP Petroleum Agreement, but with the end of the exploration phase occurring in January 2013. We and the other block partners also have a right to negotiate a new petroleum agreement with respect to the undeveloped parts of the DT Block, but we cannot assure you that any such new agreement will either be entered into or be on the same terms as the current DT Petroleum Agreement.

        Regarding our licenses in Cameroon, under the existing permit, contract of association and convention of establishment which we assigned into (together, the "Kombe-N'sepe License Agreements"), the exploration phase to the Kombe-N'sepe Block expires on June 30, 2011. The Kombe-N'sepe License Agreements provide for a subsequent two-year exploration period, but whether we enter such period will not be determined until after we analyze the results of our second exploration well on the Kombe-N'sepe Block spud in early 2011 and currently being drilled. Under the

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production sharing contract covering the Ndian River Block (the "Ndian River Production Sharing Contract"), the initial exploration phase to the Ndian River Block expired on November 20, 2010. On September 16, 2010, in compliance with the Ndian River Production Sharing Contract, we applied to Cameroon's Minister of Industry, Mines, and Technological Development for a two-year renewal of the exploration period (the first of two additional exploration periods of two years each). This application suspends the termination of the license until approval is obtained and upon submission of the application we were required to relinquish 30% of the original license area of the Ndian River Block.

        Regarding our license in Morocco, under the petroleum agreement covering the Boujdour Offshore Block (the "Boujdour Offshore Petroleum Agreement"), the most recent exploration phase expired on February 26, 2011, however, we entered a memorandum of understanding with ONHYM to enter a new petroleum agreement covering the highest potential areas of this block under essentially the same terms as the original license. Accordingly, the acreage covered by any new petroleum agreement will be less than the acreage covered by the original Boujdour Offshore Petroleum Agreement.

        For each of these license areas, we cannot assure you that any renewals or extensions will be granted or whether any new agreements will be available on commercially reasonable terms, or, in some cases, at all.

The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results.

        We may be liable for certain costs if third parties who contract with us are unable to meet their commitments under such agreements. We are currently exposed to credit risk through joint interest receivables from our block and/or unit partners. If any of our partners in the blocks or unit in which we hold interests are unable to fund their share of the exploration and development expenses, we may be liable for such costs. In the past, certain of our WCTP and DT Block partners have not paid their share of block costs in the time frame required by the joint operating agreements for these blocks. This has resulted in such party being in default, which in return requires Kosmos and its non-defaulting block partners to pay their proportionate share of the defaulting party's costs during the default period. Should a default not be cured, Kosmos could be required to pay its share of the defaulting party's costs going forward. One of our WCTP Block partners, the EO Group, is currently in default under the joint operating agreement for the WCTP Block for failure to pay its share of block costs and expenses. Under the terms of the joint operating agreement, the non-defaulting block partners have the right to require the EO Group to forfeit its interest in the WCTP Block and the Jubilee Unit, and each non-defaulting block partner has the pro rata right to assume such interest. Should we choose to participate in such assumption, we would incur the costs associated therein. Should we choose not to participate, our block and unit partners may increase their respective interests in the WCTP Block and Jubilee Unit.

        Furthermore, MODEC, Inc. ("MODEC"), the contractor for the FPSO we are using to produce hydrocarbons from the Jubilee Field, has made a disclosure regarding matters which may give rise to potential violations by MODEC under the U.S. Foreign Corrupt Practices Act ("FCPA") and other similar anti-corruption legislation. The Jubilee Unit partners as well as the International Finance Corporation ("IFC") are working with MODEC and its legal advisors to investigate this matter. As a result of these concerns, MODEC's long-term funding from a syndicate of international banks for the repayment of funds originally loaned by us, Tullow and Anadarko for the financing of the construction of such FPSO has been suspended pending this investigation. If MODEC cannot access such funding arrangements or otherwise source alternative funding, we may not be repaid for these amounts owed to us. As MODEC's parent is a Japanese company listed on the Tokyo Stock Exchange, the recent earthquake and tsunami affecting Japan and the resulting crisis concerning the Japanese nuclear power plants may adversely affect MODEC's financial position. In addition, in order to continue the

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production activities on the Jubilee Unit, we may be required to contribute further funds before September 15, 2011 in order to purchase the FPSO or find an alternative funding source or buyer. If we were unable to do so and lost access to the MODEC FPSO, we would be unable to produce hydrocarbons from the Jubilee Field unless and until we arranged access to an alternative FPSO.

        Our principal exposure to credit risk will be through receivables resulting from the sale of our oil, which we plan to market to energy marketing companies and refineries, and to cover our commodity derivatives contracts. The inability or failure of our significant customers or counter-parties to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Joint interest receivables arise from our block partners. The inability or failure of third parties we contract with to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

The unit partners' respective interests in the Jubilee Unit are subject to redetermination and our interests in such unit may decrease as a result.

        The interests in and development of the Jubilee Unit are governed by the terms of the UUOA. The parties to the UUOA, the collective interest holders in each of the WCTP and DT Blocks, initially agreed that interests in the Jubilee Unit will be shared equally, with each block deemed to contribute 50% of the area of such unit. The respective interests in the Jubilee Unit were therefore determined by the respective interests in such contributed block interests. Pursuant to the terms of the UUOA, the percentage of such contributed interests is subject to a process of redetermination once sufficient development work has been completed in the unit. The redetermination process is currently underway, however, we do not expect it to be concluded in the near term. We cannot assure you that any redetermination pursuant to the terms of the UUOA will not negatively affect our interests in the Jubilee Unit or that such redetermination will be satisfactorily resolved.

We are not, and may not be in the future, the operator on all of our license areas and do not, and may not in the future, hold all of the working interests in certain of our license areas. Therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and to an extent, any non-wholly owned, assets.

        As we carry out our exploration and development programs, we have arrangements with respect to existing license areas and may have agreements with respect to future license areas that result in a greater proportion of our license areas being operated by others. Currently, we are not the Unit Operator on the Jubilee Field and do not hold operatorship in one of our two blocks offshore Ghana (the DT Block) or on one of our two blocks in Cameroon (the Kombe-N'sepe Block). In addition, the terms of the UUOA governing the unit partners' interests in the Jubilee Field require certain actions be approved by at least 80% of the unit voting interests and the terms of our other current or future license or venture agreements may require at least the majority of working interests to approve certain actions. As a result, we may have limited ability to exercise influence over the operations of the discoveries or prospects operated by our block or unit partners, or which are not wholly owned by us, as the case may be. Dependence on block or unit partners could prevent us from realizing our target returns for those discoveries or prospects. Further, because we do not have majority ownership in all of our properties we may not be able to control the timing of exploration or development activities or the amount of capital expenditures and, therefore, may not be able to carry out one of our key business strategies of minimizing the cycle time between discovery and initial production. The success and timing of exploration and development activities operated by our block partners will depend on a number of factors that will be largely outside of our control, including:

•
the timing and amount of capital expenditures;

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•
the operator's expertise and financial resources;

•
approval of other block partners in drilling wells;

•
the scheduling, pre-design, planning, design and approvals activities and processes;

•
selection of technology; and

•
the rate of production of reserves, if any.

        This limited ability to exercise control over the operations on some of our license areas may cause a material adverse effect on our financial condition and results of operations.

We have been, until recently, a development stage entity and our future performance is uncertain.

        We were a development stage entity until we first generated revenue in early 2011. Development stage entities face substantial business risks and may suffer significant losses. We have generated substantial net losses and negative cash flows from operating activities since our inception and expect to continue to incur substantial net losses as we continue our exploration and appraisal program. We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. As a new public company, we will need to develop additional business relationships, establish additional operating procedures, hire additional staff, and take other measures necessary to conduct our intended business activities. We may not be successful in implementing our business strategies or in completing the development of the facilities necessary to conduct our business as planned. In the event that one or more of our drilling programs is not completed, is delayed or terminated, our operating results will be adversely affected and our operations will differ materially from the activities described in this prospectus. There are uncertainties surrounding our future business operations which must be navigated as we transition from a development stage entity and commence generating revenues, some of which may cause a material adverse effect on our results of operations and financial condition.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

        The process of estimating oil and natural gas reserves is technically complex. It requires interpretations of available technical data and many assumptions, including those relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this prospectus. See "Business—Our Reserves" for information about our estimated oil and natural gas reserves and the PV-10 and Standardized Measure of discounted future net revenues (as defined herein) as of December 31, 2010.

        In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

        Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

        You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with new U.S. Securities and Exchange Commission ("SEC") requirements, we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas assets will be affected by factors such as:

•
actual prices we receive for oil and natural gas;

•
actual cost of development and production expenditures;

•
derivative transactions;

•
the amount and timing of actual production; and

•
changes in governmental regulations or taxation.

        The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas assets will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

        Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus. If oil prices decline by $1.00 per bbl, then the present value of our net revenues at a 10% discount rate ("PV-10") and the Standardized Measure as of February 3, 2011 would each decrease by approximately $23.0 million. See "Business—Our Reserves."

We are dependent on certain members of our management and technical team.

        Investors in our common shares must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, discovering, evaluating and developing reserves. Our performance and success are dependent, in part, upon key members of our management and technical team, and their loss or departure could be detrimental to our future success. In making a decision to invest in our common shares, you must be willing to rely to a significant extent on our management's discretion and judgment. A significant amount of the pre-offering interests in Kosmos held by members of our management and technical team will be vested at the time of this offering. While a new equity incentive plan will be in place following this offering, there can be no assurance that our management and technical team will remain in place. The loss of any of our management and technical team members could have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common shares. See "Management."

Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms in the future, which may in turn limit our ability to develop our exploration, appraisal, development and production activities.

        We expect our capital outlays and operating expenditures to be substantial over the next several years as we expand our operations. Obtaining seismic data, as well as exploration, appraisal, development and production activities entail considerable costs, and we expect that we will need to

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raise substantial additional capital, through future private or public equity offerings, strategic alliances or additional debt financing.

        Our future capital requirements will depend on many factors, including:

•
the scope, rate of progress and cost of our exploration, appraisal, development and production activities;

•
oil and natural gas prices;

•
our ability to locate and acquire hydrocarbon reserves;

•
our ability to produce oil or natural gas from those reserves;

•
the terms and timing of any drilling and other production-related arrangements that we may enter into;

•
the cost and timing of governmental approvals and/or concessions; and

•
the effects of competition by larger companies operating in the oil and gas industry.

        We do not currently have any commitments for future external funding beyond the capacity of our commercial debt facility (including the accordion therein). Additional financing may not be available on favorable terms, or at all. Even if we succeed in selling additional securities to raise funds, at such time the ownership percentage of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we choose to farm-out interests in our licenses, we would dilute our ownership interest subject to the farm-out and any potential value resulting therefrom, and may lose operating control or influence over such license areas.

        Assuming we are able to commence exploration, appraisal, development and production activities or successfully exploit our licenses during the exploratory term, our interests in our licenses (or the development/production area of such licenses as they existed at that time, as applicable) would extend beyond such term for a fixed period or life of production, depending on the jurisdiction. If we are unable to meet our well commitments and/or declare development of the prospective areas of our licenses during this time, we may be subject to significant potential forfeiture of all or part of the relevant license interests. If we are not successful in raising additional capital, we may be unable to continue our exploration and production activities or successfully exploit our license areas, and we may lose the rights to develop these areas upon the expiration of exploratory terms. See "—Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects."

A substantial or extended decline in both global and local oil and natural gas prices may adversely affect our business, financial condition and results of operations.

        The prices that we will receive for our oil and natural gas will significantly affect our revenue, profitability, access to capital and future growth rate. Historically, the oil and natural gas markets have been volatile and will likely continue to be volatile in the future. The prices that we will receive for our production and the levels of our production depend on numerous factors. These factors include, but are not limited to, the following:

•
changes in supply and demand for oil and natural gas;

•
the actions of the Organization of the Petroleum Exporting Countries ("OPEC");

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•
speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;

•
global economic conditions;

•
political and economic conditions, including embargoes in oil-producing countries or affecting other oil-producing activities, particularly in the Middle East, Africa, Russia and South America;

•
the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

•
the level of global oil and natural gas exploration and production activity;

•
the level of global oil inventories and oil refining capacities;

•
weather conditions and natural disasters;

•
technological advances affecting energy consumption;

•
governmental regulations and taxation policies;

•
proximity and capacity of transportation facilities;

•
the price and availability of competitors' supplies of oil and natural gas; and

•
the price and availability of alternative fuels.

        Lower oil prices may not only decrease our revenues on a per share basis but also may reduce the amount of oil that we can produce economically. A substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas assets and this could result in reduced availability under our commercial debt facility.

        We will review our proved oil and natural gas assets for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of appraisal and development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas assets. A write-down constitutes a non-cash charge to earnings.

        In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. Redeterminations may occur as a result of a variety of factors, including the commodity price assumptions, assumptions regarding future production from our oil and natural gas assets, or assumptions concerning our future holdings of proved reserves. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

We may not be able to commercialize our interests in any natural gas produced from our license areas in West Africa.

        The development of the market for natural gas in West Africa is in its early stages. Currently the infrastructure to transport and process natural gas on commercial terms is limited and the expenses associated with constructing such infrastructure ourselves may not be commercially viable given local

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prices currently paid for natural gas. Accordingly, there may be limited or no value derived from any natural gas produced from our West African license areas.

Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production.

        Our ability to market our oil production will depend substantially on the availability and capacity of processing facilities, oil tankers and other infrastructure, including FPSOs, owned and operated by third parties. Our failure to obtain such facilities on acceptable terms could materially harm our business. We also rely on continuing access to drilling rigs suitable for the environment in which we operate. The delivery of drilling rigs may be delayed or cancelled, and we may not be able to gain continued access to suitable rigs in the future. We may be required to shut in oil wells because of the absence of a market or because access to processing facilities may be limited or unavailable. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market, which could cause a material adverse effect on our financial condition and results of operations.

        Additionally, the future exploitation and sale of associated and non-associated natural gas and liquids will be subject to timely commercial processing and marketing of these products, which depends on the contracting, financing, building and operating of infrastructure by third parties. The Government of Ghana has expressed an intention to build a gas pipeline from the Jubilee Field to transport such natural gas to the mainland for processing and sale, however, to date, the planning and execution of such pipeline is in its early stages. Even if such pipeline is constructed, it would only give us access to a limited natural gas market. In addition, in connection with the approval of the Jubilee Phase 1 PoD, we granted the first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to Ghana at no cost. We have not been issued a permit from the Ghana Environmental Protection Agency ("Ghana EPA") to flare natural gas produced from the Jubilee Field in the long-term. The Jubilee Phase 1 PoD provided an initial period during commencement of production for which natural gas could be flared. Subsequent to such period, the Jubilee Phase 1 PoD provided that a portion of the natural gas would be reinjected and the balance of the natural gas would be transported to shore via the pipeline to be built. While reinjection improves the recoverability of oil from such reservoirs in the short term, in order to maintain maximum oil production levels, eventually we will need to either flare excess natural gas or otherwise remove it from the reservoirs' production system. In the absence of construction of a natural gas pipeline or if we do not receive a permit to flare such natural gas for the long-term prior to reaching the Jubilee Field Phase 1's reinjection capacity, the field's oil production capacity may be adversely affected.

We are subject to numerous risks inherent to the exploration and production of oil and natural gas.

        Oil and natural gas exploration and production activities involve many risks that a combination of experience, knowledge and interpretation may not be able to overcome. Our future will depend on the success of our exploration and production activities and on the development of infrastructure that will allow us to take advantage of our discoveries. Additionally, many of our license areas are located in deepwater, which generally increases the capital and operating costs, chances of delay, planning time, technical challenges and risks associated with oil and natural gas exploration and production activities. As a result, our oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore or develop discoveries, prospects or licenses will depend in part on the evaluation of seismic data through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.

        Furthermore, the marketability of expected oil and natural gas production from our discoveries and prospects will also be affected by numerous factors. These factors include, but are not limited to,

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market fluctuations of prices, proximity, capacity and availability of processing facilities, transportation vehicles and pipelines, equipment availability and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, domestic supply requirements, importing and exporting of oil and natural gas, environmental protection and climate change). The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital.

        In the event that our currently undeveloped discoveries and prospects are developed and become operational, they may not produce oil and natural gas in commercial quantities or at the costs anticipated, and our projects may cease production, in part or entirely, in certain circumstances. Discoveries may become uneconomic as a result of an increase in operating costs to produce oil and natural gas. Our actual operating costs may differ materially from our current estimates. Moreover, it is possible that other developments, such as increasingly strict environmental, climate change, health and safety laws and regulations and enforcement policies thereunder and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities, delays, an inability to complete the development of our discoveries or the abandonment of such discoveries, which could cause a material adverse effect on our financial condition and results of operations.

We are subject to drilling and other operational environmental hazards.

        The oil and natural gas business involves a variety of operating risks, including, but not limited to:

•
fires, blowouts, spills, cratering and explosions;

•
mechanical and equipment problems, including unforeseen engineering complications;

•
uncontrolled flows or leaks of oil, well fluids, natural gas, brine, toxic gas or other pollution;

•
gas flaring operations;

•
marine hazards with respect to offshore operations;

•
formations with abnormal pressures;

•
pollution, other environmental risks, and geological problems; and

•
weather conditions and natural disasters.

        These risks are particularly acute in deepwater drilling and exploration. Any of these events could result in loss of human life, significant damage to property, environmental or natural resource damage, impairment, delay or cessation of our operations, adverse publicity, substantial losses and civil or criminal liability. In accordance with customary industry practice, we expect to maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events, whether or not covered by insurance, could have a material adverse effect on our financial position and results of operations.

The development schedule of oil and natural gas projects, including the availability and cost of drilling rigs, equipment, supplies, personnel and oilfield services, is subject to delays and cost overruns.

        Historically, some oil and natural gas development projects have experienced delays and capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential equipment, supplies, personnel and oilfield services. The cost to develop our projects has not been fixed and remains dependent upon a number of factors, including the completion of detailed cost estimates and final engineering, contracting and procurement costs. Our construction and operation schedules may not proceed as planned and may experience delays or cost overruns. Any delays may increase the costs of the projects, requiring additional capital, and such capital may not be available in a timely and cost-effective fashion.

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Our offshore and deepwater operations will involve special risks that could adversely affect our results of operations.

        Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, sinking, collisions and damage or loss to pipeline, subsea or other facilities or from weather conditions. We could incur substantial expenses that could reduce or eliminate the funds available for exploration, development or license acquisitions, or result in loss of equipment and license interests.

        Deepwater exploration generally involves greater operational and financial risks than exploration in shallower waters. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of equipment failure and usually higher drilling costs. In addition, there may be production risks of which we are currently unaware. If we participate in the development of new subsea infrastructure and use floating production systems to transport oil from producing wells, these operations may require substantial time for installation or encounter mechanical difficulties and equipment failures that could result in significant liabilities, cost overruns or delays. Furthermore, deepwater operations generally, and operations in West Africa in particular, lack the physical and oilfield service infrastructure present in other regions. As a result, a significant amount of time may elapse between a deepwater discovery and the marketing of the associated oil and natural gas, increasing both the financial and operational risks involved with these operations. Because of the lack and high cost of this infrastructure, further discoveries we may make in West Africa may never be economically producible.

We had disagreements with the Republic of Ghana and the Ghana National Petroleum Corporation regarding certain of our rights and responsibilities under the WCTP and DT Petroleum Agreements.

        All of our proved reserves and our discovered fields are located offshore Ghana. The WCTP Petroleum Agreement and the DT Petroleum Agreement cover the two blocks that form the basis of our exploration, development and production operations in Ghana. Pursuant to these petroleum agreements, most significant decisions, including our plans for development and annual work programs, must be approved by GNPC and/or Ghana's Ministry of Energy. We previously had disagreements with Ghana and GNPC regarding certain of our rights and responsibilities under these petroleum agreements, the Petroleum Law of 1984 (PNDCL 84) (the "Ghanaian Petroleum Law") and the Internal Revenue Act, 2000 (Act 592) (the "Ghanaian Tax Law"). These included disagreements over sharing information with prospective purchasers of our interests, pledging our interests to finance our development activities, potential liabilities arising from discharges of small quantities of drilling fluids into Ghanaian territorial waters, the failure to approve the proposed sale of our Ghanaian assets and assertions that could be read to give rise to taxes payable under the Ghanaian Tax Law in connection with this offering. In addition, we were requested to provide information to Ghana's Ministry of Justice in connection with its investigation of the EO Group, however, we are not a subject of this investigation. These past disagreements have been resolved. In connection with resolving certain of these disagreements, we entered into a settlement agreement with GNPC and the Government of Ghana in December 2010. As part of such agreement and with respect to one particular issue, we agreed to pay GNPC $8 million upon signing the settlement agreement and $15 million upon the first to occur of certain liquidity events, including the successful completion of this offering. These past disagreements did not and are not expected to materially affect our operations, exploration or development activities.

        There can be no assurance that future disagreements will not arise with any host government and/or national oil companies that may have a material adverse effect on our exploration or development activities, our ability to operate, our rights under our licenses and local laws or our rights to monetize our interests.

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The geographic concentration of our licenses in West Africa subjects us to an increased risk of loss of revenue or curtailment of production from factors specifically affecting West Africa.

        Our current exploration licenses are concentrated in one principal region: West Africa. Some or all of these licenses could be affected should such region experience any of the following factors (among others):

•
severe weather or natural disasters or other acts of God;

•
delays or decreases in production, the availability of equipment, facilities, personnel or services;

•
delays or decreases in the availability of capacity to transport, gather or process production; and/or

•
military conflicts.

        For example, oil and natural gas operations in Africa may be subject to higher political and security risks than those operations under the sovereignty of the United States. We plan to maintain insurance coverage for only a portion of risks we face from doing business in these regions. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss.

        Due to the concentrated nature of our portfolio of licenses, a number of our licenses could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of licenses.

Our operations may be adversely affected by political and economic circumstances in the countries in which we operate.

        Oil and natural gas exploration, development and production activities are subject to political and economic uncertainties (including but not limited to changes in energy policies or the personnel administering them), changes in laws and policies governing operations of foreign based companies, expropriation of property, cancellation or modification of contract rights, revocation of consents or approvals, obtaining various approvals from regulators, foreign exchange restrictions, currency fluctuations, royalty increases and other risks arising out of foreign governmental sovereignty, as well as risks of loss due to civil strife, acts of war, guerrilla activities, terrorism, acts of sabotage, territorial disputes and insurrection. In addition, we are subject both to uncertainties in the application of the tax laws in the countries in which we operate and to possible changes in such tax laws (or the application thereof), each of which could result in an increase in our tax liabilities. These risks may be higher in the developing countries in which we conduct our activities.

        Our operations in these areas increase our exposure to risks of war, local economic conditions, political disruption, civil disturbance, expropriation, piracy, tribal conflicts and governmental policies that may:

•
disrupt our operations;

•
require us to incur greater costs for security;

•
restrict the movement of funds or limit repatriation of profits;

•
lead to U.S. government or international sanctions; or

•
limit access to markets for periods of time.

        Some countries in West and North Africa have experienced political instability in the past or are currently experiencing instability. Disruptions may occur in the future, and losses caused by these

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disruptions may occur that will not be covered by insurance. Consequently, our offshore West Africa exploration, development and production activities may be substantially affected by factors which could have a material adverse effect on our results of operations and financial condition. Furthermore, in the event of a dispute arising from non-U.S. operations, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the United States, which could adversely affect the outcome of such dispute.

        Our operations may also be adversely affected by laws and policies of the jurisdictions, including Ghana, Cameroon, Morocco, the United States, the United Kingdom, Bermuda and the Cayman Islands and other jurisdictions in which we do business, that affect foreign trade and taxation. Changes in any of these laws or policies or the implementation thereof, could materially and adversely affect our financial position, results of operations and cash flows.

A portion of our asset portfolio is in Western Sahara, and we could be adversely affected by the political, economic, and military conditions in that region. Our exploration licenses in this region conflict with exploration licenses issued by the Sahrawai Arab Democratic Republic.

        Morocco claims the territory of Western Sahara, where our Boujdour Offshore Block is geographically located, as part of the Kingdom of Morocco, and it has de facto  administrative control of approximately 80% of Western Sahara. However, Western Sahara is on the United Nations list of Non-Self-Governing territories, and the territory's sovereignty has been in dispute since 1975. The Polisario Front, representing the Sahrawai Arab Democratic Republic (the "SADR"), has a conflicting claim of sovereignty over Western Sahara. No countries have formally recognized Morocco's claim to Western Sahara, although some countries implicitly support Morocco's position. Other countries have formally recognized the SADR, but the UN has not. A UN-administered cease-fire has been in place since 1991, and while there have been intermittent UN-sponsored talks, the dispute remains stalemated. It is uncertain when and how Western Sahara's sovereignty issues will be resolved.

        We own a 75% working interest in the Boujdour Offshore Block located geographically offshore Western Sahara. Our license was granted by the government of Morocco. The SADR has issued its own offshore exploration licenses which conflict with our licenses. As a result of SADR's conflicting claim of rights to oil and natural gas licenses granted by Morocco, and the SADR's claims that Morocco's exploitation of Western Sahara's natural resources violates international law, our interests could decrease in value or be lost. Any political instability, terrorism, changes in government, or escalation in hostilities involving the SADR, Morocco, or neighboring states could adversely affect our operations and assets. In addition, Morocco has recently experienced political and social disturbances that could affect its legal and administrative institutions. A change in U.S. foreign policy or the policies of other countries regarding Western Sahara could also adversely affect our operations and assets. We are not insured against political or terrorism risks because management deems the premium costs of such insurance to be currently prohibitively expensive.

        Furthermore, various activist groups have mounted public relations campaigns to force companies to cease and divest operations in Western Sahara, and we could come under similar public pressure. Some investors have refused to invest in companies with operations in Western Sahara, and we could be subject to similar pressure, particularly as we become a public company. Any of these factors could have a material adverse effect on our results of operations and financial condition.

Maritime boundary demarcation between Côte D'Ivoire and Ghana may affect a portion of our license areas.

        In early 2010, Ghana's western neighbor, the Republic of Côte d'Ivoire, petitioned the United Nations to demarcate the Ivorian territorial maritime boundary with Ghana. In response to the petition, Ghana established a Boundary Commission to undertake negotiations in order to determine Ghana's land and maritime boundaries. Meetings between the Ghanaian Boundary Commission and

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Ivorian delegates concerning the boundary demarcation occurred in April 2010, although the results of the meeting were not announced and the issue remains unresolved at present. The Ghanaian-Ivorian maritime boundary forms the western boundary of the DT Block offshore Ghana. Uncertainty remains with regard to the outcome of the boundary demarcation between Ghana and Côte d'Ivoire and we do not know if the maritime boundary will change, therefore affecting our rights to explore and develop our discoveries or prospects within such areas.

The oil and gas industry, including the acquisition of exploratory licenses in West Africa, is intensely competitive and many of our competitors possess and employ substantially greater resources than us.

        The international oil and gas industry, including in West Africa, is highly competitive in all aspects, including the exploration for, and the development of, new license areas. We operate in a highly competitive environment for acquiring exploratory licenses and hiring and retaining trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than us, which can be particularly important in the areas in which we operate. These companies may be better able to withstand the financial pressures of unsuccessful drill attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable licenses and to consummate transactions in a highly competitive environment. Also, there is substantial competition for available capital for investment in the oil and gas industry. As a result of these and other factors, we may not be able to compete successfully in an intensely competitive industry, which could cause a material adverse effect on our results of operations and financial condition.

Participants in the oil and gas industry are subject to numerous laws that can affect the cost, manner or feasibility of doing business.

        Exploration and production activities in the oil and gas industry are subject to local laws and regulations. We may be required to make large expenditures to comply with governmental laws and regulations, particularly in respect of the following matters:

•
licenses for drilling operations;

•
tax increases, including retroactive claims;

•
unitization of oil accumulations;

•
local content requirements (including the mandatory use of local partners and vendors); and

•
environmental requirements and obligations, including remediation or investigation activities.

        Under these and other laws and regulations, we could be liable for personal injuries, property damage and other types of damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change, or their interpretations could change, in ways that could substantially increase our costs. These risks may be higher in the developing countries in which we conduct our operations, where there could be a lack of clarity or lack of consistency in the application of these laws and regulations. Any resulting liabilities, penalties, suspensions or terminations could have a material adverse effect on our financial condition and results of operations.

        For example, Ghana's Parliament is considering the enactment of a new Petroleum Exploration and Production Act and a new Petroleum Revenue Management Act. There can be no assurance that the final laws will not seek to retroactively modify the terms of the agreements governing our license interests in Ghana, including the WCTP and DT Petroleum Agreements and the UUOA, require

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governmental approval for transactions that effect a direct or indirect change of control of our license interests or otherwise affect our current and future operations in Ghana. Any such changes may have a material adverse affect on our business. We also cannot assure you that government approval will not be needed for direct or indirect transfers of our petroleum agreements or other license interests under existing legislation. See "Business—Other Regulation of the Oil and Gas Industry—Ghana."

        Furthermore, the explosion and sinking in April 2010 of theDeepwater Horizon oil rig during operations on the Macondo exploration well in the Gulf of Mexico, and the resulting oil spill, may have increased certain of the risks faced by those drilling for oil in deepwater regions, including, without limitation, the following:

•
increased industry standards, governmental regulation and enforcement of our and our industry's operations in a number of areas, including health and safety, financial responsibility, environmental, licensing, taxation, equipment specifications and training requirements;

•
increased difficulty or delays in obtaining rights to drill wells in deepwater regions;

•
higher operating costs;

•
higher insurance costs and increased potential liability thresholds under environmental laws;

•
decreased access to appropriate equipment, personnel and infrastructure in a timely manner;

•
higher capital costs as a result of any increase to the risks we or our industry face; and

•
less favorable investor perception of the risk-adjusted benefits of deepwater offshore drilling.

        The occurrence of any of these factors, or the continuation thereof, could have a material adverse effect on our business, financial position or future results of operations.

We and our operations are subject to numerous environmental, health and safety regulations which may result in material liabilities and costs.

        We and our operations are subject to various international, foreign, federal, state and local environmental, health and safety laws and regulations governing, among other things, the emission and discharge of pollutants into the ground, air or water, the generation, storage, handling, use and transportation of regulated materials and the health and safety of our employees. We are required to obtain environmental permits from governmental authorities for our operations, including drilling permits for our wells. We have not been or may not be at all times in complete compliance with these permits and the environmental laws and regulations to which we are subject, and there is a risk that these laws and regulations could change in the future or become more stringent. If we violate or fail to comply with these laws, regulations or permits, we could be fined or otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or termination of our operations. If we fail to obtain permits in a timely manner or at all (due to opposition from community or environmental interest groups, governmental delays or any other reasons), or if we face additional requirements imposed as a result of changes in or enactment of laws or regulations, such failure to obtain permits or such changes in or enactment of laws could impede or affect our operations, which could have a material adverse effect on our results of operations and financial condition.

        We, as an interest owner or as the designated operator of certain of our current and future discoveries and prospects, could be held liable for some or all environmental, health and safety costs and liabilities arising out of our actions and omissions as well as those of our block partners, third-party contractors or other operators. To the extent we do not address these costs and liabilities or if we do not otherwise satisfy our obligations, our operations could be suspended or terminated. We have contracted with and intend to continue to hire third parties to perform services related to our operations. There is a risk that we may contract with third parties with unsatisfactory environmental,

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health and safety records or that our contractors may be unwilling or unable to cover any losses associated with their acts and omissions. Accordingly, we could be held liable for all costs and liabilities arising out of the acts or omissions of our contractors, which could have a material adverse effect on our results of operations and financial condition.

        We are not fully insured against all risks and our insurance may not cover any or all environmental claims that might arise from our operations or at any of our license areas. If a significant accident or other event occurs and is not covered by insurance, such accident or event could have a material adverse effect on our results of operations and financial condition.

        Releases into deepwater of regulated substances may occur and can be significant. Under certain environmental laws, we could be held responsible for all of the costs relating to any contamination at our facilities and at any third party waste disposal sites used by us or on our behalf. In addition, offshore oil and natural gas exploration and production involves various hazards, including human exposure to regulated substances, which include naturally occurring radioactive and other materials. As such, we could be held liable for any and all consequences arising out of human exposure to such substances or for other damage resulting from the release of hazardous substances to the environment, property or to natural resources, or affecting endangered species.

        In addition, we expect continued and increasing attention to climate change issues. Various countries and regions have agreed to regulate emissions of greenhouse gases, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of oil and natural gas combustion). The regulation of greenhouse gases and the physical impacts of climate change in the areas in which we, our customers and the end-users of our products operate could adversely impact our operations and the demand for our products.

        Environmental, health and safety laws are complex, change frequently and have tended to become increasingly stringent over time. Our costs of complying with current and future climate change, environmental, health and safety laws, the actions or omissions of our block partners and third party contractors and our liabilities arising from releases of, or exposure to, regulated substances may adversely affect our results of operations and financial condition. See "Business—Environmental Matters."

We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act and other anti-corruption laws, and any determination that we violated the U.S. Foreign Corrupt Practices Act or other such laws could have a material adverse effect on our business.

        We are subject to the FCPA and other laws that prohibit improper payments or offers of payments to foreign government officials and political parties for the purpose of obtaining or retaining business. We do business and may do additional business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials. We face the risk of unauthorized payments or offers of payments by one of our employees or consultants. Our existing safeguards and any future improvements may prove to be less than effective in preventing such unauthorized payments, and our employees and consultants may engage in conduct for which we might be held responsible. Violations of the FCPA may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition. In addition, the U.S. government may seek to hold us liable for successor liability FCPA violations committed by companies in which we invest or that we acquire.

        In January 2009, the U.S. Department of Justice ("DOJ") was notified of an alleged possible violation of the FCPA by Kosmos and EO Group and its principals in connection with securing the WCTP Petroleum Agreement. We and our outside FCPA counsel undertook a thorough investigation and found no basis for such allegations and cooperated fully with the DOJ in its investigation. On May 12, 2010, the DOJ notified us through a letter of declination and on June 2, 2010 the DOJ

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notified EO Group and its principals that they presently do not intend to take any enforcement action and have closed their inquiry into this matter. In addition, we were required to provide information to Ghana's Ministry of Justice in connection with its investigation of the EO Group, however, we are not a subject of this investigation.

        MODEC, the contractor for the FPSO for the Jubilee Field Phase 1 development, is being investigated by its legal advisors, the Jubilee Unit partners and the syndicate of international banks who had committed to refinance the construction costs of the FPSO (a portion of such costs were originally loaned by the Jubilee Unit partners, including Kosmos) regarding matters which may give rise to certain FCPA violations. See "Risk Factors—The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results." While we had no prior knowledge of the matters under investigation, should the DOJ launch a formal investigation into these matters, there can be no assurance that the Jubilee Unit partners, including us, would not be subject to enforcement actions which may have a material adverse affect on our business.

We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage.

        We intend to maintain insurance against risks in the operation of the business we plan to develop and in amounts in which we believe to be reasonable. Such insurance, however, may contain exclusions and limitations on coverage. For example, we are not insured against political or terrorism risks. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition and results of operations.

Our derivative activities could result in financial losses or could reduce our income.

        To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we have and may in the future enter into derivative arrangements for a portion of our oil and natural gas production, including puts, collars and fixed-price swaps. In addition, we currently, and may in the future, hold swaps designed to hedge our interest rate risk. We do not currently designate any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

        Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:

•
production is less than the volume covered by the derivative instruments;

•
the counter-party to the derivative instrument defaults on its contract obligations; or

•
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.

        In addition, these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas or beneficial interest rate fluctuations and may expose us to cash margin requirements.

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Our commercial debt facility contains certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.

        Our commercial debt facility includes certain covenants that, among other things, restrict:

•
our investments, loans and advances and certain of our subsidiaries' payment of dividends and other restricted payments;

•
our incurrence of additional indebtedness;

•
the granting of liens, other than liens created pursuant to the commercial debt facilities and certain permitted liens;

•
mergers, consolidations and sales of all or a substantial part of our business or licenses;

•
the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities;

•
the sale of assets (other than production sold in the ordinary course of business); and

•
our capital expenditures that we can fund with our commercial debt facility.

        Our commercial debt facility requires us to maintain certain financial ratios, such as debt service coverage ratios. All of these restrictive covenants may limit our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our commercial debt facility may be impacted by changes in economic or business conditions, our results of operations or events beyond our control. The breach of any of these covenants could result in a default under our commercial debt facility, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under our commercial debt facility, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders, successors or assignees could proceed against their collateral. If the indebtedness under our commercial debt facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.

Our level of indebtedness may increase and thereby reduce our financial flexibility.

        As of December 31, 2010 we had $1.05 billion of indebtedness outstanding under our previous $1.25 billion commercial debt facilities. In March 2011 we entered into a new $2.0 billion commercial debt facility, which may be increased to $3.0 billion upon us obtaining additional commitments. At March 31, 2011 we had $1.3 billion outstanding, $151 million of availability and $700 million of committed undrawn capacity under such facility. In the future, we may incur significant indebtedness in order to make future investments or acquisitions or to explore, appraise or develop our oil and natural gas assets.

        Our level of indebtedness could affect our operations in several ways, including the following:

•
a significant portion of our cash flows, when generated, could be used to service our indebtedness;

•
a high level of indebtedness would increase our vulnerability to general adverse economic and industry conditions;

•
the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

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•
a high level of indebtedness may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

•
our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

•
additional hedging instruments may be required as a result of our indebtedness;

•
a high level of indebtedness may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

•
a high level of indebtedness may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

        A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, risks associated with exploring for and producing oil and natural gas, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our indebtedness and future working capital, borrowings or equity financing may not be available to pay or refinance such indebtedness. Factors that will affect our ability to raise cash through an offering of our equity securities or a refinancing of our indebtedness include financial market conditions, the value of our assets and our performance at the time we need capital.

Our operations could be adversely impacted by our block partner, whose affiliate is involved in the Macondo Gulf of Mexico oil spill.

        In April 2010, an explosion occurred on theDeepwater Horizon oil rig during operations on the Macondo exploration well, following which the oil rig sank and hydrocarbons flowed into the Gulf of Mexico. In response to this event, certain U.S. federal agencies and governmental officials ordered additional inspections of deepwater operations in the Gulf of Mexico. The full cause of the explosion, the extent of the environmental impact and the ultimate costs associated with this event are not yet known.

        Anadarko WCTP Company ("Anadarko WCTP"), an affiliate of Anadarko, which holds a participating interest in the Macondo well, also owns working interests in the WCTP and DT Blocks, including the Jubilee Unit. See "Prospectus Summary—Overview." As a 25% non-operating interest owner in the Macondo well, Anadarko may incur liability under environmental laws and may be required to contribute to the significant and ongoing remediation expenses in the Gulf of Mexico. This event and its aftermath could result in substantial costs to Anadarko and could in turn affect Anadarko WCTP's ability to meet its obligations under the UUOA or the WCTP and DT Petroleum Agreements or related agreements, as the case may be, or necessitate delays in our development activities, which could cause a material adverse effect on our business, results of operations and financial condition.

We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.

        We periodically evaluate acquisitions of prospects and licenses, reserves and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of these assets requires an assessment of several factors, including:

•
recoverable reserves;

•
future oil and natural gas prices and their appropriate differentials;

•
development and operating costs; and

•
potential environmental and other liabilities.

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        The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject assets that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the assets to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We may not be entitled to contractual indemnification for environmental liabilities and could acquire assets on an "as is" basis. Significant acquisitions and other strategic transactions may involve other risks, including:

•
diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

•
the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;

•
difficulty associated with coordinating geographically separate organizations; and

•
the challenge of attracting and retaining personnel associated with acquired operations.

        The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be adversely affected.

        The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and gas industry conditions, or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties, including the assumption of environmental or other liabilities in connection with the acquisition. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.

Because we are a relatively small company, the requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

        As a public company with listed equity securities, we will need to comply with additional laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements

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will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

•
institute a more comprehensive compliance function;

•
design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

•
comply with rules promulgated by the NYSE;

•
prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

•
establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

•
involve and retain to a greater degree outside counsel and accountants in the above activities; and

•
establish an investor relations function.

        In addition, we also expect that being a public company subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.

        Lastly, shortly after the closing of this offering we intend to apply to list our common shares on the GSE, although there can be no assurance that this listing will be completed in a timely manner, or at all. Complying with the regulations and requirements of the GSE may heighten the risks listed above.

Our bye-laws contain a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or future prospects.

        Our bye-laws provide that, to the fullest extent permitted by applicable law, we renounce any right, interest or expectancy in, or in being offered an opportunity to participate in, any business opportunity that may be from time to time be presented to the Investors or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (other than us and our subsidiaries) or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such person shall be liable to us for breach of any statutory, fiduciary, contractual or other duty, as a director or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us unless, in the case of any such person who is our director, such person fails to present any business opportunity that is expressly offered to such person solely in his or her capacity as our director.

        As a result, our directors and Investors and their affiliates may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they or their affiliates have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing of our interest and expectancy in any business opportunity that may be from time to time presented to our directors and Investors and

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their affiliates could adversely impact our business or future prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. See "Description of Share Capital—Corporate Opportunities."

We receive certain beneficial tax treatment as a result of being an exempted company incorporated pursuant to the laws of Bermuda. Changes in that treatment could have a material adverse effect on our net income, our cash flow and our financial condition.

        We are an exempted company incorporated pursuant to the laws of Bermuda and operate through subsidiaries in a number of countries throughout the world. Consequently, we are subject to changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the United States, Bermuda, Ghana, Cameroon, Morocco and other jurisdictions in which we or any of our subsidiaries operate or are resident. Recent legislation has been introduced in the Congress of the United States that is intended to reform the U.S. tax laws as they apply to certain non-U.S. entities and operations, including legislation that would treat a foreign corporation as a U.S. corporation for U.S. federal income tax purposes if substantially all of its senior management is located in the United States. If this or other legislation is passed that ultimately changes our U.S. tax position, it could have a material adverse effect on our net income, our cash flow and our financial condition.

We may become subject to taxes in Bermuda after March 31, 2035, which may have a material adverse effect on our results of operations and your investment.

        The Bermuda Minister of Finance, under the Exempted Undertakings Tax Protection Act 1966 of Bermuda, as amended, has given us an assurance that if any legislation is enacted in Bermuda that would impose tax computed on profits or income, or computed on any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance tax, then the imposition of any such tax will not be applicable to us or any of our operations, shares, debentures or other obligations until March 31, 2035, except insofar as such tax applies to persons ordinarily resident in Bermuda or to any taxes payable by us in respect of real property owned or leased by us in Bermuda. See "Certain Tax Considerations—Bermuda Tax Considerations." Given the limited duration of the Bermuda Minister of Finance's assurance, we cannot assure you that we will not be subject to any Bermuda tax after March 31, 2035.

The impact of Bermuda's letter of commitment to the Organization for Economic Cooperation and Development to eliminate harmful tax practices is uncertain and could adversely affect our tax status in Bermuda.

        The Organization for Economic Cooperation and Development ("OECD") has published reports and launched a global initiative among member and non-member countries on measures to limit harmful tax competition. These measures are largely directed at counteracting the effects of tax havens and preferential tax regimes in countries around the world. According to the OECD, Bermuda is a jurisdiction that has substantially implemented the internationally agreed tax standard and as such is listed on the OECD "white" list. However, we are not able to predict whether any changes will be made to this classification or whether such changes will subject us to additional taxes.

The recent adoption of The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price and other risks associated with our business.

        We use derivative instruments to manage our commodity price risk. The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (the "CFTC") and the SEC to

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promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. In addition, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Lastly, the Dodd-Frank Act requires, no later than 270 days after the enactment of the Act, the SEC to promulgate rules requiring SEC reporting companies that engage in the commercial development of oil, natural gas or minerals, to include in their annual reports filed with the SEC disclosure about all payments (including taxes, royalties, fees and other amounts) made by the issuer or an entity controlled by the issuer to the United States or to any non-U.S. government for the purpose of commercial development of oil, natural gas or minerals. As these rules are not yet effective, we are unable to predict what form these rules may take and whether we will be able to comply with them without adversely impacting our business, or at all. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

We may be a "passive foreign investment company" for U.S. federal income tax purposes, which could create adverse tax consequences for U.S. investors.

        U.S. investors that hold stock in a "passive foreign investment company" ("PFIC") are subject to special rules that can create adverse U.S. federal income tax consequences, including imputed interest charges and recharacterization of certain gains and distributions. Based on management estimates and projections of future revenue, we do not believe that we will be a PFIC for the current taxable year and we do not expect to become one in the foreseeable future. However, if we do not generate significant amounts of gross income from such activities when expected, we may be a PFIC for the current taxable year and for one or more future taxable years. Because PFIC status is a factual determination that is made annually and thus is subject to change, there can be no assurance that we will not be a PFIC for any taxable year. See "Certain Tax Considerations—U.S. Federal Income Tax Considerations—Passive Foreign Investment Company Rules."
Risks Relating to This Offering

An active and liquid trading market for our common shares may not develop.

        Prior to this offering, our common shares were not traded on any market. An active and liquid trading market for our common shares may not develop or be maintained after this offering. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors' purchase and sale orders. The market price of our common shares could vary significantly as

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a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common shares, you could lose a substantial part or all of your investment in our common shares. The initial public offering price will be negotiated between us and representatives of the underwriters and may not be indicative of the market price of our common shares after this offering. Consequently, you may not be able to sell our common shares at prices equal to or greater than the price paid by you in the offering.

Our share price may be volatile, and purchasers of our common shares could incur substantial losses.

        Our share price may be volatile. The stock market in general has experienced extreme volatility that has often been unrelated to the operating performance of particular companies. As a result of this volatility, investors may not be able to sell their common shares at or above the initial public offering price. The market price for our common shares may be influenced by many factors, including, but not limited to:

•
the price of oil and natural gas;

•
the success of our exploration and development operations, and the marketing of any oil and natural gas we produce;

•
regulatory developments in Bermuda, the United States and foreign countries where we operate;

•
the recruitment or departure of key personnel;

•
quarterly or annual variations in our financial results or those of companies that are perceived to be similar to us;

•
market conditions in the industries in which we compete and issuance of new or changed securities;

•
analysts' reports or recommendations;

•
the failure of securities analysts to cover our common shares after this offering or changes in financial estimates by analysts;

•
the inability to meet the financial estimates of analysts who follow our common shares;

•
the issuance of any additional securities of ours;

•
investor perception of our company and of the industry in which we compete; and

•
general economic, political and market conditions.

A substantial portion of our total issued and outstanding common shares may be sold into the market at any time. This could cause the market price of our common shares to drop significantly, even if our business is doing well.

        All of the shares being sold in this offering will be freely tradable without restrictions or further registration under the federal securities laws, unless purchased by our "affiliates" as that term is defined in Rule 144 under the Securities Act. The remaining common shares issued and outstanding upon the closing of this offering are restricted securities as defined in Rule 144 under the Securities Act. Restricted securities may be sold in the U.S. public market only if registered or if they qualify for an exemption from registration, including by reason of Rules 144 or 701 under the Securities Act. All of our restricted shares will be eligible for sale in the public market beginning in 2011, subject in certain circumstances to the volume, manner of sale and other limitations under Rule 144, and also the lock-up agreements described under "Underwriting" in this prospectus. Additionally, we intend to register all our common shares that we may issue under our employee benefit plans. Once we register these shares, they can be freely sold in the public market upon issuance, unless pursuant to their terms

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these share awards have transfer restrictions attached to them. Sales of a substantial number of our common shares, or the perception in the market that the holders of a large number of shares intend to sell common shares, could reduce the market price of our common shares.

The concentration of our share capital ownership among our largest shareholders, and their affiliates, will limit your ability to influence corporate matters.

        After our offering, we anticipate that our two largest shareholders will collectively own approximately 76% of our issued and outstanding common shares. Consequently, these shareholders have significant influence over all matters that require approval by our shareholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

If you purchase our common shares in this offering, you will suffer immediate and substantial dilution of your investment.

        The initial public offering price of our common shares is substantially higher than the net tangible book value per common share. Therefore, if you purchase our common shares in this offering, your interest will be diluted immediately to the extent of the difference between the initial public offering price per common share and the net tangible book value per common share after this offering. See "Dilution."

We have broad discretion in the use of our net proceeds from this offering and may not use them effectively.

        Our management will have broad discretion in the application of the net proceeds from this offering and could spend the proceeds in ways that do not improve our operating results or enhance the value of our common shares. Our shareholders may not agree with the manner in which our management chooses to allocate and spend the net proceeds. The failure by our management to apply these funds effectively could result in financial losses that could have a material adverse effect on our business and cause the price of our common shares to decline. Pending their use, we may invest our net proceeds from this offering in a manner that does not produce income or that loses value. See "Use of Proceeds".

We will be a "controlled company" within the meaning of the NYSE rules and, as a result, will qualify for and will rely on exemptions from certain corporate governance requirements.

        Upon completion of this offering, funds affiliated with Warburg Pincus LLC and The Blackstone Group L.P., respectively, will continue to control a majority of the voting power of our issued and outstanding common shares, after giving effect to our corporate reorganization, and we will be a "controlled company" within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a "controlled company" and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

•
a majority of the board of directors consist of independent directors;

•
the nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities;

•
the compensation committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities; and

•
there be an annual performance evaluation of the nominating and corporate governance and compensation committees.

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        Following this offering, we intend to elect to be treated as a controlled company and utilize these exemptions, including the exemption for a board of directors composed of a majority of independent directors. In addition, although we will have adopted charters for our audit, nominating and corporate governance and compensation committees and intend to conduct annual performance evaluations for these committees, none of these committees will be composed entirely of independent directors immediately following the completion of this offering. We will rely on the phase-in rules of the SEC and the NYSE with respect to the independence of our audit committee. These rules permit us to have an audit committee that has one member that is independent upon the effectiveness of the registration statement of which this prospectus forms a part, a majority of members that are independent within 90 days thereafter and all members that are independent within one year thereafter. Accordingly, you may not have the same protections afforded to shareholders of companies that are subject to all of the NYSE corporate governance requirements.

We do not intend to pay dividends on our common shares and, consequently, your only opportunity to achieve a return on your investment is if the price of our shares appreciates.

        We do not plan to declare dividends on shares of our common shares in the foreseeable future. Additionally, certain of our subsidiaries are currently restricted in their ability to pay dividends to us pursuant to the terms of our commercial debt facility unless they meet certain conditions, financial and otherwise. Consequently, your only opportunity to achieve a return on your investment in us will be if the market price of our common shares appreciates, which may not occur, and you sell your shares at a profit. There is no guarantee that the price of our common shares that will prevail in the market after this offering will ever exceed the price that you pay.

We are a Bermuda company and a significant portion of our assets are located outside the United States. As a result, it may be difficult for shareholders to enforce civil liability provisions of the federal or state securities laws of the United States.

        We are a Bermuda exempted company. As a result, the rights of holders of our common shares will be governed by Bermuda law and our memorandum of association and bye-laws. The rights of shareholders under Bermuda law may differ from the rights of shareholders of companies incorporated in other jurisdictions. One of our directors is not a resident of the United States, and a substantial portion of our assets are located outside the United States. As a result, it may be difficult for investors to effect service of process on that person in the United States or to enforce in the United States judgments obtained in U.S. courts against us or that person based on the civil liability provisions of the U.S. securities laws. It is doubtful whether courts in Bermuda will enforce judgments obtained in other jurisdictions, including the United States, against us or our directors or officers under the securities laws of those jurisdictions or entertain actions in Bermuda against us or our directors or officers under the securities laws of other jurisdictions.

Bermuda law differs from the laws in effect in the United States and might afford less protection to shareholders.

        Our shareholders could have more difficulty protecting their interests than would shareholders of a corporation incorporated in a jurisdiction of the United States. As a Bermuda company, we are governed by the Companies Act 1981 of Bermuda (the "Bermuda Companies Act"). The Bermuda Companies Act differs in some material respects from laws generally applicable to U.S. corporations and shareholders, including the provisions relating to interested directors, mergers and acquisitions, takeovers, shareholder lawsuits and indemnification of directors. Set forth below is a summary of these provisions, as well as modifications adopted pursuant to our bye-laws, which differ in certain respects from provisions of Delaware corporate law. Because the following statements are summaries, they do

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not discuss all aspects of Bermuda law that may be relevant to us and our shareholders. See "Description of Share Capital."

        Interested Directors.    Under Bermuda law and our bye-laws, as long as a director discloses a direct or indirect interest in any contract or arrangement with us as required by law, such director is entitled to vote in respect of any such contract or arrangement in which he or she is interested, unless disqualified from doing so by the chairman of the meeting, and such a contract or arrangement will not be voidable solely as a result of the interested director's participation in its approval. In addition, the director will not be liable to us for any profit realized from the transaction. In contrast, under Delaware law, such a contract or arrangement is voidable unless it is approved by a majority of disinterested directors or by a vote of shareholders, in each case if the material facts as to the interested director's relationship or interests are disclosed or are known to the disinterested directors or shareholders, or such contract or arrangement is fair to the corporation as of the time it is approved or ratified. Additionally, such interested director could be held liable for a transaction in which such director derived an improper personal benefit.

        Mergers and Similar Arrangements.    The amalgamation of a Bermuda company with another company or corporation (other than certain affiliated companies) requires the amalgamation agreement to be approved by the company's board of directors and by its shareholders. Unless the company's bye-laws provide otherwise, the approval of 75% of the shareholders voting at such meeting is required to approve the amalgamation agreement, and the quorum for such meeting must be two persons holding or representing more than one-third of the issued shares of the company. Our bye-laws provide that an amalgamation (other than with a wholly owned subsidiary, per the Bermuda Companies Act) that has been approved by the board must only be approved by shareholders owning a majority of the issued and outstanding shares entitled to vote. Under Bermuda law, in the event of an amalgamation of a Bermuda company with another company or corporation, a shareholder of the Bermuda company who is not satisfied that fair value has been offered for such shareholder's shares may, within one month of notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the fair value of those shares. Under Delaware law, with certain exceptions, a merger, consolidation or sale of all or substantially all the assets of a corporation must be approved by the board of directors and a majority of the issued and outstanding shares entitled to vote thereon. Under Delaware law, a shareholder of a corporation participating in certain major corporate transactions may, under certain circumstances, be entitled to appraisal rights pursuant to which such shareholder may receive cash in the amount of the fair value of the shares held by such shareholder (as determined by a court) in lieu of the consideration such shareholder would otherwise receive in the transaction.

        Shareholders' Suit.    Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company's memorandum of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of the company's shareholders than that which actually approved it.

        When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply to the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company's affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company.

        Our bye-laws contain a provision by virtue of which we and our shareholders waive any claim or right of action that they have, both individually and on our behalf, against any director or officer in

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relation to any action or failure to take action by such director or officer, except in respect of any fraud or dishonesty of such director or officer. Class actions and derivative actions generally are available to shareholders under Delaware law for, among other things, breach of fiduciary duty, corporate waste and actions not taken in accordance with applicable law. In such actions, the court has discretion to permit the winning party to recover attorneys' fees incurred in connection with such action.

        Indemnification of Directors.    We may indemnify our directors and officers in their capacity as directors or officers for any loss arising or liability attaching to them by virtue of any rule of law in respect of any negligence, default, breach of duty or breach of trust of which a director or officer may be guilty in relation to the company other than in respect of his own fraud or dishonesty. Under Delaware law, a corporation may indemnify a director or officer of the corporation against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in defense of an action, suit or proceeding by reason of such position if such director or officer acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, such director or officer had no reasonable cause to believe his or her conduct was unlawful. In addition, we have entered into customary indemnification agreements with our directors.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Forward-Looking Statements

        This prospectus contains estimates and forward-looking statements, principally in "Prospectus Summary," "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Industry" and "Business." 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 this prospectus, may adversely affect our results as indicated in forward-looking statements. You should read this prospectus and the documents that we have filed as exhibits to the registration statement of which this prospectus is a part completely and with the understanding that our actual future results may be materially different from what we expect.

        Our estimates and forward-looking statements may be influenced by the following factors, among others:

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

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

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

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

•
termination of or intervention in concessions, rights or authorizations granted by the 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;

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•
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 this prospectus.

        The words "aim," "anticipate," "believe," "continue," "estimate," "expect," "intend," "may," "plan," "should," "will" 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 prospectus 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 when making an investment decision.

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DIVIDEND POLICY

        At the present time, we intend to retain all of our future earnings, if any, generated by our operations for the development and growth of our business. Additionally, we are subject to Bermuda legal constraints that may affect our ability to pay dividends on our common shares and make other payments. Under the Bermuda Companies Act, we may not declare or pay a dividend if there are reasonable grounds for believing that we are, or would after the payment be, unable to pay our liabilities as they become due or that the realizable value of our assets would thereafter be less than the aggregate of our liabilities, issued share capital and share premium accounts. Certain of our subsidiaries are also currently restricted in their ability to pay dividends to us pursuant to the terms of our commercial debt facility unless we meet certain conditions, financial and otherwise. Any decision to pay dividends in the future is at the discretion of our board of directors and depends on our financial condition, results of operations, capital requirements and other factors that our board of directors deems relevant.

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USE OF PROCEEDS

        We estimate that our net proceeds from the sale of 30,000,000 common shares in this offering will be approximately $477.7 million after deducting estimated offering expenses payable by us of $5.5 million and underwriting discounts and commissions and assuming an initial public offering price of $17.00 per common share (the midpoint of the estimated public offering price range set forth on the cover of this prospectus). If the over-allotment option is exercised in full, we estimate that our net proceeds will be approximately $550.2 million.

        We intend to use the net proceeds from this offering, available cash and borrowings under our commercial debt facility to fund our capital expenditures, and in particular our exploration and appraisal drilling program and development activities through 2013, our related operating expenses, to make a $15.0 million payment to GNPC upon the successful completion of this offering pursuant to the settlement agreement we entered into with GNPC to resolve our past disputes, and for general corporate purposes. See "Risk Factors—We had disagreements with the Republic of Ghana and the Ghana National Petroleum Corporation regarding certain of our rights and responsibilities under the WCTP and DT Petroleum Agreements." Management will retain broad discretion over the allocation of the net proceeds from this offering. Pending use of the net proceeds of this offering, we intend to invest the net proceeds in interest bearing, investment-grade securities.

        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 which are available for additional drilling and licensing costs and activities.

        The ultimate amount of capital we will expend 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 thereof, 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. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

        A $1.00 increase (decrease) in the assumed public offering price of $17.00 per common share would increase (decrease) our expected net proceeds by approximately $28.4 million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us.

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CORPORATE REORGANIZATION

        Kosmos Energy Ltd. is a Bermuda exempted company that was formed for the purpose of making this offering. Pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the closing of this offering, all of the interests in Kosmos Energy Holdings will be exchanged for newly issued common shares of Kosmos Energy Ltd. and as a result Kosmos Energy Holdings will become wholly-owned by Kosmos Energy Ltd. Therefore, investors in this offering will only receive, and this prospectus only describes the offering of, common shares of Kosmos Energy Ltd. Our business will continue to be conducted through Kosmos Energy Holdings.

        The reorganization will consist of a series of internal transactions and changes followed by an exchange of the vested and unvested common and preferred units in Kosmos Energy Holdings for common shares in Kosmos Energy Ltd. Upon completion of the reorganization, Kosmos Energy Ltd. will directly own all of the equity interests in Kosmos Energy Holdings, and the former holders of the common and preferred units in Kosmos Energy Holdings will own an aggregate of 341,176,471 common shares based on their relative rights as set forth in Kosmos Energy Holdings' operating agreement. Any increase or decrease in the actual initial public offering price as compared to the assumed initial public offering price of $17.00 (the midpoint of the estimated public offering price range set forth on the cover of this prospectus) will change the relative percentages of common shares owned by the former holders of common and preferred units, but will not change the aggregate number of common shares outstanding following the completion of this offering. See "Description of Share Capital" for additional information regarding the terms of our memorandum of association and bye-laws as will be in effect upon the closing of this offering.

        Upon the completion of the reorganization, Kosmos Energy Holdings' current operating agreement will be terminated and a new memorandum of association and articles of association will be put in place.

        We refer to the reorganization pursuant to which Kosmos Energy Ltd. will acquire all of the interests in Kosmos Energy Holdings in exchange for common shares of Kosmos Energy Ltd. and the termination of Kosmos Energy Holding's current operating agreement as our "corporate reorganization."

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CAPITALIZATION

        The following table sets forth our capitalization as of December 31, 2010 on an actual basis, pro forma to give effect to our corporate reorganization and pro forma as adjusted for the effect of this offering.

        You should read this table together with "Use of Proceeds," "Selected Historical and Pro Forma Financial Information," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical financial statements and related notes included elsewhere in this prospectus.

	 	As of December 31, 2010	 	
 
	 	Actual	 	Pro Forma to
Give Effect to our
Corporate
Reorganization(1)	 	Pro Forma as
Adjusted for the
Effect of this
Offering(1)(2)	 	
 
	 	(In thousands, except share and per share data)
	 	
Cash and cash equivalents	 	$	100,415	 	$	100,415	 	$	578,140	 	
Restricted cash	 	 	112,000	 	 	112,000	 	 	112,000	 	
 	 	 	 	 	 	 	 	
 	Total cash	 	$	212,415	 	$	212,415	 	$	690,140	 	
 	 	 	 	 	 	 	 	
Current maturities of long-term debt	 	$	245,000	 	$	245,000	 	$	245,000	 	
Long-term debt	 	 	800,000	 	 	800,000	 	 	800,000	 	
 	 	 	 	 	 	 	 	
 	Total debt	 	 	1,045,000	 	 	1,045,000	 	 	1,045,000	 	
Series A Convertible Preferred Units; 30,000,000 units outstanding, actual	 	 	383,246	 	 	—	 	 	—	 	
Series B Convertible Preferred Units; 20,000,000 units outstanding, actual	 	 	568,163	 	 	—	 	 	—	 	
Series C Convertible Preferred Units; 884,956 units outstanding, actual	 	 	27,097	 	 	—	 	 	—	 	
 	 	 	 	 	 	 	 	
 	Total Convertible Preferred Units	 	 	978,506	 	 	—	 	 	—	 	
Common units; 19,069,662 units outstanding, actual	 	 	516	 	 	—	 	 	—	 	
Common shares, $0.01 par value per share; 341,176,471 shares issued and outstanding, pro forma to give effect to our corporate reorganization(3); 371,176,471 shares issued and outstanding, pro forma as adjusted for the effect of this offering(4)	 	 	—	 	 	3,412	 	 	3,712	 	
Additional paid-in capital	 	 	—	 	 	975,610	 	 	1,453,035	 	
Deficit accumulated during development stage/Retained deficit	 	 	(615,515	)	 	(615,515	)	 	(615,515	)	
Accumulated other comprehensive income (loss)	 	 	588	 	 	588	 	 	588	 	
 	 	 	 	 	 	 	 	
 	Total unit holdings/shareholders' equity	 	 	(614,411	)	 	364,095	 	 	841,820	 	
 	 	 	 	 	 	 	 	
 	Total capitalization	 	$	1,409,095	 	$	1,409,095	 	$	1,886,820	 	

(1)
Gives effect to the exchange of all of the interests in Kosmos Energy Holdings for newly issued common shares of Kosmos Energy Ltd. pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the closing of this offering.

(2)
Also gives effect to the issuance of 30,000,000 common shares contemplated by this offering at an assumed initial public offering price of $17.00 per common share (the midpoint of the estimated public offering price range set forth on the cover page of this prospectus) less underwriting discounts and commissions and expenses payable by us. A $1.00 decrease or increase in the

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assumed initial public offering price would result in approximately a $28.4 million decrease or increase in each of the following pro forma as adjusted (i) cash and cash equivalents, (ii) additional paid-in capital, (iii) total unit holdings' capital/shareholders' equity and (iv) total capitalization, assuming the total number of common shares offered by us remains the same and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us.(3)
Pursuant to the operating agreement, all of the preferred units and common units of Kosmos Energy Holdings, including (i) units issued to management and employees in connection with our corporate reorganization and (ii) all unvested units, will be 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 163,954,751; 110,419,935; 4,834,112; and 61,967,673 common shares, respectively, or 341,176,471 common shares in the aggregate. 341,176,471 common shares issued and outstanding, pro forma to give effect to our corporate reorganization, includes 9,572,543 restricted shares issued to management and employees in connection with our corporate reorganization, but excludes 24,503,000 common shares reserved for issuance pursuant to our long-term incentive plan (of which we intend to issue approximately 14,080,000 restricted shares to management and employees on or shortly after the closing of this offering). Any increase or decrease in the initial public offering price from the assumed offering price of $17.00 per common share will change the relative interest percentages of common shares owned by the different classes of unit holders but will not change the aggregate number of shares owned by all of the unit holders.

(4)
371,176,471 common shares issued and outstanding, pro forma as adjusted for the effect of this offering, includes 30,000,000 common shares issued pursuant to this offering and 9,572,543 restricted shares issued to management and employees in connection with our corporate reorganization, but excludes 24,503,000 common shares reserved for issuance pursuant to our long-term incentive plan (of which we intend to issue approximately 14,080,000 restricted shares to management and employees on or shortly after the closing of this offering).

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DILUTION

        If you invest in our common shares, your interest will be diluted to the extent of the difference between the initial public offering price per common share and the pro forma as adjusted net tangible book value per common share after this offering. We calculate net tangible book value per share by dividing the net tangible book value (tangible assets less total liabilities) by the number of issued and outstanding common shares.

        Our pro forma net tangible book value at December 31, 2010 after giving effect to our corporate reorganization was $364,095,000, or $1.07 per common share, based on 341,176,471 common shares issued and outstanding prior to the closing of this offering. After giving effect to our corporate reorganization and the sale of 30,000,000 common shares by us in this offering at an assumed initial public offering price of $17.00 per common share (the midpoint of the estimated public offering price range set forth on the cover page of this prospectus), less the estimated underwriting discounts and commissions and the estimated offering expenses payable by us, our pro forma as adjusted net tangible book value at December 31, 2010 would be $841,820,000, or $2.27 per common share. This represents an immediate increase in the pro forma net tangible book value of $1.20 per common share to existing shareholders and an immediate dilution of $14.73 per common share to new investors purchasing common shares in this offering. The following table illustrates this per share dilution:
 	 	 	 	 	 	 	 	
Assumed initial public offering price	 	 	        	 	$	17.00	 	
Pro forma net tangible book value per share as of December 31, 2010 after giving effect to our corporate reorganization	 	$	1.07	 	 	        	 	
Increase per share attributable to this offering	 	$	1.20	 	 	        	 	
 	 	 	 	 	 	 	
Pro forma net tangible book value per share after giving effect to our corporate reorganization and this offering	 	 	        	 	$	2.27	 	
 	 	 	 	 	 	 	
Dilution per share to new investors in this offering	 	 	        	 	$	14.73	 	
 	 	 	 	 	 	 	
        The following table shows, at December 31, 2010, on a pro forma basis as described above, the difference between the number of common shares purchased from us, the total consideration paid to us and the average price paid per common share by existing shareholders and by new investors purchasing common shares in this offering:

	 	Common Shares
Purchased	 	 

	 	 	
 
	 	 	 	Total Consideration	 	 

	 	 	 	 	 	Average Price
Per Common Share	 	 	 	 	 	 	 	 	 	 	 	 	
 
	 	Number	 	Percentage	 	Amount	 	Percentage	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Existing shareholders	 	 	341,176,471	 	 	92	%	$	979,022,000	(1)	 	66	%	$	2.87	 	 	 	 	 	 	 	 	 	 	 	 	
New investors	 	 	30,000,000	 	 	8	%	$	510,000,000	 	 	34	%	$	17.00	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	371,176,471	 	 	100.00	%	$	1,489,022,000	 	 	100.00	%	$	4.01	 	 	 	 	 	 	 	 	 	 	 	 	

(1)
Represents the total amount of capital contributions made by the Kosmos Energy Holdings unit holders.

        Assuming the underwriters' over-allotment option is exercised in full, sales by us in this offering will reduce the percentage of common shares held by existing shareholders to 91% and will increase the number of common shares held by new investors to 34,500,000, or 9%. This information is based on common shares issued and outstanding as of December 31, 2010, after giving effect to our corporate reorganization. No material change has occurred to our equity capitalization since December 31, 2010, after giving effect to our corporate reorganization and this offering.

        Each $1.00 increase (decrease) in the assumed public offering price per common share would increase (decrease) the pro forma net tangible book value by $0.07 per share (after giving effect to our corporate reorganization and assuming no exercise of the underwriters' option to purchase additional shares) and the dilution to investors in this offering by $0.93 per share, assuming the number of common shares offered by us, as set forth on the cover page of this prospectus, remains the same.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL INFORMATION

        The selected historical financial information set forth below should be read in conjunction with the sections entitled "Corporate Reorganization", "Management's Discussion and Analysis of Financial Condition and Results of Operations" and with Kosmos Energy Holdings' financial statements and the notes to those financial statements included elsewhere in this prospectus. Kosmos Energy Holdings has been a development stage company. The consolidated statements of operations and cash flows for the years ended December 31, 2006, 2007, 2008, 2009 and 2010 and for the period April 23, 2003 (Inception) through December 31, 2010, and the consolidated balance sheets as of December 31, 2006, 2007, 2008, 2009 and 2010 were derived from Kosmos Energy Holdings' audited consolidated financial statements. The unaudited pro forma information is derived from Kosmos Energy Holdings' audited consolidated financial statements appearing elsewhere in this prospectus and is based on assumptions and includes adjustments as explained in the notes to the table.

        Other than as indicated under "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies," all accounting policies in effect for Kosmos Energy Holdings and described in this prospectus will remain in effect upon completion of the corporate reorganization and will be utilized by Kosmos Energy Ltd.

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Consolidated Statements of Operations Information:

	 	 

	 	 
	 	 
	 	Period
April 23, 2003
(Inception)
through
December 31
2010	 	 	
 
	 	Year Ended December 31	 	 	 	 	 	
 
	 	2006	 	2007	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands, except per share data)
	 	 	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas revenue	 	$	—	 	$	—	 	$	—	 	$	—	 	$	—	 	$	—	 	 	 	
 	Interest income	 	 	445	 	 	1,568	 	 	1,637	 	 	985	 	 	4,231	 	 	9,142	 	 	 	
 	Other income	 	 	3,100	 	 	2	 	 	5,956	 	 	9,210	 	 	5,109	 	 	26,699	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total revenues and other income	 	 	3,545	 	 	1,570	 	 	7,593	 	 	10,195	 	 	9,340	 	 	35,841	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Exploration expenses, including dry holes	 	 	9,083	 	 	39,950	 	 	15,373	 	 	22,127	 	 	73,126	 	 	166,450	 	 	 	
 	General and administrative	 	 	9,588	 	 	18,556	 	 	40,015	 	 	55,619	 	 	98,967	 	 	236,165	 	 	 	
 	Depletion, depreciation and amortization	 	 	401	 	 	477	 	 	719	 	 	1,911	 	 	2,423	 	 	6,505	 	 	 	
 	Amortization—debt issue costs	 	 	—	 	 	—	 	 	—	 	 	2,492	 	 	28,827	 	 	31,319	 	 	 	
 	Interest expense	 	 	—	 	 	8	 	 	1	 	 	6,774	 	 	59,582	 	 	66,389	 	 	 	
 	Derivatives, net	 	 	—	 	 	—	 	 	—	 	 	—	 	 	28,319	 	 	28,319	 	 	 	
 	Equity in losses of joint venture	 	 	9,194	 	 	2,632	 	 	—	 	 	—	 	 	—	 	 	16,983	 	 	 	
 	Doubtful accounts expense	 	 	—	 	 	—	 	 	—	 	 	—	 	 	39,782	 	 	39,782	 	 	 	
 	Other expenses, net	 	 	7	 	 	17	 	 	21	 	 	46	 	 	1,094	 	 	1,949	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total costs and expenses	 	 	28,273	 	 	61,640	 	 	56,129	 	 	88,969	 	 	332,120	 	 	593,861	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Loss before income taxes	 	 	(24,728	)	 	(60,070	)	 	(48,536	)	 	(78,774	)	 	(322,780	)	 	(558,020	)	 	 	
 	Income tax expense (benefit)	 	 	—	 	 	718	 	 	269	 	 	973	 	 	(77,108	)	 	(75,148	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(24,728	)	$	(60,788	)	$	(48,805	)	$	(79,747	)	$	(245,672	)	$	(482,872	)	 	 	
Accretion to redemption value of convertible preferred units	 	 	(4,019	)	 	(8,505	)	 	(21,449	)	 	(51,528	)	 	(77,313	)	 	(165,262	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss attributable to common unit holders	 	$	(28,747	)	$	(69,293	)	$	(70,254	)	$	(131,275	)	$	(322,985	)	$	(648,134	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pro forma net loss (unaudited)(1):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pro forma basic and diluted net loss per common share(2)	 	 	 	 	 	 	 	 	 	 	 	 	 	$	(0.75	)	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pro forma weighted average number of shares used to compute pro forma net loss per common share, basic and diluted(3)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	325,799	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(1)
Pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the closing of this offering, all of the interests in Kosmos Energy Holdings will be exchanged for newly issued common shares of Kosmos Energy Ltd. based on these interests' relative rights as set forth in Kosmos Energy Holdings' current operating agreement. This includes convertible preferred units of Kosmos Energy Holdings which are redeemable upon the consummation of a qualified public offering (as defined in the current operating agreement) into common shares of Kosmos Energy Ltd. based on the pre-offering equity value of such interests.

(2)
Any stock options, restricted share units and share appreciation rights that are out of the money will be excluded as they will be anti-dilutive.

(3)
The weighted average common shares outstanding have been calculated as if the ownership structure resulting from the corporate reorganization was in place since inception.

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Consolidated Balance Sheets Information:

	 	As of December 31	 	Pro Forma
as Adjusted as of
December 31
2010(1)	 	 	
 
	 	2006	 	2007	 	2008	 	2009	 	2010	 	 	 	 	

	 	 

	 	 
	 	(Unaudited)

	 	(In thousands)
	 	 	
Cash and cash equivalents	 	$	9,837	 	$	39,263	 	$	147,794	 	$	139,505	 	$	100,415	 	$	100,415	 	 	
Total current assets	 	 	10,334	 	 	65,960	 	 	205,708	 	 	256,728	 	 	559,920	 	 	559,920	 	 	
Total property and equipment	 	 	1,567	 	 	18,022	 	 	208,146	 	 	604,007	 	 	998,000	 	 	998,000	 	 	
Total other assets	 	 	3,704	 	 	3,393	 	 	1,611	 	 	161,322	 	 	133,615	 	 	133,615	 	 	
Total assets	 	 	15,605	 	 	87,375	 	 	415,465	 	 	1,022,057	 	 	1,691,535	 	 	1,691,535	 	 	
Total current liabilities	 	 	1,436	 	 	28,574	 	 	68,698	 	 	139,647	 	 	482,057	 	 	482,057	 	 	
Total long-term liabilities	 	 	—	 	 	—	 	 	444	 	 	287,022	 	 	845,383	 	 	845,383	 	 	
Total convertible preferred units	 	 	61,952	 	 	167,000	 	 	499,656	 	 	813,244	 	 	978,506	 	 	—	 	 	
Total unit holdings/shareholders' equity	 	 	(47,783	)	 	(108,199	)	 	(153,333	)	 	(217,856	)	 	(614,411	)	 	364,095	 	 	
Total liabilities, convertible preferred units and unit holdings/shareholders' equity	 	 	15,605	 	 	87,375	 	 	415,465	 	 	1,022,057	 	 	1,691,535	 	 	1,691,535	 	 	

(1)
Includes the effect of our corporate reorganization and the effect of this offering as described in "Corporate Reorganization," "Capitalization" and "Dilution."

Consolidated Statements of Cash Flows Information:

	 	 

	 	 
	 	 
	 	Period
April 23, 2003
(Inception)
through
December 31
2010	 	 	
 
	 	Year Ended December 31	 	 	 	 	 	
 
	 	2006	 	2007	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	
Net cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	$	(9,617	)	$	(17,386	)	$	(65,671	)	$	(27,591	)	$	(191,800	)	$	(331,009	)	 	 	
Investing activities	 	 	(14,663	)	 	(58,161	)	 	(156,882	)	 	(500,393	)	 	(589,975	)	 	(1,329,026	)	 	 	
Financing activities	 	 	19,768	 	 	104,973	 	 	331,084	 	 	519,695	 	 	742,685	 	 	1,760,450	 	 	 	
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MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including, without limitation, those set forth in "Risk Factors," "Cautionary Note Regarding Forward-Looking Statements" and the other matters set forth in this prospectus. The following discussion of our financial condition and results of operations should be read in conjunction with our financial statements and the notes thereto included elsewhere in this prospectus, as well as the information presented under "Selected Historical and Pro Forma Financial Information." Due to the fact that we have not yet generated any revenues, we believe that the financial information contained in this prospectus is not indicative of, or comparable to, the financial profile that we expect to have once we begin to generate revenues. Except to the extent required by law, we undertake no obligation to publicly update any forward-looking statements for any reason, even if new information becomes available or other events occur in the future.

Overview

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

        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. 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. Pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the closing of this offering, all of the interests in Kosmos Energy Holdings will be exchanged for newly issued common shares of Kosmos Energy Ltd. and as a result Kosmos Energy Holdings will become wholly-owned by Kosmos Energy Ltd.

Exploration and Other Agreements

        Each of our five exploration licenses is governed by related petroleum or license agreements. In July 2004, Kosmos signed the WCTP Petroleum Agreement. In July 2006, Kosmos signed the DT Petroleum Agreement. In 2006, Anadarko farmed in to the WCTP Block and DT Block while Tullow and Sabre farmed in to the WCTP Block. Following the discovery of the Jubilee Field, on July 13, 2009 Kosmos and the other WCTP and DT block partners signed the UUOA, which governs the interests in and development of the Jubilee Field and created the Jubilee Unit from portions of the WCTP Block and the DT Block. In November 2005, Kosmos farmed in to the Kombe-N'sepe License Agreements. In November 2006, Kosmos signed the Ndian River Production Sharing Contract. In May 2006, Kosmos signed the Boujdour Offshore Petroleum Agreement and in September 2010, we entered a memorandum of understanding with ONHYM to enter a new petroleum agreement covering the highest potential areas of this block under essentially the same terms as the original petroleum agreement. Kosmos has also entered numerous agreements ancillary to the operation of the above license agreements or otherwise necessary to conduct Kosmos' oil and natural gas exploration, development and production activities.

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Factors Affecting Comparability of Future Results

        This management's discussion and analysis of our financial condition and results of operations should be read in conjunction with our historical financial statements included elsewhere in this prospectus. Below are the period-to-period comparisons of our historical results and the analysis of our financial condition. Our future results could differ materially from our historical results due to a variety of factors, including the following:

        Success in the Discovery and Development of Oil and Natural Gas Reserves.    Because we have limited operating history in the production of oil and natural gas, our future results of operations and financial condition will be directly affected by our ability to discover and develop reserves through our drilling activities. The calculation of our geological and petrophysical estimates is complex and imprecise, and it is possible that our future exploration will not result in additional discoveries, and, even if we are able to successfully make such discoveries, there is no certainty that the discoveries will be commercially viable to produce. Our results of operations will be adversely affected in the event that our estimated oil and natural gas asset base does not result in additional reserves that may eventually be commercially developed.

        Oil and Gas Revenue.    We commenced oil and natural gas production on November 28, 2010, and received our first revenues from such production in early 2011. No oil and gas revenue is reflected in our historical financial statements.

        Production Costs.    We have recently commenced oil and natural gas production and will accordingly incur production costs. Production costs are the costs incurred in the operation of producing and processing our production and are primarily comprised of lease operating expense, workover costs and production taxes. No production costs are reflected in our historical financial statements.

        General and Administrative.    We expect general and administrative expenses to increase as a result of commencing production from the Jubilee Field on November 28, 2010 and as a result of becoming a publicly traded company. Public company costs include expenses associated with our annual and quarterly reporting, investor relations, registrar and transfer agent fees, incremental insurance costs, and accounting and legal services. We expect to incur $27.7 million of costs related to unit-based compensation in connection with awards issued in connection with our corporate reorganization. Additionally, we expect to issue 14,080,000 restricted shares under our long-term incentive plan shortly after our initial public offering. These costs will be expensed over the vesting period of the awards. These differences in general and administrative expenses are not reflected in our historical financial statements.

        Depletion, Depreciation and Amortization.    We recently commenced oil and natural gas production and deplete the costs of successful exploration, appraisal, drilling and field development using the unit-of-production method based on estimated proved developed oil and natural gas reserves.

        Other Income.    Our amounts of other income earned will depend on whether we are the operator of any future blocks we acquire. As operator of a block, we bill portions of our general and administrative expenses to the other block partners in accordance with their working interests. These billings are recorded as other income.

        Income Taxes.    The Kosmos Ghana valuation allowance, reducing the deferred tax asset to zero, was removed in December 2010. Based upon various factors including the commencement of start-up operations, the placing into service of the equipment and infrastructure necessary to lift and store oil, the lifting of oil beginning on November 28, 2010, our forecast of future production and our estimates of future taxable income from the related oil sales, we believe it is more likely than not that the deferred tax asset will be realized in the future.

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        We entered into the Boujdour Offshore Petroleum Agreement in May 2006. This 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. We currently have recorded deferred tax assets of $6.8 million, recorded at the Moroccan statutory rate of 30%, with an offsetting valuation allowance of $6.8 million. Once we enter into the tax holiday period (when production begins) we will re-evaluate our 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.

        Demand and Price.    The demand for oil and natural gas is susceptible to volatility based on, among other factors, the level of global economic activity, and may also fluctuate depending on the performance of specific industries.

        We expect to earn income from:

•
oil and natural gas sales to international markets; and

•
other sources, including technical services, investment income and foreign exchange gains.

        We expect that our expenses will include:

•
costs of sales (which include production costs, insurance, sales expenses and costs associated with the drilling and operation of our wells and related facilities);

•
maintenance and repair of property and equipment;

•
depreciation of fixed assets;

•
depletion of oilfields and associated abandonment costs;

•
exploration and appraisal costs;

•
costs of acquiring seismic or other geological and geophysical data;

•
selling expenses and general and administrative expenses; and

•
financing expenses, interest expense and foreign exchange losses.

        We expect that fluctuations in our financial condition and results of operations will be driven by a combination of factors, including:

•
the volume of oil and natural gas we produce and sell;

•
changes in the market prices of oil and natural gas;

•
changes in fair value of derivative financial instruments;

•
our success in obtaining new licenses and other acquisitions;

•
the successful implementation of our drilling and appraisal and development plans;

•
political and economic conditions in the countries in which we conduct our business activities; and

•
the amount of taxes and duties that we are required to pay with respect to our future operations.

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Results of Operations

        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.

Year Ended December 31, 2010 vs. 2009

	 	Years Ended
December 31	 	 

	 	 	 	Increase
(Decrease)	 	 	 	 	 	 	
 
	 	2009	 	2010	 	 	 	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	 	 	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas revenue	 	$	—	 	$	—	 	$	—	 	 	 	 	 	 	
 	Interest income	 	 	985	 	 	4,231	 	 	3,246	 	 	 	 	 	 	
 	Other income	 	 	9,210	 	 	5,109	 	 	(4,101	)	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total revenues and other income	 	 	10,195	 	 	9,340	 	 	(855	)	 	 	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Exploration expenses, including dry holes	 	 	22,127	 	 	73,126	 	 	50,999	 	 	 	 	 	 	
 	General and administrative	 	 	55,619	 	 	98,967	 	 	43,348	 	 	 	 	 	 	
 	Depletion, depreciation and amortization	 	 	1,911	 	 	2,423	 	 	512	 	 	 	 	 	 	
 	Amortization—debt issue costs	 	 	2,492	 	 	28,827	 	 	26,335	 	 	 	 	 	 	
 	Interest expense	 	 	6,774	 	 	59,582	 	 	52,808	 	 	 	 	 	 	
 	Derivatives, net	 	 	—	 	 	28,319	 	 	28,319	 	 	 	 	 	 	
 	Doubtful accounts expense	 	 	—	 	 	39,782	 	 	39,782	 	 	 	 	 	 	
 	Other expenses, net	 	 	46	 	 	1,094	 	 	1,048	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total costs and expenses	 	 	88,969	 	 	332,120	 	 	243,151	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Loss before income taxes	 	 	(78,774	)	 	(322,780	)	 	(244,006	)	 	 	 	 	 	
 	Income tax expense (benefit)	 	 	973	 	 	(77,108	)	 	(78,081	)	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(79,747	)	$	(245,672	)	$	(165,925	)	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
        Oil and gas revenue.    We have recently commenced oil and natural gas production. We did not realize any oil and gas revenue during the years ended December 31, 2009 and 2010.

        Interest income.    Interest income increased by $3.2 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009, due to interest accrued on receivables—joint interest billings.

        Other income.    Other income decreased by $4.1 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009, primarily due to a decrease in technical services fees and overhead charges billed to the Unit Operator as a result of the Jubilee Field Phase 1 development nearing completion.

        Exploration expenses.    Exploration expenses increased by $51.0 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009, primarily due to unsuccessful well costs of $28.4 million and $26.0 million for the Ghana Dahoma-1 well and Cameroon Mombe-1 well, respectively, and an increase in purchases of seismic data for Ghana of $5.6 million offset by a decrease in purchases of seismic data for Morocco of $12.9 million.

        General and administrative.    General and administrative costs increased by $43.3 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009, due to non-recurring charges of approximately $23.0 million, which includes a $15.0 million accrual that is payable upon the successful completion of this offering pursuant to our settlement agreement entered into with GNPC and the Government of Ghana in December 2010, increases in professional fees and expenses

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of $6.1 million, unit-based compensation of $10.4 million and operator charges of $4.3 million, offset in part by increases in capitalized technical service fees of $4.4 million.

        Amortization—debt issue costs.    Amortization—debt issue costs increased by $26.3 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009, due to the amortization of the fees which were capitalized in connection with the initial draw on the commercial debt facilities in November 2009.

        Interest expense.    Interest expense increased by $52.8 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009, $49.6 million due to draws on the commercial debt facilities beginning in November 2009 and $12.4 million for realized and unrealized losses on interest rate swaps offset by an increase of $9.2 million in capitalized interest.

        Derivatives, net.    During the year ended December 31, 2010, we recorded $28.3 million of unrealized losses on commodity derivatives, due to exposure to continuing market risk.

        Doubtful accounts expense.    During the year ended December 31, 2010, we recorded an allowance for doubtful accounts of $39.8 million, related to a receivable in default which became due upon the commencement of oil production from the Jubilee Field in November 2010. Based on this default, we have established an allowance to cover our estimated exposures.

        Income tax expense (benefit).    Income tax decreased by $78.1 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009, 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 beginning of oil production in late November 2010 and future projected taxable income to be generated from oil sales.

Year Ended December 31, 2009 vs. 2008

	 	Years Ended
December 31	 	 

	 	 	 	Increase
(Decrease)	 	 	 	 	 	 	
 
	 	2008	 	2009	 	 	 	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	 	 	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas revenue	 	$	—	 	$	—	 	$	—	 	 	 	 	 	 	
 	Interest income	 	 	1,637	 	 	985	 	 	(652	)	 	 	 	 	 	
 	Other income	 	 	5,956	 	 	9,210	 	 	3,254	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total revenues and other income	 	 	7,593	 	 	10,195	 	 	2,602	 	 	 	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Exploration expenses, including dry holes	 	 	15,373	 	 	22,127	 	 	6,754	 	 	 	 	 	 	
 	General and administrative	 	 	40,015	 	 	55,619	 	 	15,604	 	 	 	 	 	 	
 	Depreciation and amortization	 	 	719	 	 	1,911	 	 	1,192	 	 	 	 	 	 	
 	Amortization—debt issue costs	 	 	—	 	 	2,492	 	 	2,492	 	 	 	 	 	 	
 	Interest expense	 	 	1	 	 	6,774	 	 	6,773	 	 	 	 	 	 	
 	Other expenses, net	 	 	21	 	 	46	 	 	25	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total costs and expenses	 	 	56,129	 	 	88,969	 	 	32,840	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Loss before income taxes	 	 	(48,536	)	 	(78,774	)	 	(30,238	)	 	 	 	 	 	
 	Income tax expense	 	 	269	 	 	973	 	 	704	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(30,942	)	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
        Oil and gas revenue.    We have recently commenced oil and natural gas production. We did not realize any oil and gas revenue during the years ended December 31, 2008 and 2009.

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        Other income.    Other income increased by $3.3 million during the year ended December 31, 2009, as compared to the year ended December 31, 2008, primarily due to an increase of $3.6 million in technical services fees and overhead charges billed to the Unit Operator for the Jubilee Field Phase 1 development.

        Exploration expenses.    Exploration expenses increased by $6.8 million during the year ended December 31, 2009, as compared to the year ended December 31, 2008, due to an increase of $14.5 million in purchases of seismic data for Cameroon and Morocco offset by a decrease of $7.7 million in purchases of seismic data for Ghana and Nigeria.

        General and administrative.    General and administrative costs increased by $15.6 million during the year ended December 31, 2009, as compared to the year ended December 31, 2008, due to increases in professional fees and expenses and office-related costs offset by increases in capitalized technical service fees and billings to block partners.

        Depreciation and amortization.    Depreciation and amortization, which relates primarily to non-oil and natural gas properties and equipment, increased by $1.2 million during the year ended December 31, 2009, as compared to the year ended December 31, 2008, due to acquisitions of depreciable leasehold improvements and office furniture and equipment.

        Amortization—debt issue costs.    Amortization—debt issue costs increased by $2.5 million during the year ended December 31, 2009, as compared to the year ended December 31, 2008, due to the amortization of the fees which were capitalized in connection with the initial draw on the commercial debt facilities in November 2009.

        Interest expense.    Interest expense increased by $6.8 million during the year ended December 31, 2009, as compared to the year ended December 31, 2008, due to the draws on the commercial debt facilities beginning in November 2009.

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. To meet our ongoing liquidity requirements, we have historically secured funding from equity commitments and from commercial debt facilities. We have a proven ability to raise capital, having secured commitments for approximately $2.3 billion of private equity funding and commercial debt funding in the last seven years. In addition, we received our first oil revenues in early 2011 from production from Jubilee Field Phase 1. Accordingly, the cash generated from our operating activities will provide an additional source of funding going forward. We believe that our available cash, together with the net proceeds from this offering and borrowings under our commercial debt facility, 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

        To date all of our equity has been provided by funds affiliated with either Warburg Pincus or The Blackstone Group, as well as the management group, certain accredited employee investors and directors. We have received three rounds of equity funding commitments aggregating $1.05 billion.

        During 2009, we secured commercial debt facilities from a number of financial institutions, including the IFC, for up to $900.0 million to be used in funding our share of Jubilee Field Phase 1 development. The facilities were amended in August 2010 to increase the total commercial debt facilities amount to $1.25 billion and to add additional lenders.

        In March 2011, we secured a new commercial debt facility from a number of financial institutions for up to $2.0 billion to be used in funding our share of the development and maintenance of various

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oil and gas fields, and to refinance our previous commercial debt facilities. The facility contains an accordion feature which allows the size of the facility to increase to up to $3.0 billion should additional commitments be obtained.

        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 Modelling Bank, Crédit Agricole Corporate And Investment Bank is the Co-Technical and Modelling Bank and HSBC Bank plc is the Co-Technical Bank. The commercial debt 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 relevant documentation). 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 uncancelled portion of the total commitments. Commitment fees for the lenders are, when a commitment is available for utilization, equal to 40% per annum of the then-applicable respective margin, and when a commitment is not available for utilization, equal to 20% per annum of the then-applicable respective margin.

        The new commercial debt facility contains financial covenants, requiring 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 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.

        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 on June 15 and December 15 of each year as part of a forecast that is prepared and agreed by Kosmos and the Technical and Modelling 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 December 31, 2010, borrowings against our previous commercial debt facilities totaled $1.05 billion, of which $970.0 million was senior debt and $75.0 million was junior debt. As of December 31, 2010, the availability under our commercial debt facilities was $203.0 million, with $205.0 million of committed undrawn capacity provided for in such facilities (the difference being the result of borrowing base constraints). As of March 31, 2011, borrowings against the new commercial debt facility totaled $1.3 billion, with $151 million of availability and $700 million of committed undrawn capacity under such facility.

        If an event of default exists under the facility, the lenders will be able to 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.

        We incurred approximately $54.3 million of debt issue costs in the acquisition of our new commercial debt facility, in addition to our existing unamortized debt issue costs of $68.6 million as of March 31, 2011. As a result of the debt refinance, we will record a $60.7 million loss on the

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extinguishment of debt with the remaining costs to be capitalized and amortized over the term of the new commercial debt facility.

Capital Expenditures and Investments

        We expect to incur substantial expenses and generate significant operating losses as we continue to develop our oil and natural gas prospects and as we:

•
complete our current exploration and appraisal drilling program through 2011 for our offshore Ghana licenses;

•
drill two exploration wells in Cameroon;

•
purchase and analyze seismic and other geological and geophysical data in order to identify future prospects;

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

•
develop our discoveries which we determine to be commercially viable.

        Oil production from the Jubilee Field commenced on November 28, 2010, and we received our first oil revenues in early 2011. We expect gross oil production from the Jubilee Field to reach the design capacity of the FPSO facility used to produce from the field of 120,000 bopd in the third quarter of 2011. At that rate, the share of this gross oil production net to us is expected to be 28,200 bopd.

        In budgeting for our future activities, we have relied on a number of assumptions, including with regard to our discovery success rate, 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 both 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 prove to be incorrect or if we choose to expand our hydrocarbon asset acquisition, exploration, appraisal or development efforts more rapidly than we presently anticipate, and we may decide to raise additional funds even 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 could also result in 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 such FPSO in order to repay amounts originally loaned by us and certain other Jubilee Unit partners under an Advance Payments Agreement (which we are not a signatory of, as Tullow entered such agreement as Unit Operator of the Jubilee Unit) and a construction loan from a third-party for the financing of the construction of such 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. Tullow is required, based on the terms of the joint operating agreement for the Jubilee Unit, to reimburse us the amounts MODEC reimburses to Tullow within ten 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 market value of the FPSO. 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

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amount up to approximately $120.0 million. See "Risk Factors—The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results."

        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 which are available for additional drilling and licensing costs and activities.

        The ultimate amount of capital we will expend 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 thereof, 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.

Cash Flows

	 	 

	 	Period
April 23, 2003
(Inception)
through
December 31
2010	 	 	
 
	 	Year Ended December 31	 	 	 	 	 	
 
	 	2008	 	2009	 	2010	 	 	 	 	 	

	 	 
	 	 
	 	(Unaudited)

	 	(In thousands)
	 	 	 	
Net cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Operating activities	 	$	(65,671	)	$	(27,591	)	$	(191,800	)	$	(331,009	)	 	 	
 	Investing activities	 	 	(156,882	)	 	(500,393	)	 	(589,975	)	 	(1,329,026	)	 	 	
 	Financing activities	 	 	331,084	 	 	519,695	 	 	742,685	 	 	1,760,450	 	 	 	
        Operating activities.    Net cash used in operating activities in 2010 was $191.8 million compared with net cash used in operating activities of $27.6 million and $65.7 million in 2009 and 2008, respectively. The increase in cash used in 2010 when compared to 2009 is mainly due to changes in working capital related to receivables of $66.1 million, primarily joint interest billings, timing of payments of $15.1 million, prepaid drilling costs of $12.5 million, increases in interest expense of $45.7 million and $28.3 million of general and administrative expenses. The decrease in cash used in 2009 when compared to 2008 is primarily attributed to timing of payments related to working capital expenditures offset by increases in seismic exploration costs of $6.7 million and $6.8 million of interest expense.

        Investing activities.    Net cash used in investing activities in 2010 was $590.0 million compared with net cash used in investing activities of $500.4 million and $156.9 million in 2009 and 2008, respectively. The increase in cash used in 2010 when compared to 2009 is primarily attributable to increases in restricted cash of $29.0 million related to the commercial debt facilities and $23.0 million for the cash collateralized irrevocable letter of credit associated with the Eirik Raude drilling rig and increases of $32.8 million in expenditures for oil and gas assets primarily in Ghana for exploration and appraisal wells and development activities. The increase in cash used in 2009 when compared to 2008 is primarily attributed to increased expenditures in Ghana for exploration and appraisal wells and development activities.

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        Financing activities.    Net cash provided by financing activities in 2010 was $742.7 million compared with net cash provided by financing activities of $519.7 million and $331.1 million in 2009 and 2008, respectively. The increase in cash provided in 2010 when compared to 2009 is primarily due to increased borrowings of $475.0 million on the commercial debt facilities and a decrease of $73.3 million in cash used for debt issue costs offset by a decrease of $325.3 million of proceeds from the issuances of Series B and Series C Convertible Preferred Units. The increase in cash provided in 2009 when compared to 2008 is due to borrowings of $285.0 million on the commercial debt facilities offset by a net decrease of $7.3 million of proceeds from issuances of Series B and Series C Convertible Preferred Units and an increase of $89.1 million 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 December 31, 2010:

	 	Payments Due By Year(3)	 	
 
	 	Total	 	2011	 	2012	 	2013	 	2014	 	2015	 	Thereafter	 	
 
	 	(In thousands)
	 	
Drilling rig contract(1)	 	$	271,719	 	$	138,588	 	$	133,131	 	$	—	 	$	—	 	$	—	 	$	—	 	
Operating leases	 	 	6,461	 	 	1,615	 	 	1,636	 	 	1,660	 	 	1,168	 	 	382	 	 	—	 	
Commercial debt facilities(2)	 	 	1,045,000	 	 	245,000	 	 	250,000	 	 	200,000	 	 	175,000	 	 	100,000	 	 	75,000	 	
Interest payments on commercial debt facilities	 	 	219,295	 	 	72,131	 	 	56,430	 	 	39,288	 	 	28,691	 	 	17,559	 	 	5,196	 	

(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. Pursuant to the terms in the commercial debt facilities, when any junior debt is outstanding, repayments may be required to be made under the agreement, whereby 75% of any funds remaining on any repayment date, after required payments are made, will be applied to prepay the junior facilities and the remaining 25% will be applied to prepay the senior facilities. The table of scheduled maturities assumes the outstanding borrowings under the junior facilities will be repaid on June 15, 2016. If repayments are required as noted above, amortization of the junior facilities will occur through such repayments. Subsequent to December 31, 2010 and prior to the date of the financial statements, we borrowed an additional $28.0 million under the senior facilities. As of the date of our audited financial statements, borrowings against the commercial debt facilities totaled $1.07 billion. Subsequent to the date of our audited financial statements, we borrowed an additional $65 million under the junior facilities. In March 2011 we entered into a new $2.0 billion commercial debt facility. At March 31, 2011 we had $700 million of committed undrawn capacity under such facility, as well as the ability to increase the commitments under the facility by $1.0 billion. As of April 13, 2011, borrowings against the new commercial debt facility totaled $1.3 billion. The scheduled principal maturities during the next five years and thereafter are: 2011—$—; 2012—$—; 2013—$—; 2014—$—; 2015—$300 million and thereafter—$1.0 billion.

(3)
Does not include purchase commitments for jointly owned fields and facilities where we are not the operator.

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        The following table presents maturities by expected maturity dates under our commercial debt facilities, the weighted average interest rates expected to be paid on the credit facilities 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 any amortization of debt issue costs.

	 	 

	 	 

	 	Asset
(Liability) Fair
Value at
December 31
2010	 	 	
 
	 	Year Ending December 31	 	 	 	 	 	
 
	 	2011	 	2012	 	2013	 	2014	 	2015	 	Thereafter	 	 	 	 	 	
 
	 	(In thousands, except percentages)
	 	 	 	
Variable Rate Debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Credit facilities maturities	 	$	245,000	 	$	250,000	 	$	200,000	 	$	175,000	 	$	100,000	 	$	75,000	 	$	(1,045,000	)	 	 	
 	Weighted average interest rate	 	 	6.90	%	 	7.65	%	 	7.86	%	 	9.48	%	 	11.71	%	 	13.86	%	 	 	 	 	 	
Interest Rate Swaps	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Notional debt amount(1)	 	$	161,250	 	$	138,073	 	$	91,683	 	$	47,033	 	$	16,875	 	$	6,250	 	$	(2,938	)	 	 	
 	 	Fixed rate payable	 	 	2.22	%	 	2.22	%	 	2.22	%	 	2.22	%	 	2.22	%	 	2.22	%	 	 	 	 	 	
 	 	Variable rate receivable(2)	 	 	0.52	%	 	1.23	%	 	2.34	%	 	3.37	%	 	4.18	%	 	4.60	%	 	 	 	 	 	
 	Notional debt amount(1)	 	$	161,250	 	$	138,073	 	$	91,683	 	$	47,033	 	$	16,875	 	$	6,250	 	$	(3,309	)	 	 	
 	 	Fixed rate payable	 	 	2.31	%	 	2.31	%	 	2.31	%	 	2.31	%	 	2.31	%	 	2.31	%	 	 	 	 	 	
 	 	Variable rate receivable(2)	 	 	0.52	%	 	1.23	%	 	2.34	%	 	3.37	%	 	4.18	%	 	4.60	%	 	 	 	 	 	
 	Notional debt amount(1)	 	$	77,500	 	$	63,625	 	$	19,057	 	$	1,868	 	$	—	 	$	—	 	$	91	 	 	 	
 	 	Fixed rate payable	 	 	0.98	%	 	0.98	%	 	0.98	%	 	0.98	%	 	 	 	 	 	 	 	 	 	 	 	
 	 	Variable rate receivable(2)	 	 	0.52	%	 	1.23	%	 	2.34	%	 	3.37	%	 	 	 	 	 	 	 	 	 	 	 	
 	Notional debt amount(1)	 	$	75,004	 	$	50,942	 	$	24,680	 	$	38,434	 	$	23,137	 	$	—	 	$	518	 	 	 	
 	 	Fixed rate payable	 	 	1.34	%	 	1.34	%	 	1.34	%	 	1.34	%	 	1.34	%	 	 	 	 	 	 	 	 	
 	 	Variable rate receivable(2)	 	 	0.52	%	 	1.23	%	 	2.34	%	 	3.37	%	 	4.01	%	 	 	 	 	 	 	 	 	

(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 December 31, 2010, we did not have any off-balance sheet arrangements.

Critical Accounting Policies

        This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities as of the date the financial statements are available to be issued. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual audited results may vary from our estimates. Our significant accounting policies are detailed in Note 2—Accounting Policies to our consolidated financial statements. We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management.

        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 early 2011. As of December 31, 2010, no revenues had been recognized in our financial statements.

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        Exploration and Development Costs.    We follow the successful efforts method of accounting for costs incurred in crude 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 crude oil and natural gas to the surface are expensed.

        Receivables.    Our receivables consist of joint interest billings, notes and other receivables for which we generally do 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, and the owner's ability to pay its obligation, in consideration of future net revenues from the debtor's ownership interest in oil and natural gas properties we operate assuming we have a perfected lien against the debtor's interest, among other things. We do not have a perfected lien against the account receivable for which we have established an allowance for doubtful accounts as of December 31, 2010 and, therefore, did not consider the future net revenues in our assessment of the collectability of the receivable. Details concerning such account receivable are as follows.

        The agreement between Kosmos Energy Ghana HC ("Kosmos Ghana") and EO Group dated June 1, 2004 (the "EO Participation Agreement") created Kosmos Ghana's obligation to pay EO Group's 3.5% share of costs (the "EO Carry") under the WCTP Petroleum Agreement. Under the EO Participation Agreement, Kosmos Ghana is entitled to reimbursement for the development capital expenditures paid for EO Group (the "EO Development Costs"). The EO Participation Agreement also provides for the termination of the EO Carry on commencement of production from the WCTP Block, which occurred on November 28, 2010. Thereafter, EO Group was obligated to (i) pay their share of costs under the WCTP Petroleum Agreement pursuant to the joint operating agreement for the WCTP Block among Kosmos Ghana, Anadarko WCTP, Tullow Ghana, EO Group and Sabre Oil and Gas (the "WCTP JOA"), due to termination of the EO Carry; and (ii) reimburse Kosmos Ghana for EO Development Costs in the amount of $61.7 million. However, shortly thereafter, EO Group did not pay its share of WCTP JOA costs, was declared in default under the WCTP JOA in December 2010 and currently remains in default; with an unpaid balance of $3.7 million as of December 31, 2010. Each non-defaulting party must pay its proportionate share of the EO Group's default amounts and has done so. EO Group has also not reimbursed Kosmos Ghana for the $61.7 million in EO Development Costs and accordingly currently remains in default under the EO Participation Agreement.

        As a defaulting party under the WCTP JOA, EO Group loses its right to sell its share of oil production which is instead sold by the non-defaulting parties to repay the default amounts paid by the non-defaulting parties. If the default is not remedied within 60 days, EO Group may be required to withdraw from the WCTP Petroleum Agreement and the WCTP JOA and forfeit its interest to the non-defaulting parties (subject to the Government of Ghana's consent to such "transfer"). If such forfeiture occurs, the non-defaulting parties would proportionately own EO Group's interest in the WCTP Petroleum Agreement. However, a forfeiture could be disputed by EO Group in international arbitration under the WCTP JOA and further, enforcement would be subject to the discretion of English courts. Furthermore, the non-defaulting parties have not exercised the right to require EO Group's withdrawal and forfeiture from the WCTP Petroleum Agreement; but instead have agreed to temporarily hold off exercising such right, after recently becoming aware of a potential sale of EO Group's interest in the WCTP Petroleum Agreement. As the non-defaulting parties have the right to sell EO Group's share of oil production to repay default amounts paid by such non-defaulting parties, we believe any buyer would seek to cure any defaults in connection with any purchase of the EO Group's interest in the WCTP Petroleum Agreement so as to enable the buyer to exercise the right to sell the corresponding share of oil. As a result of this belief and the non-defaulting parties ability to repay default amounts owed to them through the sale of EO Group's share of oil production, we did

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not establish an allowance for doubtful accounts as of December 31, 2010 for EO Group's default under the WCTP JOA.

        Our ability to collect the $61.7 million owed to Kosmos Ghana under the EO Participation Agreement by the EO Group depends on the EO Group's ability to sell its share of the Jubilee oil production or sell all or part of their interest in the WCTP Petroleum Agreement. Because EO Group's share of production is being sold by the non-defaulting parties to pay EO Group's share of WCTP JOA costs (as discussed in the paragraph above), EO Group has not made any payments to reimburse Kosmos Ghana for the EO Development Costs. Unlike the WCTP JOA, the EO Participation Agreement does not provide specific remedies should EO Group fail to reimburse the EO Development Costs and such was not contemplated in 2004. If Kosmos Ghana is not paid, Kosmos Ghana would have a contractual claim against EO Group for the amounts owed under the EO Participation Agreement and our recourse would be to international arbitration. While we may prevail in such arbitration, our ability to fully collect under an arbitral award would be uncertain due to the EO Group likely not having the financial means to satisfy any such award as well as any enforcement thereof being subject to the discretion of the English courts. However, under the WCTP JOA, Kosmos has a pro rata right of first refusal to buy EO Group's interest in the WCTP Petroleum Agreement should EO Group seek to sell such interest. As stated above, we have recently become aware of a potential sale of EO Group's interest in the WCTP Petroleum Agreement. While the right of first refusal does not entitle us to withhold consent to any sale, we believe the existence of such right may provide commercial leverage in the sale process such that EO Group or any buyer of their interests will pay Kosmos Ghana the amounts owed under the EO Participation Agreement in connection with such sale. We believe a buyer may be hesitant to purchase an asset such as EO Group's interest in the WCTP Petroleum Agreement unless unresolved claims, such as our claim to be reimbursed for the EO Development Costs, are resolved. Furthermore, we believe that it is not uncommon for buyers of assets subject to rights of first refusals to require such rights to be preemptively waived to ensure the smooth execution of the purchase process. While we believe these factors will aid us in recovering amounts owed, without an absolute right to withhold consent to any sale of EO Group's interest, recovery through this method cannot be assured. Accordingly, we do not presently intend to bring a breach of contract dispute in an international arbitration proceeding against EO Group for their default under the EO Participation Agreement as we are attempting to resolve this matter amicably by affording EO Group time to arrange the potential sale of all or part of their interest in the WCTP Petroleum Agreement. However, should such sale not occur on a timely basis or should we not recover amounts owed to us, we intend to pursue legal remedies available to us against EO Group.

        After consideration of the circumstances outlined above, we determined the EO Development Costs were not fully collectible at December 31, 2010 and estimated our range of loss to be between 50% to 75% of the balance. $39.8 million (approximately 65%) of the $61.7 million EO Development Costs represents our best estimate of the potential uncollectible amounts at December 31, 2010. In determining our best estimate of the recoverable amount and the reserve amount, we considered a number of factors that included, but were not limited to, the following: the uncertainty in enforcing our reimbursement right under the EO Participation Agreement in international arbitration, discussions held with EO Group regarding recovery of amounts owed and their current ability to pay such amounts, the commercial leverage we believe is afforded under our pro rata right of first refusal discussed above, EO Group's lack of access to funds as evidenced by their inability to pay their share of WCTP JOA costs upon commencement of production on November 28, 2010 and their subsequent default, and the fact that our ability to collect the amounts owed to us by EO Group depends on either their ability to sell their share of Jubilee oil production or sell all or part of their interest in the WCTP Petroleum Agreement. With the share of Jubilee oil production presently being sold by the non-defaulting parties under the WCTP JOA to repay EO Group's default amounts under the WCTP JOA, we intend to closely follow the development of any potential sale of all or part of EO Group's interest in the WCTP Petroleum Agreement and otherwise continue to pursue full recovery of amounts owed. However, the $39.8 million reserve for uncollectible debt at December 31, 2010 reflects our best estimate of what amounts we actually will be able to recover.

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        Income Taxes.    We account for income taxes as required by the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("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 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 $20.6 million at December 31, 2009 primarily relating to capitalized operating expenses incurred during the development phase of the Jubilee Field. 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 no longer exist as of December 31, 2010. The net change in the valuation allowance of $3.6 million is due to the release of the Ghana valuation allowance netted against current year activity in Morocco and Cameroon.

        Additionally, in 2010, with the commencement of oil production in Ghana, the Company began to amortize its pre-operating development costs related to the Jubilee Field over a five-year period for tax purposes in accordance with Ghanaian tax law.

        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 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

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the November 28, 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 commenced on November 28, 2010. Such schedule anticipates that the FPSO producing from the field will reach its maximum production capacity of 120,000 boepd (28,200 boepd net to us) in the third quarter of 2011. Prices have been estimated based on prices utilized to calculate our standardized measure as of December 31, 2010. We have estimated our expenses based on current contracts and cost structures in place. Our current production is consistent with our development plan and there have been no negative indicators that our production forecast will not be met in 2011. Since year-end, our current production continues to increase according to our plan, currently achieving 60,000-70,000 boepd.

•
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.

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 $116.45 per barrel on March 2, 2011. Conversely, assuming a 25% increase in prices (or $99.19 per barrel which would still be less than the $116.45 per barrel price of Dated Brent on March 2, 2011, the date of our financial statements for the year ended December 31, 2010 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

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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 realized and, therefore, released the $20.6 million valuation allowance that was recorded as of December 31, 2009 and recognized $56.9 million of deferred tax assets generated during 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.

        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 and effective June 1, 2010 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.

        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 which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As of December 31, 2010, our net proved reserves totaled 56 Mmboe. 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 SEC and the FASB. The accuracy of these reserve estimates is a function of:

•
the engineering and geological interpretation of available data;

•
estimates regarding 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.

        Asset Retirement Obligations.    We account for asset retirement obligations as required by the FASB 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 as if that obligation were incurred on that 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 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. Estimating the future restoration and removal costs is difficult and requires management to make estimates and

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judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Additionally, asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

        Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is generally made to the oil and gas property balance.

        Impairment of Long-Lived Assets.    We review our 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 us are recorded at the lower of carrying amount or fair value less cost to sell.

New Accounting Pronouncements

        In June 2009, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 167, "Amendments to FASB Interpretation No. 46(R)," to address the effects of the elimination of the qualifying special purpose entity concept and other concerns about the application of key provisions of consolidation guidance for variable interest entities (VIEs). This Statement was codified into FASB ASC 810—Consolidation. More specifically, SFAS No. 167 requires a qualitative rather than a quantitative approach to determine the primary beneficiary of a VIE, it amends certain guidance pertaining to the determination of the primary beneficiary when related parties are involved, and it amends certain guidance for determining whether an entity is a VIE. Additionally, this Statement requires continuous assessments of whether an enterprise is the primary beneficiary of a VIE. The Company adopted this Statement on its effective date, January 1, 2010, and it did not have a material impact on the Company's financial position or results of operation.

        In January 2010, the FASB issued Accounting Standards Update ("ASU") No. 2010-03—Oil and Gas Reserve Estimation and Disclosures. This ASU amends the FASB's ASC Topic 932—Extractive Activities—Oil and Gas to align the accounting requirements of this topic with the Securities and Exchange Commission's final rule, "Modernization of the Oil and Gas Reporting Requirements" issued on December 31, 2008. In summary, the revisions in ASU No. 2010-03 modernize the disclosure rules to better align with current industry practices and expand the disclosure requirements for equity method investments so that more useful information is provided. More specifically, the main provisions include the following:

•
An expanded definition of oil and gas producing activities to include nontraditional resources such as bitumen extracted from oil sands.

•
The use of an average of the first-day-of-the-month price for the 12-month period, rather than a year-end price for determining whether reserves can be produced economically.

•
Amended definitions of key terms such as "reliable technology" and "reasonable certainty" which are used in estimating proved oil and gas reserve quantities.

•
A requirement for disclosing separate information about reserve quantities and financial statement amounts for geographical areas representing 15 percent or more of proved reserves.

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•
Clarification that an entity's equity investments must be considered in determining whether it has significant oil and gas activities and a requirement to disclose equity method investments in the same level of detail as is required for consolidated investments.

        ASU No. 2010-03 is effective for annual reporting periods ended on or after December 31, 2009, and it requires (1) the effect of the adoption to be included within each of the dollar amounts and quantities disclosed, (2) qualitative and quantitative disclosure of the estimated effect of adoption on each of the dollar amounts and quantities disclosed, if significant and practical to estimate and (3) the effect of adoption on the financial statements, if significant and practical to estimate. Adoption of these requirements did not significantly impact our reported reserves or our consolidated financial statements.

        In January 2010, the FASB issued ASU No. 2010-06—Improving Disclosures and Fair Value Measurements to improve disclosure requirements and thereby increase transparency in financial reporting. We adopted the update as of December 31, 2009, and it did not have a material impact on our financial position or results of operations.

Qualitative and Quantitative Disclosures about Market Risk

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

        The following table reconciles the changes that occurred in fair values of our open derivative contracts during the year ending December 31, 2010:

	 	Derivative Contracts Assets (Liabilities)	 	
 
	 	Commodities	 	Interest Rates	 	Total	 	
 
	 	(In thousands)
	 	
Fair value of contracts outstanding as of December 31, 2009	 	$	—	 	$	—	 	$	—	 	
Changes in contract fair value	 	 	(28,319	)	 	(11,805	)	 	(40,124	)	
Contract maturities	 	 	—	 	 	6,167	 	 	6,167	 	
 	 	 	 	 	 	 	 	
Fair value of contracts outstanding as of December 31, 2010	 	$	(28,319	)	$	(5,638	)	$	(33,957	)	
 	 	 	 	 	 	 	 	
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 have consisted of deferred premium puts and compound options (calls on puts) and have been entered into as required under the terms of our commercial debt facilities.

        We manage and control market and counterparty credit risk in accordance with policies and guidelines approved by the Board. 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. All of our commodity derivative contracts are with parties that are lenders under our commercial debt facilities. See Note 11—Derivative Financial Instruments in our consolidated financial statements for a description of the accounting procedures we follow relative to our derivative financial instruments.

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Commodity Price Sensitivity

        The following tables provide information about our oil derivative financial instruments that were sensitive to changes in oil prices as of December 31, 2010.

	 	Years Ending December 31	 	Liability Fair
Value at
December 31
2010	 	 	
 
	 	2011	 	2012	 	2013	 	 	 	 	
Oil Derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Deferred premium puts	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Average daily notional bbl volumes	 	 	11,332	 	 	4,625	 	 	2,515	 	$	23,279	 	 	
 	 	Weighted average floor price per bbl	 	$	72.01	 	$	62.74	 	$	61.73	 	 	 	 	 	
 	 	Weighted average deferred premium	 	$	8.90	 	$	7.04	 	$	7.32	 	 	 	 	 	
 	Compound options (calls on puts)(1)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Average daily notional bbl volumes	 	 	—	 	 	5,399	 	 	3,855	 	$	5,040	 	 	
 	 	Weighted average floor price per bbl	 	$	—	 	$	66.48	 	$	66.48	 	 	 	 	 	
 	 	Weighted average deferred premium	 	$	—	 	$	6.73	 	$	7.10	 	 	 	 	 	
Average forward Dated Brent oil prices(2)	 	$	105.22	 	$	104.50	 	$	103.27	 	 	 	 	 	

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

(2)
The average forward Dated Brent oil prices are based on February 22, 2011 market quotes.

Interest Rate Sensitivity

        At December 31, 2010, we had indebtedness outstanding under our commercial debt facilities of $1.05 billion, of which $570.0 million bore interest at floating rates. The weighted average annual interest rate incurred on this indebtedness for the year ended December 31, 2010 was approximately 7.1%. At this level of floating rate debt, if LIBOR increased by 10%, we would incur an additional $0.3 million of interest expense per year on our commercial debt facilities.

        As of December 31, 2010, the fair market value of our interest rate swaps was a net liability of approximately $5.6 million. If the LIBOR rate increased by 10%, we estimate the liability would decrease to approximately $4.1 million, and if the LIBOR rate decreased by 10%, we estimate the liability would increase to approximately $7.2 million.

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INDUSTRY

Global Oil and Gas Industry

Location of Kosmos' Assets in Africa and Related Market Accessibility

        West African offshore oil production is strategically situated to supply the growth markets of non-OECD countries, including those in Asia, as well as North American and European markets. The compound annual growth rate of oil reserves from 1989 to 2009 in Africa was 3.9% and from 1999 to 2009 was 4.2%. The following pie charts depict global proved reserve growth rates by region over the last 20 years.

Distribution of Proved Reserves in 1989, 1999 and 2009

        Source: BP Statistical Review.

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Brent Crude

        Oil produced from West Africa, including the Jubilee Field, is generally priced against Dated Brent crude. Brent crude is produced in the North Sea and is widely accepted by the oil and gas industry as most representative of the global physical standard for the oil market in comparison to other reference oils, such as West Texas Intermediate ("WTI") and Dubai. The location of the Jubilee Phase 1 FPSO offshore Ghana will allow us to sell our oil to the major refining markets of North America, Asia and Europe. Due to its quality, oil from the Jubilee Field is currently selling for a slight premium relative to Dated Brent.

West Africa

        Until the 1990's, exploration and production in West Africa was limited to shallow onshore and nearshore regions, in particular the Tertiary hydrocarbon plays of the Niger Delta and the Congo Fan petroleum systems. The advent of new 3D seismic, drilling and completion technology, as well as floating production systems and related sub-sea infrastructure, enabled operations to extend to deeper hydrocarbon plays in deep water. These hydrocarbon plays included under-explored petroleum systems of the Cretaceous along Atlantic margins of the African continent other than the Niger Delta and Congo Fan.

        The following diagram illustrates the depositional setting of the Late Cretaceous system offshore West Africa relative to the Early Cretaceous and Tertiary plays.

        The potential Late Cretaceous hydrocarbon plays were the niche in which Kosmos chose to build its initial exploration portfolio between 2004 and 2006, based upon overall assessment of West Africa petroleum systems. As a result of its detailed regional basin analysis, Kosmos targeted and was successful in accessing licenses in Ghana, Cameroon and Morocco that shared similar geologic characteristics largely focused on untested structural-stratigraphic traps within the Late Cretaceous. This strategy has since proved extremely successful, as the Kosmos discovery of the Jubilee Field in 2007 proved the commercial viability of the Late Cretaceous stratigraphic play along the West African Transform Margin. The Jubilee Field discovery was play-opening and has ushered in a new level of industry interest in similar concepts along the African continent, a play type that had been largely ignored prior to the discovery. Kosmos' technical leadership in this play enabled the company to

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establish a highly targeted license position in 2004 through 2006 that would be difficult to replicate in today's environment.

        Notwithstanding this, Kosmos will continue to pursue opportunities in these areas. However, the company's business development plan also includes new exploration ventures in other locations.

Ghana

Country Overview

        Ghana is located on West Africa's Gulf of Guinea a few degrees north of the Equator and has a population of approximately 24 million. English is the official and commercial language. Ghana's population is concentrated along the coast and in the principal cities of Accra and Kumasi.

        Ghana achieved its independence in 1957 under the leadership of Dr. Kwame Nkrumah. On March 6, 2007, Ghana celebrated its 50th anniversary since becoming independent. During the four decades after independence, Ghana underwent periodic changes in its governmental and constitutional structure. Since 1992, there have been four peaceful, democratic presidential elections. In December 2008, John Atta Mills was elected president. The political environment remains stable following the elections in 2008. The next presidential election is scheduled for 2012.

        The U.S. State Department characterizes the current government under President Mills as enjoying broad support among the Ghanaian population as it pursues its domestic political agenda. This agenda includes promoting free markets, protecting worker rights and reducing poverty, while supporting the rule of law and basic human rights. President Mills has also pursued an anti-corruption agenda. As part of its anti-corruption efforts, the Mills government required senior government officials to comply with the assets declaration law, changed the regulation to require public disclosure of assets, pledged greater transparency in government procurement, and sought to protect public funds.

        Ghana's stated goals are to accelerate economic growth, improve the quality of life for all Ghanaians, and reduce poverty through macroeconomic stability, increased private investment, broad-based social and rural development, and direct poverty-alleviation efforts. These plans have been supported by the international donor community.

        Ghana's potential to serve as a West African hub for U.S. and international businesses is enhanced by its relative political stability, overall sound economic management, low crime rate, competitive wages and an educated, English-speaking workforce. In addition, Ghana scores well among its peers on various measures of corruption, ranking 62 nd  out of 178 countries in Transparency International's 2010 Corruption Perceptions Index, vastly ahead of each of its peers according to a peer group selected by Standard & Poor's. Ghana is also the highest ranked among such peer group in the World Bank's Doing Business 2011 report, at fifth out of 46 sub-Sahara African countries included in such report.

        According to the U.S. State Department, the United States has enjoyed good relations with Ghana since Ghana's independence. The United States is among Ghana's principal trading partners and there is an active American Chamber of Commerce in Accra. Major companies operating in the country include 3M, Barclays, Cadbury, Coca Cola, IBM, Motorola, Pfizer and Unilever. Ghana was recognized for its economic and democratic achievements in 2006, when it signed a 5-year, $547 million anti-poverty compact with the United States' Millennium Challenge Corporation. The compact focuses on accelerating growth and poverty reduction through agricultural and rural development. The compact has three main components: enhancing the profitability of commercial agriculture among small farmers; reducing the transportation costs affecting agricultural commerce through improvements in transportation infrastructure, and expanding basic community services and strengthening rural institutions that support agriculture and agri-business.

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Oil and Gas Industry

        From a geological perspective, Ghana can be broadly divided into five sedimentary basins: the Voltain Basin, Keta Basin, Saltpond Basin, Tano Basin and Outer Ghanaian Basin. To date, the most successful basin for hydrocarbon exploration has been the Tano Basin, in which both the DT and WCTP Blocks are located. This basin contains a proven world-class petroleum system as evidenced by the Jubilee, Mahogany East, Odum, Tweneboa, Enyenra, Teak and Tweneboa Deep discoveries.

        On a combined basis, the DT and WCTP Blocks comprise an area of approximately 575,000 acres (2,325 square kilometers). This license position is equivalent to approximately 100 standard U.S. Gulf of Mexico deep water blocks, which is approximately 5,760 acres.

        Kosmos, Tullow and Anadarko are the primary upstream industry participants within the country. Additional oil and gas companies that hold interests in license areas within Ghana include Eni S.p.A., Hess, Vitol Group ("Vitol") and OAO LUKOIL. Prior to commencement of production from the Jubliee Field, Ghana produced less than 500 barrels of oil per day. As a result of the commencement of first oil from the Jubilee Field, Ghana is expected to produce up to approximately 120,000 bopd in 2011.

        The oil industry in Ghana is still in its early stages. A large portion of the data available about industry and geological characteristics comes from exploration and development activity undertaken by us and our block partners. See "Risk Factors—We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects."

Tano Basin

        The Tano Basin is situated offshore Ghana. The main hydrocarbon prospects in the Tano Basin are located in the Late Cretaceous stratigraphic section. The Late Cretaceous is a geological time period consisting of sediments that are 65 to 100 million years old. In particular, sediments from two stages of the Late Cretaceous period have provided notable exploration success: the Turonian (89 to 94 million years old) and the Campanian (71 to 84 million years old). These reservoirs are part of large submarine fans that were associated with the ancient river system sourced from the Volta River within Ghana. A number of these drainage systems exist along the ancient West African Transform Margin from Ghana to Sierra Leone. Drilling by Kosmos and its partners have yielded Turonian and Campanian reservoirs within the Tano Basin which have thickness weighted porosity and permeabilities of approximately 18% and 290mD, respectively. Specific reservoirs within these sequences can reach porosities of up to 25%.

        These Late Cretaceous fan systems are laterally extensive and have been deposited at the base of the continental slope. This has resulted in updip thinning of the reservoir intervals against Albian aged sequences. Subsequent uplift has caused the reservoirs, which lap onto underlying highs, to be folded into trapping geometries. This results in a series of combination structural-stratigraphic traps, which can be very large in size and in which most of the recent discoveries are located, including the Jubilee, Mahogany East, Odum and Enyenra Fields, all of which have been discovered since 2007.

Exploration History

        Offshore exploration drilling began in Ghana in 1956 when Gulf Oil drilled its first wildcat well. Signal Oil made the first oil discovery in Ghana in 1970 in the Saltpond Basin. This discovery, brought online in 1978, continues to produce a small amount of oil today. In the 1990s, deepwater licenses were awarded for the first time; it was during this era that international oil companies, including Amoco Corporation, Hunt Oil Company and Dana Petroleum plc ("Dana"), drilled exploration wells offshore Ghana. However, given a lack of commercial exploration success, these companies exited the region in subsequent years.

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        Ghanaian deepwater exploration activity started in earnest in 2007 when Kosmos drilled its first exploration well, Mahogany-1, on the WCTP Block and made the Mahogany discovery. This was followed in August 2007 by the Hyedua-1 well on the DT Block, which encountered the same oil accumulation. The results of the Hyedua-1 well confirmed the Mahogany-Hyedua field was one continuous structure, extending across the two blocks. This new field was renamed the Jubilee Field. Jubilee was one of the largest oil discoveries worldwide in 2007 and the largest find offshore West Africa in the last decade. The reservoirs in the Jubilee Field are of a very high quality.

        Between the first quarter of 2008 and end of 2009, the industry drilled several exploration wells offshore Ghana resulting in five further discoveries in the Tano Basin. The Odum and the Tweneboa Fields were discovered on the WCTP and the DT Blocks respectively. The Mahogany-3 well confirmed another similar aged accumulation adjacent to the Jubilee field while also discovering the Mahogany-Deep reservoir within the WCTP Block. In 2010, the Owo-1 discovery well was successfully completed by Kosmos and its block partners and the Onyina exploration well was drilled. The repeated success of our and our partners' exploration drilling to date has demonstrated that the northern part of the deepwater Tano Basin contains a world class petroleum system. In the block known as "Cape Three Points," Vitol discovered the Sankofa Field approximately 23 miles (38 kilometers) east of the Jubilee Field. The block known as "Cape Three Points Deepwater" also yielded a Cretaceous aged discovery when the Vanco-Lukoil partnership drilled the Dzata structure approximately 70 miles (112 kilometers) east of the Jubilee Field.

Cameroon

Country Overview

        Cameroon is located on West Africa's Gulf of Guinea adjacent to and south-east of Nigeria and has a population of approximately 20 million.

        Since gaining independence in 1960, Cameroon has had two presidents: Ahmadou Ahidjo and Paul Biya, to whom Mr. Ahidjo relinquished power voluntarily in 1982. The next election is scheduled for 2011. According to the U.S. State Department, the 1972 constitution (amended in 1996 and 2008) provides for a strong central government dominated by the executive.

        The U.S. State Department describes U.S. relations with Cameroon as close. While on the UN Security Council in 2002, Cameroon worked alongside the United States on a number of initiatives. The U.S. Government continues to provide substantial funding for international financial institutions, such as the World Bank, IMF, and African Development Bank, which provide financial and other assistance to Cameroon. Cameroon ranks 146 th  out of 178 countries in Transparency International's 2010 Corruption Perceptions Index.

Oil and Gas Industry

        The coastal and offshore portions of Cameroon are associated with two primary, geologically distinct basins, the Rio del Rey Basin in the north and the Douala Basin in the south. These basins extend into Equatorial Guinea, a country in which members of the Kosmos, management and technical teams have extensive experience exploring for and developing oil.

        Kosmos has interests in two blocks in Cameroon, the Ndian River Block in the Rio del Rey Basin, in which it operates with a 100% equity interest and the Perenco operated, Kombe-N'sepe Block located in the Douala Basin, in which Kosmos maintains a 35% interest. These licenses, which together comprise an area covering approximately 1.2 million acres (4,800 square kilometers), represent the equivalent of 205 standard deepwater U.S. Gulf of Mexico blocks.

        Oil and gas companies with interests in these basins include Bowleven PLC Oil and Gas Company, Hess, Noble Energy ("Noble"), Marathon Oil ("Marathon"), Sinopec Corp., Pecten Cameroon Company and Total S.A. ("Total"). During 2009, we estimate Cameroon produced approximately

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74,000 bopd, a reduction of 56% from its peak oil production of 167,600 bopd (which was achieved in 1986).

        Based on data from Cameroon's historical oil and gas production, we have made estimates about the geologic characteristics of Cameroon's basins. See "Risk Factors—We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects."

Douala Basin

        The Douala Basin contains a thick Late Cretaceous-Tertiary sedimentary sequence which is overlain by a Tertiary sequence associated with major transform faults resulting from the opening of the Atlantic in a similar fashion to the Tano Basin of Ghana, with which it shares very similar hydrocarbon play elements.

        The Douala Basin lies southeast of the Cameroon volcanic trend, which forms the northern limit of the basin. The basin extends south into the neighboring country of Equatorial Guinea, where oil is being produced from the Late Cretaceous Ceiba and Northern Block G developments. Notably, the Northern Block G and Ceiba fields were discovered by Triton, which was led by current members of the Kosmos technical and management teams. More recently, the northern part of the Douala Basin has seen successful drilling in the Miocene, with several oil and natural gas discoveries by Noble. Miocene uplift has resulted in the present day onshore part of the basin containing deepwater, Late Cretaceous reservoirs and seals. The onshore part of the basin is characterized by low-lying ground covered in forest, swamps and plantations.

Rio del Rey Basin

        Adjacent to the Niger Delta, the Rio del Rey Basin is a predominantly Tertiary petroleum system with existing production from primarily Miocene aged, shelf and deepwater four-way and three-way fault closures. Discoveries in this region include the Kombo, Ekundu and Abana oil fields. Adjacent to the basin's oil province, the industry has also had access to the Rio Del Rey Basin's outboard natural gas condensate play, which contains Marathon's giant Alba field located in Equatotial Guinea.

        The Rio del Rey Basin of Cameroon has been filled by sediments from the Niger Delta, which has been progressively expanding into the Atlantic Ocean at the mouth of the Niger-Benue River system. The vast majority of the offshore delta is located within Nigeria. The extreme eastern edge lies within territorial waters of Cameroon and provides most of the country's oil production.

        The Niger and Rio del Rey rivers provided sand to the basin throughout the Tertiary, and, as a result, the basin contains very good quality reservoirs. The reservoirs consist of individual channels and sand bodies. Porosities are as high as 35%, averaging 15% to 25%. Permeability is exceptional, commonly in the 1 to 2 darcy range.

        Most of the hydrocarbon traps in the Niger Delta are structural. Major trapping geometries include four-way and three-way fault closures. The productive fields are frequently located on the crests and flanks of these structures.

Exploration History

        The first hydrocarbon exploration in Cameroon took place in the 1920s and was concentrated in the onshore area of the Douala Basin. Initial exploration was encouraged by naturally occurring oil and natural gas seeps in the region. Exploration drilling in the Douala Basin, both onshore and offshore, remained sporadic until 1979, when ExxonMobil discovered the Sanaga Sud natural gas field. This discovery resulted in an exploration focus in structural traps in Albian and Aptian aged reservoirs. A limited number of Tertiary exploration wells have been drilled and in most cases these have encountered oil, including the Coco Marine-1 well drilled by ConocoPhillips Company in 2002. Between 2005 and 2009, a number of oil and natural gas discoveries were made in 3D seismic defined,

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Micoene, deepwater stratigraphic traps adjacent to the Kosmos license area. These discoveries are currently the focus of development drilling.

        In general, the Late Cretaceous section has been under-explored in the Douala Basin. One of the few exploration wells drilled was North Matanda-1, which encountered natural gas condensate. As with other petroleum provinces around the West African margin, exploration transitioned from shallow water structural traps, which could be defined using 2D seismic data, to deeper water Tertiary structural and stratigraphic traps, which were better defined with 3D seismic data. However, the intervening Late Cretaceous turbidite section, which has the best relationship with the potential source rock and evidence of large trapping geometries, has been overlooked. This is the focus of Kosmos' exploration program in the Douala Basin.

        In the Rio del Rey Basin, the first exploration well to be drilled was in 1967, however, it was not until 1972 that the first commercial oil discovery, Betika, was made by Elf Aquitaine ("Elf"). Exploration activity in the Rio del Rey Basin was most intense between 1977 and 1981, including several discoveries by Elf, Pecten International Co. and Total. Twenty oil fields located in shallow reservoirs were brought onstream between 1977 and 1984. This basin is still a major hydrocarbon producing basin with an estimated production rate of 48,000 bopd.

        In the 1990s this shallow water province was supplemented by deepwater drilling in the Equatorial Guinea sector of the Rio Del Rey Basin. This exploration yielded the giant Alba natural gas condensate field, operated by Marathon, as well as a number of satellite discoveries. These and more recent oil discoveries in the last two years in the Etinde block, IE and IF fields, all adjacent to the Kosmos operated Ndian River Block, have demonstrated effective reservoirs and the presence of a prolific petroleum system in the Isongo fairway, which extends through the core of the Ndian River Block, and is the focus of the Kosmos exploration strategy in the Rio del Rey Basin.

Morocco

Country Overview

        Morocco is located in the northwest portion of the African contintent, with a population of approximately 31 million. Arabic is the country's official language with French being the customary commercial language.

        The country gained its independence from France in 1956, and is currently governed by a constitutional monarchy, led since 2007 by Prime Minister Abbas El Fassi. Since 1999, King Mohammed VI has been head of state and ruling king. The most recent parliamentary elections were held in September 2007, after which Abbas El Fassi of the winning Istiqlal Party was appointed Prime Minister by the King. Morocco's next elections are scheduled for 2012. Morocco ranks 85 th  out of 178 countries in Transparency International's 2010 Corruption Perceptions Index.

        Kosmos' interests are geographically located offshore Western Sahara. The sovereignty of this territory has been in dispute since 1975. See "Risk Factors—A portion of our asset portfolio is in Western Sahara, and we could be adversely affected by the political, economic, and military conditions in that region. Our exploration licenses in this region conflict with exploration licenses issued by the Sahrawai Arab Democratic Republic.

        The oil industry in Morocco is still in its very early stages. The deepwater offshore Morocco has not yet proved to be a viable exploration area as, to date, there has not been a commercially successful discovery offshore. Accordingly, there is very limited data available about the industry and the geological characteristics of Morocco's basins. See "Risk Factors—We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects."

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Oil and Gas Industry

        There are six principal geological regions in Morocco: the Rif Domain Basins; the Western Meseta Region; the Atlasic Region; the Anti Atlas Basins; the Southern Onshore Basins and the Atlantic Passive Margin.

        Kosmos is the operator and 75% equity holder in the Boujdour Offshore Block located offshore Morocco in the Aaiun Basin, located along the Atlantic Passive Margin. This block comprises an area of more than 10.87 million acres (44,000 square kilometers), an area similar in scale to the entire deepwater fold belt of the U.S. Gulf of Mexico, or approximately 1,900 standard deepwater U.S. Gulf of Mexico blocks. Given the immense scale of the position, three distinct exploration play fairways have been identified by Kosmos and provide substantial oil and gas exploration optionality among relatively independent hydrocarbon concepts.

        Oil and gas companies with interests in Morocco have included Dana, Mærsk Olie og Gas As, Petroliam Nasional Berhad ("Petronas"), Repsol YPF S.A., San Leon Energy plc, Statoil ASA and Suncor Energy Inc. During 2009, we believe Morocco produced less than 300 boepd.

Aaiun Basin

        The Aaiun Basin extends for 684 miles (1,100 kilometers) along the northwest African margin from northern Mauritania, north into Morocco. Bordering the basin to the north is the non-commercial discovery of Cap Juby oil, which was discovered by the Standard Oil Company of New Jersey, now ExxonMobil, in 1969.

        While a frontier basin, a number of exploration wells have been drilled in the region that establish the presence of hydrocarbons as well as attractive reservoir objectives with good porosity and permeability. In particular, oil shows from wells within the shallower portions of the Boujdour Block of the Aaiun Basin and from adjacent onshore wells demonstrate the presence of an active regional petroleum system.

        Detailed sequence stratigraphic analysis suggests the presence of stacked deepwater turbidite systems throughout the basin. Previously available 2D seismic data as well as additional 2D and 3D seismic data acquired by Kosmos further suggest attractive reservoir targets trapped in very large four-way dip and three-way fault traps often enhanced by stratigraphic trap components.

        The oil seen in fields to the north of the Aaiun Basin and in wells onshore suggest there are at least two oil source rocks present in the basin, a Jurassic marine shale and Cenomanian Turonain marine shales. The Jurassic source rock is thought to provide the source for a number of oil and natural gas fields onshore Morocco.

Exploration History

        The first oil fields were discovered and developed in Morocco in the 1930s in the onshore Rharb Basin. In the 1960s and 1970s a number of wells were drilled to test features offshore in the southern part of Morocco and Western Sahara. These wells encountered evidence of oil and natural gas but did not test valid structures as they were located utilizing very poor geologic and geophysical seismic databases. Drilling by ExxonMobil immediately to the north of the Boujdour Offshore Block in the early 1970s resulted in the discovery of oil in Jurassic carbonates. Recent drilling onshore, adjacent to the Boujdour Offshore Block, by ONHYM has resulted in the recovery of heavy oil from Late Cretaceous silts and shales.

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BUSINESS

Overview

        We are an independent oil and gas exploration and production company focused on under-explored regions in Africa. Our current asset portfolio includes world-class discoveries and partially de-risked exploration prospects offshore Ghana, as well as exploration licenses with significant hydrocarbon potential onshore Cameroon and offshore Morocco. This portfolio, assembled by our experienced management and technical teams, will provide investors with differentiated access to both attractive exploration opportunities as well as defined, multi-year visibility in the reserve and production growth of our existing discoveries. With regard to the Jubilee Field, our de-risking activities have included the drilling of development wells, successful completion of fabrication, installation, hook-up and commissioning of the Jubilee Phase 1 facilities and initiation of production. With regard to our Ghanaian discoveries, our de-risking activities have included the drilling of successful appraisal wells. With regard to our Ghanaian prospects, these have been partially de-risked due to their similarity and proximity to our existing discoveries.

        After our formation in 2003, we acquired our current portfolio of exploration licenses and established a new, major oil province in West Africa with the discovery of the Jubilee Field in 2007. This was the first of our seven discoveries offshore Ghana; it was one of the largest oil discoveries worldwide in 2007 and the largest find offshore West Africa during the last decade. Oil production from the Jubilee Field offshore Ghana commenced on November 28, 2010, and we received our first oil revenues in early 2011. We expect gross oil production from the Jubilee Field to reach the design capacity of the FPSO facility used to produce from the field of 120,000 bopd in the third quarter of 2011. At that rate, the share of this gross oil production net to us is expected to be 28,200 bopd.

Our Competitive Strengths

World-class asset portfolio situated along the Atlantic Coast Margin of West Africa

        We targeted the Atlantic Margin of Africa as a focus area for exploration following a multi-year assessment of numerous exploration opportunities across a broad region. Our assessment was driven by our interpretation of geological and seismic data and by our internationally experienced technical, operational and management teams.

        We also make an in-depth evaluation of regional political risk, economic conditions and fiscal terms. Ghana, for example, enjoys relative political stability, overall sound economic management, a low crime rate, competitive wages and an educated, English-speaking workforce. The country also scores well among its peers on various measures of corruption, ranking 62 nd  out of 178 countries in Transparency International's 2010 Corruption Perceptions Index, vastly ahead of each of its peers according to a peer group selected by Standard & Poor's. Ghana is also the highest ranked among such peer group in the World Bank's Doing Business 2011 report, at fifth out of 46 sub-Sahara African countries included in such report.

        Our asset portfolio consists of seven discoveries including the Jubilee Field, which is one of the largest oil discoveries worldwide in 2007 and the largest find offshore West Africa in the last decade. Our other discoveries include Mahogany East, Odum, Tweneboa, Enyenra, Teak and Tweneboa Deep offshore Ghana, which have geologic characteristics similar to the Jubilee Field. In addition, we have identified 19 additional prospects offshore Ghana, 10 additional prospects in Cameroon and 19 additional prospects offshore Morocco. We expect to make new discoveries and to define additional prospects as our team continues to develop our current portfolio and identify and pursue new high-potential assets.

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Well-defined production and growth plan

        Our plan for developing the Jubilee Field provides visible, near-term cash generation and long-term growth opportunities. We estimate Jubilee Field Phase 1 daily gross production to reach the 120,000 bopd design capacity of the FPSO facility used at the field, in the third quarter of 2011. Within the next few years, we intend to expand upon the Jubilee Field Phase 1 development with three additional phases that are designed to maintain production and cash flow from partially de-risked locations. A phased drilling program allows us to develop Jubilee Phase I on a faster timeline and allowed us to achieve first oil production at an earlier date than traditional development techniques. See "—Our Strategy—Focus on rapidly developing our discoveries to initial production." In addition to Jubilee, we are currently in the development planning stage for Mahogany East, the pre-development planning stage for the Odum discovery, and the appraisal stage for the Tweneboa, Enyenra, Teak and Tweneboa Deep discoveries. We believe these assets provide additional mid-term production and cash flow opportunities to supplement the phased Jubilee Field development.

Significant upside potential from exploratory assets

        Since our inception we have focused on acquiring exploratory licenses in emerging petroleum basins in West Africa. This led to the assembly of a hydrocarbon asset portfolio of five licenses with significant upside potential and attractive fiscal terms. In Ghana, we believe our existing licenses offer substantial opportunities for significant growth in shareholder value as a result of numerous high value exploration prospects that are partially de-risked due to their similarity and proximity to our existing discoveries. We plan to drill two exploratory wells in Cameroon, one on our Kombe-N'sepe Block, which was spud in early 2011, and the other on our Ndian River Block in early 2012.

Oil-weighted asset portfolio in key strategic regions

        Our portfolio of assets consists primarily of oil discoveries and prospects. Oil comprises approximately 94% of our proved reserves which are associated with the Jubilee Field Phase 1 development. Due to its high quality and strategic geographic location, crude oil from the Jubilee Field is commanding a premium to Dated Brent, its reference commodity price. We expect our other Ghana discoveries and prospects, as well as our Cameroon and Morocco prospects, to maintain a primarily oil-weighted composition. We believe that global petroleum supply and demand fundamentals will continue to provide a strong market for our oil, and therefore we intend to continue targeting oil exploration and development opportunities. Furthermore, our geographic location in West Africa enables broad access to the major consuming markets of the North America, Asia and Europe, providing marketing flexibility. The ability to supply oil to global markets with reasonable transportation costs reduces localized supply/demand risks often associated with various international oil markets.

New ventures group focused on expanding our asset portfolio

        Our existing asset portfolio has already delivered large scale drill-bit success in Ghana and provided the opportunity for near- to mid-term reserve and production growth. While substantial exploration potential remains in our portfolio, we are also focused on renewing, replenishing and expanding our prospect inventory through the work of our new ventures group, which is tasked with executing an acquisition program to replicate this success. We believe this will permit timely delivery of further oil and natural gas discoveries for continued long-term reserve and production growth. We aim to leverage our unique exploration approach to maintain our successful track record with these new ventures.

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Seasoned and incentivized management and technical team with demonstrable track record of performance and value creation

        We are led by an experienced management team with a track record of successful exploration and development and public shareholder value creation. Our management team's average experience in the energy industry is over 20 years. Members of the senior management team successfully worked together both at and since their tenure at Triton, where they contributed to transforming Triton into one of the largest internationally focused independent oil and gas companies headquartered in the United States, prior to the sale of Triton to Hess for approximately $3.2 billion in 2001. Members of our management and senior technical team participated in discovering and developing multiple large scale upstream projects around the world, including the deepwater Ceiba Field, which was developed on budget and in record time offshore Equatorial Guinea, in West Africa in 2000. In the course of this work, the team acquired a track record for successful identification, acquisition and development of large offshore oil fields, and has been involved in discovering and developing over five Bboe. We believe our unique experience, industry relationships, and technical expertise have been critical to our success and are core competitive strengths.

        Furthermore, our management team has considerable experience in managing the political risks present when operating in developing countries, including working with the host governments to achieve mutually beneficial results, while at all times protecting the company's rights and asserting investors' interests.

        Our management team currently owns and will continue to own a significant direct ownership interest in us immediately following the completion of this offering. We believe our management team's direct ownership interest as well as their ability to increase their holdings over time through our long-term incentive plan aligns management's interests with those of our shareholders. This long-term incentive plan will also help to attract and retain the talent to support our business strategy.

Strong financial position

        Since inception we have been backed by our Investors, namely Warburg Pincus and The Blackstone Group, each supporting our initial growth with substantial equity investments. Each Investor will retain a significant interest in Kosmos following this offering. With the proceeds from this offering, our cash on hand and our commercial debt commitments, we believe we will possess the necessary financial strength to implement our business strategy through 2013. As of December 31, 2010, we had approximately $212 million of total cash on hand, including $112 million of restricted cash, and $205 million of committed undrawn capacity under our previous commercial debt facilities. In March 2011 we entered into a new $2.0 billion commercial debt facility, which may be increased to $3.0 billion upon us obtaining additional commitments. At March 31, 2011 we had $1.3 billion outstanding, $151 million of availability and $700 million of committed undrawn capacity under such facility. In addition, we have demonstrated the ability to raise capital, having secured commitments for approximately $1.05 billion of private equity funding in the last seven years and recently put in place the $2.0 billion commercial debt facility. Furthermore, we received our first oil revenues in early 2011 from the Jubilee Field, and accordingly a portion of these revenues will be used to fund future exploration and development activities.

Our Strategy

        In the near-term, we are focused on maximizing production from the Jubilee Field Phase 1 development, as well as accelerating the development of our other discoveries. Longer term, we are focused on the acquisition, exploration, appraisal and development of existing and new opportunities in Africa, including identifying, capturing and testing additional high-potential prospects to grow reserves and production. By employing our competitive advantages, we seek to increase net asset value and

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deliver superior returns to our shareholders. To this end, our strategy includes the following components:

Grow proved reserves and production through accelerated exploration, appraisal and development

        In the near-term, we plan to develop and produce our current discoveries offshore Ghana, including Jubilee and Mahogany East, and upon a declaration of commerciality and approval of a plan of development, Odum, Tweneboa, Enyenra, Teak and Tweneboa Deep. Additionally, we plan to drill-out our portfolio of exploration prospects offshore Ghana, which have been partially de-risked by our successful drilling program to date. If successful, these prospects will deliver proved reserve and production growth in the medium term. In the longer term, we plan to drill-out our existing prospect inventory on our other licenses in West Africa and to replicate our exploratory success through new ventures in other regions of the African continent.

Apply our technically-driven culture, which fosters innovation and creativity, to continue our successful exploration and development program

        We differentiate ourselves from other E&P companies through our approach to exploration and development. Our senior-most geoscientists and development engineers are pivotal to the success of our business strategy. We have created an environment that enables them to focus their knowledge, skills and experience on finding and developing oil fields. Culturally, we have an open, team-oriented work environment that fosters both creative and contrarian thinking. This approach allows us to fully consider and understand risk and reward and to deliberately and collectively pursue strategies that maximize value. We used this philosophy and approach to unlock the Tano Basin offshore Ghana, a significant new petroleum system that the industry previously did not consider either prospective or commercially viable.

Focus on rapidly developing our discoveries to initial production

        We focus on maximizing returns through phasing the appraisal and development of discoveries. There are numerous benefits to pursuing a phased development strategy to support our production growth plan. Importantly, a phased development strategy provides for first oil production earlier than what would otherwise be possible using traditional development techniques, which are disadvantaged by more time-consuming, costly and sequential appraisal and pre-development activities. This approach optimizes full-field development and a phased development approach allows numerous activities to be performed in a parallel rather than a sequential manner. The initial phase of the Jubilee Field, for example, could be brought on production at an earlier date by using a phased drilling program, since this approach allowed appraisal and pre-development activities to be performed in parallel and detailed engineering could be conducted simultaneously with the execution of the project. In contrast, a traditional development approach consists of full appraisal, conceptual engineering, preliminary engineering, detail engineering, procurement and fabrication of facilities, development drilling and installation of facilities for the full-field development, all performed in sequence, before first production is achieved. This adds considerably more time to the development timeline.

        A phased approach provides dynamic reservoir performance information that allows the full-field development to be optimized. This approach also maximizes net asset value by refining appraisal and development plans based on experience gained in initial phases of production and by leveraging existing infrastructure as we implement subsequent phases of development. Other benefits include minimizing upfront capital costs, reducing execution risks through smaller initial infrastructure requirements, and enabling cash flow from the initial phase of production to fund a portion of capital costs for subsequent phases.

        First oil from the Jubilee Field commenced on November 28, 2010, and we received our first oil revenues in early 2011. This development timeline from discovery to first oil is significantly less than

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the industry average of seven to ten years and is a record for a deepwater development at this water depth in West Africa. This condensed timeline reflects the lessons learned by members of our seasoned management while at Triton and during their time at other major deepwater operators. At Triton, the team took the 50,000 bopd Ceiba Field offshore Equatorial Guinea from discovery to first oil in fourteen months. Additionally, our development team has led other larger scale deepwater developments, such as Neptune and Mensa in the U.S. Gulf of Mexico. These experiences drove the 42-month record timeline from discovery to first oil achieved by the significantly larger Jubilee Field Phase 1 development.

        Subsequent phases of the development of the Jubilee Field will consist of drilling infill wells that target the currently producing UM3 and LM2 reservoirs. Production and reservoir performance is being monitored closely at present and planning is ongoing to initiate infill drilling in late 2011 or early 2012. The timing and scope of subsequent phases will be defined based on reservoir performance.

Identify, access and explore emerging exploratory regions and hydrocarbon plays

        Our management and exploration team have demonstrated an ability to identify regions and hydrocarbon plays that will yield multiple large commercial discoveries. We will continue to utilize our systematic and proven geologically focused approach to emerging petroleum systems where source rocks and reservoirs have been established by previous drilling and where seismic data suggests hydocarbon accumulations are likely to exist, but where commercial discoveries have yet to be made. We believe this approach reduces the exploratory risk in poorly understood, under-explored or otherwise overlooked hydrocarbon basins that offer significant oil potential. This was the case with respect to the Late Cretaceous stratigraphy of West Africa, the niche in which we chose to build our exploration portfolio between 2004 and 2006. Our licenses in Ghana, Cameroon and Morocco share similar geologic characteristics focused on untested structural-stratigraphic traps. This exploration focus has proved successful, with the discovery of the Jubilee Field ushering in a new level of industry interest in Late Cretaceous petroleum systems across the African continent, including play types that had previously been largely ignored.

        This approach and focus, coupled with a first-mover advantage, provide a competitive advantage in identifying and accessing new strategic growth opportunities. We expect to continue to seek new opportunities where oil has not been discovered or produced in meaningful quantities by leveraging the skills of our experienced technical team. This includes our existing areas of interest as well as selectively expanding our reach into other locations in Africa or beyond that offer similar geologic characteristics.

Acquire additional exploration assets

        We intend to utilize our experience and expertise and leverage our reputation and relationships to selectively acquire additional exploration licenses and maintain a portfolio of undrilled exploration prospects. We plan to farm-in to new venture opportunities as well as to undertake exploration in emerging basins, plays and fairways to enhance and optimize our position in Africa. In addition, we plan to expand our geographic footprint in a focused and systematic fashion. Consistent with this strategy, we also evaluate potential corporate acquisition opportunities as a source of new ventures to replenish and expand our asset portfolio.

Kosmos Exploration Approach

        The Kosmos exploration philosophy is deeply rooted in a fundamental, geologically based approach geared towards the identification of misunderstood, under-explored or overlooked petroleum systems. This process begins with detailed geologic studies that methodically assess a particular region's subsurface, with particular consideration to those attributes that lead to working petroleum systems.

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The process includes basin modeling to predict oil charge and fluid migration, as well as stratigraphic and structural analysis to identify reservoir/seal pair development and trap definition. This analysis integrates data from previously drilled wells and seismic data available to Kosmos. Importantly, this approach also takes into account a detailed analysis of geological timing to ensure that we have appropriate understanding of whether the sequencing of geological events would support and preserve hydrocarbon accumulation. Once an area is high-graded based on this play/fairway analysis, detailed geophysical analysis is conducted to identify prospective traps of interest. We also work with NSAI in assessing our prospects.

        Alongside the subsurface analysis, Kosmos performs a detailed analysis of country-specific risks to gain a comprehensive understanding of the "above-ground" dynamics, which may influence a particular region's relative desirability from an overall oil and natural gas operating and risk-adjusted returns perspective.

        This iterative and comprehensive process is employed in both areas that have existing oil and natural gas production, as well as those regions that have yet to achieve commercial hydrocarbon production. The process is carried out by a small group of experienced technical personnel who individually and as a team have a proven track record of exploration success. Collectively, our team has been involved in the aggregate discovery of over five Bboe during their careers. Furthermore, key members of our technical team have worked together since the mid 1990s at Triton. This team includes individuals with complementary areas of expertise which span the exploration process, including geology, geophysics, geochemistry, reservoir engineering and other associated disciplines. Integration of these disciplines is key to creating Kosmos' competitive advantage.

        Once an area of interest has been identified, Kosmos actively targets licenses over the particular basin or fairway in order to achieve an early mover or in many cases a first-mover advantage. In terms of license selection, Kosmos targets specific regions that have sufficient size to provide scale should the exploration concept prove successful. Additional objectives include long-term contract duration to enable the "right" exploration program to be executed, play type diversity to provide multiple exploration concept options, prospect dependency to enhance the chance of replicating success and sufficiently attractive fiscal terms to maximize the commercial viability of discovered hydrocarbons.

        The Kosmos exploration process, as well as its expertise in capturing attractive leasehold positions, has proven very successful over time. For instance, while at Triton, members of the Kosmos technical team utilized the process described above to capture and successfully drill the Ceiba Field (and North Block G Complex) in Equatorial Guinea, Cusiana and Cupiagua Fields in Colombia and eight distinct natural gas fields located within the Malaysia—Thailand Joint Development Area in the Gulf of Thailand. The Cusiana/Cupiagua fields were discovered in 1988 and 1993, respectively, and we believe hold approximately 1,700 Mmboe of reserves on a combined basis. The Ceiba and North Block G Complex, discovered between 1998 and 1999, we believe hold approximately 525 Mmboe of reserves. Triton's Malaysia—Thailand Joint Development Area discoveries, initially drilled between 1995 and 1997, we believe hold approximately 950 Mmboe of reserves.

        This same process also led to the early identification of the Late Cretaceous play along the margin of North and West Africa and are highly attractive from a hydrocarbon exploration perspective. Based on its assessment using this model, Kosmos acquired its current licenses in Ghana, Cameroon and Morocco from 2004 to 2006.

        In addition to our current exploration portfolio, Kosmos continuously evaluates new opportunities to grow its portfolio of assets and its inventory of drillable prospects while simultaneously maintaining the rigorous technical standards of our exploration approach. For instance, Kosmos' new venture group reviews the exploration potential of the West and East coast African margins in order to identify overlooked and under-explored plays which may be available for direct licensing or acreage opportunities for farm-ins. This involves studying areas adjacent to our current licenses in order to

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leverage our considerable knowledge base about these petroleum systems, extrapolating new petroleum play systems and concepts along the margins and, based on our exploration approach, identifying new, emerging or under-explored petroleum systems. As part of this process, Kosmos has evaluated over 120 new venture opportunities along the West and East African margins and some African interior rift basins. While to date the work of our new venture group has not yet led to the acquisition of any licenses or acreage, we believe such a group is essential in implementing our strategy of acquiring additional exploration areas.

        Kosmos has also begun to apply the same exploration approach in order to evaluate areas outside of the African continent, in particular Brazil, broader Latin America and Asia. This process will expose us to a broader new ventures opportunity set and facilitate continued and increased future growth.

Our Discoveries and Prospects

        Information about our discoveries is summarized in the following table. In interpreting this information, specific reference should be made to the subsections of this prospectus titled "Risk Factors—Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling" and "Risk Factors—We are not, and may not be in the future, the operator on all of our license areas and do not, and may not in the future, hold all of the working interests in certain of our license areas. Therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and to an extent, any non-wholly owned, assets."
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discoveries	 	License	 	Aerial Extent
(acres)	 	Kosmos
Working
Interest	 	Block Operator(s)	 	Stage	 	Type	 	Expected
Year of PoD
Submission	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Jubilee Field Phase 1(1)(2)	 	WCTP/DT(3)	 	 	8,300	 	 	23.4913	%(5)	Tullow/Kosmos(6)	 	Production	 	Deepwater	 	2008(2)	
 	Jubilee Field subsequent phases(2)	 	WCTP/DT(3)	 	 	4,600	 	 	23.4913	%(5)	Tullow/Kosmos(6)	 	Development	 	Deepwater	 	2011	
 	Mahogany East	 	WCTP(4)	 	 	6,600	 	 	30.8750	%	Kosmos	 	Development planning	 	Deepwater	 	2011	
 	Odum	 	WCTP(4)	 	 	1,900	 	 	30.8750	%	Kosmos	 	Development planning	 	Deepwater	 	2011	
 	Teak	 	WCTP(4)	 	 	23,000	 	 	30.8750	%	Kosmos	 	Appraisal	 	Deepwater	 	2013	
 	Tweneboa	 	DT(4)	 	 	19,900	 	 	18.0000	%	Tullow	 	Appraisal	 	Deepwater	 	2012(7)	
 	Enyenra	 	DT(4)	 	 	28,100	 	 	18.0000	%	Tullow	 	Appraisal	 	Deepwater	 	2013	
 	Tweneboa Deep	 	DT(4)	 	 	20,100	 	 	18.000	%	Tullow	 	Appraisal	 	Deepwater	 	2014	

(1)
For information concerning our estimated proved reserves in the Jubilee Field as of December 31, 2010, see "—Our Reserves."

(2)
The Jubilee Phase 1 PoD was submitted to Ghana's Ministry of Energy on December 18, 2008 and was formally approved on July 13, 2009. The Jubilee Phase 1 PoD details the necessary wells and infrastructure to develop the UM3 and LM2 reservoirs. Oil production from the Jubilee Field offshore Ghana commenced on November 28, 2010, and we received our first oil revenues in early 2011. We intend to submit or amend PoDs for other reservoirs within the unit for the Jubilee Field subsequent phases to Ghana's Ministry of Energy for approval in order to extend the production plateau of the Jubilee Field.

(3)
The Jubilee Field straddles the boundary between the WCTP Block and the DT Block offshore Ghana. Consistent with the Ghanaian Petroleum Law, the WCTP and DT Petroleum Agreements and as required by Ghana's Ministry of Energy, in order to optimize resource recovery in this field, we entered into the UUOA on July 13, 2009 with GNPC and the other block partners of each of these two blocks. The UUOA governs the interests in and development of the Jubilee Field and created the Jubilee Unit from portions of the WCTP Block and the DT Block.

(4)
GNPC has the option to acquire additional paying interests in a commercial discovery on the WCTP Block and the DT Block of 2.5% and 5.0%, respectively. In order to acquire the additional paying interest, GNPC must notify the contractor of its intention to acquire such interest within sixty to ninety days of the contractor's notice to Ghana's Ministry of Energy of a commercial discovery. These interest percentages do not give effect to the exercise of such options.

(5)
These interest percentages are subject to redetermination of the working interests in the Jubilee Field pursuant to the terms of the UUOA. See "Risk Factors—The unit partners' respective interests in the Jubilee Unit are subject to redetermination and our interests in such unit may decrease as a result" and "—Material Agreements—Exploration Agreements—Ghana—Jubilee Field Unitization." GNPC has exercised its WCTP and DT PA options, with respect to the Jubilee Unit, to acquire an additional unitized paying interest of 3.75% in the Jubilee Field. The Jubilee Field interest percentages give effect to the exercise of such option.

(6)
Kosmos is the Technical Operator and Tullow is the Unit Operator of the Jubilee Unit. See "—Material Agreements—Exploration Agreements—Ghana—Jubilee Field Unitization."

(7)
Appraisal of the Tweneboa oil and gas condensate reservoirs is expected to continue through 2011. As outlined by the DT Petroleum Agreement, a submission of a PoD would be required for an oil development by 2012, while the submission of a PoD related to a natural gas development would be required by 2013.

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Ghana Well Information

        Information about the wells we have drilled on our license areas in Ghana is summarized in the following table.

	 	Operator	 	Spud Date(1)	 	Total
Depth
(feet)	 	Net
Hydrocarbon
Pay
(feet)	 	Status(2)	 	Comments	
Jubilee	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
J-09 (Mahogany-1)	 	Kosmos	 	05/30/07	 	 	12,553	 	 	321	 	Producing	 	Discovery well for Jubilee in WCTP Block. Drill stem tested at rates in excess of 20,500 bopd. Lower completion installed.	
Hyedua-1	 	Tullow	 	07/27/07	 	 	13,130	 	 	180	 	Plugged Back	 	Downdip confirmation well in DT Block.	
 	J-10 Water Injector ("WI") (Hyedua-1BP1)	 	Tullow	 	07/27/07	 	 	12,631	 	 	136	 	Completion Pending	 	Whole core obtained. Injectivity test conducted at rates in excess of 20,000 bwpd.	
J-16GI Gas Injectors ("GI") (Mahogany-2)	 	Tullow	 	03/06/08	 	 	11,296	 	 	164	 	Injection Ready	 	Updip confirmation well for Jubilee reservoirs. Whole core obtained. Two Drill Stem Tests ("DSTs") conducted.	
J-08 (Hyedua-2)	 	Tullow	 	10/09/08	 	 	12,018	 	 	180	 	Producing	 	Drill stem tested at rates in excess of 16,500 bopd. Whole core obtained.	
J-04	 	Tullow	 	01/17/09	 	 	15,121	 	 	90	 	Plugged Back	 	Tested the Southeastern edge of the Jubilee fairway.	
 	J-04 Sidetrack ("ST")	 	Tullow	 	01/17/09	 	 	13,803	 	 	199	 	Completion Pending	 	Observation well for interference testing.	
J-01	 	Tullow	 	03/18/09	 	 	12,411	 	 	140	 	Producing	 	 	
J-02	 	Tullow	 	03/25/09	 	 	13,829	 	 	186	 	Producing	 	Observation well for interference testing.	
J-11WI	 	Tullow	 	05/06/09	 	 	13,822	 	 	121	 	Completion Pending	 	Down structure water injector—net reservoir 281 feet.	
J-12WI	 	Tullow	 	05/11/09	 	 	14,081	 	 	188	 	Injecting	 	Down structure water injector—net reservoir 319 feet.	
J-15WI	 	Tullow	 	05/14/09	 	 	16,949	 	 	47	 	Completion Pending	 	Only drilled through Upper Mahogany—down structure water injector-net reservoir 87 feet.	
J-07	 	Tullow	 	05/19/09	 	 	13,599	 	 	121	 	Plugged Back	 	Whole core obtained.	
 	J-07ST	 	Tullow	 	05/19/09	 	 	13,701	 	 	116	 	Producing	 	 	
J-03	 	Tullow	 	09/29/09	 	 	12,507	 	 	173	 	Completion Pending	 	Lower completion installed.	
J-05	 	Tullow	 	07/08/09	 	 	13,753	 	 	193	 	Completion Pending	 	Lower completion installed.	
J-17	 	Tullow	 	10/07/09	 	 	19,390	 	 	174	 	Plugged Back	 	Only drilled through Upper Mahogany reservoirs.	
 	J-17STGI	 	Tullow	 	10/07/09	 	 	19,574	 	 	197	 	Completion Pending	 	 	
J-13WI	 	Tullow	 	10/10/09	 	 	13,058	 	 	143	 	Completion Pending	 	Down structure water injector—net reservoir 348 feet.	
J-14WI	 	Tullow	 	10/14/09	 	 	13,999	 	 	77	 	Injecting	 	Down structure water injector—net reservoir 334 feet.	
Mahogany East	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mahogany-3	 	Kosmos	 	11/27/08	 	 	14,262	 	 	108	 	Suspended	 	Discovery well for Mahogany Deep.	
Mahogany-4	 	Kosmos	 	08/28/09	 	 	12,074	 	 	141	 	Suspended	 	Updip confirmation well for the Mahogany East reservoirs.	
Mahogany Deep-2	 	Kosmos	 	09/29/09	 	 	14,193	 	 	49	 	Suspended	 	Drilled to delineate deep reservoirs—net reservoir of 384 feet.	
Mahogany-5	 	Kosmos	 	04/18/10	 	 	13,084	 	 	75	 	Suspended	 	Eastern confirmation of Mahogany East reservoirs.	
Odum	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Odum-1	 	Kosmos	 	01/18/08	 	 	11,109	 	 	72	 	Suspended	 	Discovery well for Odum.	
Odum-2	 	Kosmos	 	11/12/09	 	 	8,222	 	 	66	 	Suspended	 	Confirmation well for Odum.	
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	 	Operator	 	Spud Date(1)	 	Total
Depth
(feet)	 	Net
Hydrocarbon
Pay
(feet)	 	Status(2)	 	Comments	
Tweneboa	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Tweneboa-1	 	Tullow	 	01/26/09	 	 	13,002	 	 	69	 	Suspended	 	Discovery well for Tweneboa condensate pays.	
Tweneboa-2	 	Tullow	 	12/06/09	 	 	13,878	 	 	105	 	Suspended	 	Confirmation well for Tweneboa. Discovery of Central Oil Channel below condensate pays. Whole core obtained.	
Tweneboa-3	 	Tullow	 	11/26/10	 	 	12,811	 	 	29	 	Plugged back	 	Confirmation well for Tweneboa.	
Tweneboa-3ST	 	Tullow	 	12/22/10	 	 	12,816	 	 	112	 	Suspended	 	 	
Tweneboa-4	 	Tullow	 	1/16/11	 	 	13,146	 	 	59	 	Suspended	 	Surface hole section drilled early as part of batch program. Drilling resumed 3/15/11.	
Onyina	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Onyina-1	 	Tullow	 	09/25/10	 	 	 	 	 	—	 	Abandoned	 	Dry hole.	
Enyenra (formerly known as Owo)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Owo-1	 	Tullow	 	06/10/10	 	 	12,766	 	 	174	 	Plugged Back	 	Discovery well for Enyenra.	
 	Owo-1 ST1	 	Tullow	 	07/28/10	 	 	13,117	 	 	115	 	Suspended	 	Lateral confirmation well for Enyenra channels, and discovery wells for deeper condensate pays. Whole core obtained.	
Enyenra-2	 	Tullow	 	01/22/11	 	 	13,887	 	 	121	 	Suspended	 	Downdip confirmation well for Enyenra channels. Discovery well for Tweneboa Deep.	
Teak	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Teak-1	 	Kosmos	 	12/21/10	 	 	10,398	 	 	239	 	Suspended	 	Discovery well for Teak.	
Teak-2	 	Kosmos	 	2/12/11	 	 	11,184	 	 	89	 	Suspended	 	Drilled fault block adjacent to Teak-1 discovery.	
Dahoma	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Dahoma-1	 	Kosmos	 	02/04/10	 	 	14,403	 	 	—	 	Abandoned	 	Dry hole.	

(1)
In connection with our side-track wells, "spud date" refers to the date we commenced drilling such well.

(2)
These terms have the following meanings:
 	 	 	
Abandoned	 	Exploration / appraisal well that was deemed to have no further utility. The well was permanently abandoned, per approved government procedures.	

Completion Pending	
 	
Production / Injection casing has been installed across the target interval as part of the normal drilling operations, and the well is scheduled / approved to have a completion installed to facilitate production / injection per the applicable PoD.	

Injection Ready	
 	
Injection well has been drilled and completed. All well equipment is in place to commence injection.	

Plugged Back	
 	
Well that has cement set across productive interval to facilitate production from sidetrack well.	

Production Ready	
 	
Production well has been drilled and completed. All well equipment is in place to commence production.	

Suspended	
 	
Exploration / appraisal well that has had production casing installed across the target interval. However, plans to utilize the well as part of a development have not yet been approved.	
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Prospect Information

        Information about our prospects is summarized in the following table.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Prospect	 	License	 	Aerial
Extent
(acres)	 	Kosmos
Working
Interest (%)	 	Block
Operator	 	Type	 	Projected
Spud Year(4)	
Ghana(1)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Banda Campanian	 	WCTP	 	 	8,800	 	 	30.875	 	Kosmos	 	Deepwater	 	2011(5)	
 	Banda Cenomanian	 	WCTP	 	 	15,000	 	 	30.875	 	Kosmos	 	Deepwater	 	2011(5)	
 	Makore	 	WCTP	 	 	12,300	 	 	30.875	 	Kosmos	 	Deepwater	 	2011	
 	Odum East	 	WCTP	 	 	3,100	 	 	30.875	 	Kosmos	 	Deepwater	 	2012	
 	Sapele	 	WCTP	 	 	19,100	 	 	30.875	 	Kosmos	 	Deepwater	 	2012	
 	Funtum	 	WCTP	 	 	6,700	 	 	30.875	 	Kosmos	 	Deepwater	 	2012	
 	Assin	 	WCTP	 	 	2,600	 	 	30.875	 	Kosmos	 	Deepwater	 	2012	
 	Okoro	 	WCTP	 	 	4,600	 	 	30.875	 	Kosmos	 	Deepwater	 	Post 2012	
 	Late Cretaceous WCTP Play (4 identified targets)	 	WCTP	 	 	8,100	 	 	30.875	 	Kosmos	 	Deepwater	 	Post 2012	
 	Walnut	 	DT	 	 	2,900	 	 	18.000	 	Tullow	 	Deepwater	 	2012	
 	DT Sapele	 	DT	 	 	4,600	 	 	18.000	 	Tullow	 	Deepwater	 	2012	
 	Wassa	 	DT	 	 	8,900	 	 	18.000	 	Tullow	 	Deepwater	 	Post 2012	
 	Adinkra	 	DT	 	 	1,300	 	 	18.000	 	Tullow	 	Deepwater	 	Post 2012	
 	Oyoko	 	DT	 	 	1,900	 	 	18.000	 	Tullow	 	Deepwater	 	Post 2012	
 	Ananta	 	DT	 	 	1,600	 	 	18.000	 	Tullow	 	Deepwater	 	Post 2012	
Cameroon(2)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	N'gata	 	Kombe-N'sepe	 	 	6,100	 	 	35.000	 	Perenco	 	Onshore	 	2011(6)	
 	N'donga	 	Kombe-N'sepe	 	 	6,400	 	 	35.000	 	Perenco	 	Onshore	 	Post 2012	
 	Disangue	 	Kombe-N'sepe	 	 	5,200	 	 	35.000	 	Perenco	 	Onshore	 	Post 2012	
 	Pongo Songo	 	Kombe-N'sepe	 	 	2,400	 	 	35.000	 	Perenco	 	Onshore	 	Post 2012	
 	Bonongo	 	Kombe-N'sepe	 	 	3,100	 	 	35.000	 	Perenco	 	Onshore	 	Post 2012	
 	Coco East	 	Kombe-N'sepe	 	 	2,800	 	 	35.000	 	Perenco	 	Onshore	 	Post 2012	
 	Liwenyi	 	Ndian River	 	 	4,000	 	 	100.000	 	Kosmos	 	Onshore	 	2012	
 	Liwenyi South	 	Ndian River	 	 	1,600	 	 	100.000	 	Kosmos	 	Onshore	 	Post 2012	
 	Meme	 	Ndian River	 	 	3,800	 	 	100.000	 	Kosmos	 	Onshore	 	Post 2012	
 	Bamusso	 	Ndian River	 	 	12,100	 	 	100.000	 	Kosmos	 	Onshore	 	Post 2012	
Morocco(3)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Gargaa	 	Boujdour Offshore	 	 	13,900	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Argane	 	Boujdour Offshore	 	 	11,600	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Safsaf	 	Boujdour Offshore	 	 	22,400	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Aarar	 	Boujdour Offshore	 	 	8,100	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Zitoune	 	Boujdour Offshore	 	 	10,000	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Al Arz	 	Boujdour Offshore	 	 	13,400	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Felline	 	Boujdour Offshore	 	 	13,500	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Nakhil	 	Boujdour Offshore	 	 	6,500	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	
 	Barremian Tilted Fault Block Play (11 identified structures)	 	Boujdour Offshore	 	 	68,000	 	 	75.000	 	Kosmos	 	Deepwater	 	Post 2012	

(1)
GNPC has the option to acquire additional paying interests in a commercial discovery on the WCTP Block and the DT Block of 2.5% and 5.0%, respectively. In order to acquire the additional paying interests, GNPC must notify the contractor of its intention to do so within sixty to ninety days of the contractor's notice to Ghana's Ministry of Energy of a commercial discovery. These interest percentages do not give effect to the exercise of such options.

(2)
The Republic of Cameroon will back-in for a 60.0% revenue interest and a 50.0% carried paying interest in a commercial discovery on the Kombe-N'sepe Block, with Kosmos then holding a 35.0% interest in the remaining interests of the block partners. This would result in Kosmos holding a 14.0% net revenue interest and a 17.5% paying interest. The Republic of Cameroon has an option to acquire an interest of up to 15.0% in a commercial discovery on the Ndian River Block. These interest percentages do not give effect to the exercise of such options.

(3)
We have not yet made a decision as to whether or not to drill our Morocco prospects. We have entered a memorandum of understanding with ONHYM to enter a new license covering the highest potential areas of

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this block under essentially the same terms as the original license. If we decide to continue into the drilling phase of such license, we anticipate that the first well to drill within the Boujdour Offshore Block will be post 2012.(4)
See "Risk Factors—Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurence or timing of their drilling" and "Risk Factors—Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects."

(5)
The Banda-1 exploration well was spud in mid 2011 and is currently drilling both the Banda Campanian and Banda Cenomanian prospects.

(6)
The N'gata-1 exploration well was spud in early 2011 and is currently being drilled.

Ghana

        The WCTP and DT Blocks are located within the Tano Basin, offshore western Ghana. This basin contains a proven world-class petroleum system as evidenced by the Jubilee, Mahogany East, Odum, Tweneboa, Enyenra, Teak and Tweneboa Deep discoveries.

        The Tano Basin represents the eastern extension of the Deep Ivorian Basin which resulted from rock deformation caused by tensional forces in the Albian age associated with opening of the Atlantic Ocean between the St. Paul and Romanche transform faults, as South America separated from Africa in the mid-Cretaceous period. The Tano Basin forms part of the resulting transform margin which extends from Sierra Leone to Nigeria.

        The basin is a depositional environment that was created by a thick Upper Cretaceous, deepwater turbidite sequence which, in combination with a modest Tertiary section, provided sufficient thickness to mature an early to mid-Cretaceous source rock in the central part of the Tano Basin. This well-defined reservoir and charge fairway forms the play which, when draped over the South Tano high (a structural high dipping into the basin) resulted in the formation of combination trapping geometries that constitute the Jubilee and Odum accumulations, and along which a number of other prospects are located.

        Some limited exploration took place in the shallow water part of the Tano Basin prior to Kosmos' licensing of the WCTP Block. A number of small, Albian-aged oil and natural gas discoveries were made in the 1980s. Following this, a small Late Cretaceous discovery was made in the 1990s. These older discoveries illustrated the presence of viable source rock, reservoir and seal sections with the limiting factor to commerciality being structural trap size. The combination of this information with regional 2D seismic data indicated the potential presence of a much larger play in the under-explored deepwater portion of the basin. Kosmos entered into the WCTP Petroleum Agreement in 2004. Kosmos recognized the potential for large, Late Cretaceous sandstone plays in stratigraphic trapping geometries and leveraged its technical expertise to evaluate and later prove the Tano Basin to be one of the most prolific hydrocarbon provinces in West Africa.

        Kosmos uses leading edge geophysical information to define these hydrocarbon plays and related prospects. This involves reprocessing existing 2D and 3D seismic data, as well as acquiring and leveraging high resolution 3D seismic data interpretation methodologies. This 3D seismic data allows development of detailed depositional, structural, and geophysical models, which led to the identification of a number of prospects including (1) combination structural-stratigraphic traps with updip and lateral thinning of reservoir sands, (2) combination fault and three-way fault closures, and (3) four-way dip closures or anticlinal traps.

        The primary prospect types consist of well imaged Turonian and Campanian aged submarine fans situated along the steeply dipping shelf margin and trapped in an up dip direction by thinning of the

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reservoir and/or faults. The WCTP Block partners tested this play concept in June 2007 with the Mahogany-1 well, which discovered over 295 feet (90 meters) of high quality oil pay in a large structural-stratigraphic trap. All subsequent discoveries made have similar trap geometries. In addition, four-way and closures and three-way fault traps are also present within the WCTP Block. These discoveries and prospects are described in more detail below.

Our Ghanaian Discoveries

        The following is a brief discussion of our discoveries to date on our two blocks offshore Ghana. See "Risk Factors—We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects."

Jubilee Discovery

        The Jubilee Field was discovered in 2007 with the drilling of the Kosmos-operated exploration well, Mahogany-1, within the WCTP Block. Tullow subsequently drilled an appraisal well, Hyedua-1, in the offsetting DT Block. The two wells defined a continuous, large accumulation of oil underlying areas within both blocks. The field, subsequently renamed Jubilee, is located approximately 37 miles (60 kilometers) offshore Ghana in water depths of 3,250 to 5,800 feet (991 to 1,707 meters). Pursuant to the terms of the UUOA, an area that covers a portion of each block has been unitized for purposes of joint development by the DT and WCTP participating interest holders. The parties to the UUOA initially agreed that the unit interests are to be shared equally, with each block deemed to contribute a 50% interest to the Jubilee Unit. Such 50% interest contribution in the Jubilee Unit is subject to subsequent redetermination under the UUOA. See "Risk factors—The unit partners' respective interests in the Jubilee Unit are subject to redetermination and our interests in such unit may decrease as a result" and "—Material Agreements—Jubilee Field Utilization." The UUOA specifies a split operatorship role. Kosmos was selected as the Technical Operator for Development and Tullow was designated as the Unit Operator.

        In its role as Technical Operator for Development, Kosmos led a multi-disciplined team, the Integrated Project Team ("IPT"), which was responsible for all aspects of the Jubilee Phase 1 PoD, including reservoir model, reserves and drainage plan, and production facilities including sub-sea architecture and the FPSO.

        In addition, the IPT was then responsible for project execution of the production facilities, excluding drilling and completing wells, which was the responsibility of the Unit Operator. The IPT successfully delivered first oil on November 28, 2010.

Geology

        The Jubilee Field is a combination stratigraphic-structural trap with reservoir intervals consisting of a series of stacked Upper Cretaceous Turonian-aged, gravity-driven, deepwater turbidite fan lobes and channel deposits. The wells within the Jubilee Unit have intersected five major turbidite fan lobe sequences containing oil and associated gas. The oil column contained within the reservoirs is over 1,640 feet (500 meters). The 16 wells and three sidetracks drilled to date have encountered high-quality sandstone reservoirs with average porosities of approximately 18% and permeabilities of 300 mD. Fluid samples recovered from multiple wells indicate an oil gravity of between 31.2 and 38.6 degrees API.

        Recognizing the significance of the discovery, the block partners acquired a high resolution 3D seismic survey over the field area in late 2007. The survey has proved invaluable in defining the distribution and architecture of the Upper and Lower Mahogany reservoirs.

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Subsurface Engineering

        The initial phase of the development focuses on two of the six reservoirs in the Jubilee Field, the prolific UM3 and LM2 reservoirs. Kosmos constructed over 500 detailed geologic models utilizing the subsurface mapping and a range of petrophysical attributes from the exploration, appraisal, and development wells. Numerical simulation was used to evaluate and screen hundreds of potential development well plans and operational strategies. Based on these results, the Kosmos-led IPT developed an initial 17 well drainage plan, which consists of nine producing wells six water injection wells and two natural gas injection wells. We expect we will produce approximately 120,000 bopd from these two reservoirs. To validate the subsurface engineering and provide additional confidence in the start-up of the development, a series of interference tests were conducted within the LM2 reservoir. These interference tests significantly reduced uncertainty associated with inter-well communication on a production timescale for the LM2 reservoir, a key uncertainty in the performance of any deepwater field.

Facilities and wells

        While the Jubilee Phase 1 Development focuses on only two of the five reservoirs identified in the area, there is a significant amount of upside related to the Jubilee Field. Accordingly, the subsea architecture was designed to provide additional well slot capacity as additional wells are tied into the system, and add a measure of redundancy for our production operations. As such, the subsea facilities are divided into an "East" and "West" side with a total of up to 32 well slots, only 17 of which have been drilled in the Jubilee Field Phase 1 development. The current plan for subsequent phases is to increase and extend the production plateau by adding additional wells into the existing subsea system. Subsequent phases of the development of the Jubilee Field will consist of drilling infill wells that target the currently producing UM3 and LM2 reservoirs. Production and reservoir performance is being monitored closely at present and planning is ongoing to initiate infill drilling in late 2011 or early 2012. The timing and scope of subsequent phases will be defined based on reservoir performance.

        The location of the field (in water depths ranging from 4,100 to 5,500 feet (1,250 to 1,700 meters)) led to the decision to use a FPSO as the production facility for the development. The FPSO was built by modifying a Very Large Crude Carrier ("VLCC") with the necessary modifications. The rechristened "Kwame Nkrumah" FPSO is capable of processing 120,000 bopd of oil, 160,000 Mcf per day ("Mcfpd") of natural gas, and storing up to 1.6 million bbl of stabilized crude. Further, the vessel can provide reservoir pressure maintenance through water and natural gas injection support of 232,000 bwpd and 160,000 Mcfpd respectively. Thus far, 16 of the 17 development wells have been drilled, all utilizing large bore 9 5 / 8  inch production casing with frac-packs to mitigate sand production and maintain high oil production and water and natural gas injection rates. These wells are clustered around subsea manifolds and utilize directional technology to target specific locations within the reservoirs.

Mahogany East Discovery

        Mahogany East is located in the WCTP Block approximately 37 miles (60 kilometers) offshore Ghana in water depths of 4,101 to 5,905 feet (1,250 to 1,800 meters). The field is covered by a high resolution 3D seismic survey and is a combination stratigraphic-structural trap with reservoir intervals contained in a series of stacked Upper Cretaceous Turonian-aged, deepwater turbidite fan lobe and channel deposits. The Mahogany-3, Mahogany-4, Mahogany-5 and Mahogany Deep-2 wells have intersected multiple oil bearing reservoirs in a Turonian turbidite sequence. Fluid samples recovered from the wells indicate an oil gravity of between 31 and 37 degrees API.

        Mahogany East was declared commercial on September 6, 2010 and a PoD is currently being prepared for submission to Ghana's Ministry of Energy in the first half of 2011.

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Odum Discovery

        Odum is located in the eastern portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of 2,624 to 3,281 feet (800 to 1,000 meters). The field is delineated by two well penetrations and defined by a high resolution 3D seismic data survey as a combination structural-stratigraphic trap. The Odum-1 and Odum-2 wells each intersected more than 65 feet (20 meters) of net sand. The interval is comprised of Upper Cretaceous, Campanian aged stacked turbidite sequences. Geochemical analyses of the downhole fluid samples indicate the crude has undergone biodegradation and has a heavier gravity relative to other discoveries in the area. Fluid samples recovered from the wells indicate an oil gravity of approximately 17.5 degrees API.

        Due to the technical challenges presented by the gravity of the oil encountered to date, development planning is ongoing under the WCTP Petroleum Agreement which, in certain circumstances, allows additional time for development studies. Provided the technical solutions can be properly engineered, as has been the case in other similar deepwater heavy oil developments like Petrobras' Jubarte and Shell's Parque das Conchas, a declaration of commerciality may be submitted for the Odum discovery by July 2011 with a PoD submittal within the subsequent six months.

Teak Discovery

        Teak is located in the western portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 650 to 3,600 feet (200 to 1,100 meters). The field is covered by a 3D seismic survey and is a structural-stratigraphic trap with an element of four-way closure. Seismic data indicates the existence of multiple stacked reservoirs ranging in age from Turonian to Campanian. Teak is located updip and northeast of the Jubilee Field and is located within the same reservoir fairway penetrated by the Jubilee wells. The Teak-1 exploratory well penetrated net pay thickness of approximately 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. Oil samples recovered from the Teak-1 well indicate oil of approximately 40 degrees API gravity in Campanian reservoirs and 32 degrees API gravity in Turonian reservoirs. A follow-up appraisal well, Teak-2, was drilled in March 2011. This well penetrated net oil, gas 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 meters) of undetermined hydrocarbon pay.

        Following additional appraisal, drilling and evaluation, a decision regarding the commerciality of the Teak discovery is expected to be made by the block partners in the first quarter of 2013. Should the discovery be declared commercial, a PoD would be prepared for submission to Ghana's Ministry of Energy within six months.

Tweneboa Discovery

        Tweneboa is located in the central portion of the DT Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of 3,281 to 5,252 feet (1,000 to 1,500 meters). The field is a stratigraphic trap with reservoir intervals contained within a series of stacked Upper Cretaceous Turonian-aged, deepwater turbidite fan lobes and channel deposits. The Tweneboa-1, Tweneboa-2, Tweneboa-3 and Tweneboa-4 wells have intersected multiple natural gas, condensate and oil bearing reservoirs in this Turonian turbidite sequence. Oil samples recovered from the Tweneboa-2 well indicate an oil gravity of approximately 31 degrees API, and condensate gravities between 41 and 47 degrees API. The natural gas is considered a "heavy" or "liquids rich" natural

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gas with condensate ratios ranging between 50 bbl/Mmcf to 100 bbl/Mmcf. We believe Tweneboa is a predominately liquid-rich gas condensate discovery.

        Following additional appraisal, drilling and evaluation, a decision regarding the commerciality of the Tweneboa discovery is expected to be made by the block partners in 2012. Following such a declaration, a PoD would be prepared for submission to Ghana's Ministry of Energy within six months.

Enyenra Discovery (formerly known as Owo)

        Enyenra is located in the Western portion of the DT Block approximately 28 miles (45 kilometers) offshore Ghana in water depths of approximately 3,300 to 5,000 feet (1,000 to 1500 meters). The field is primarily a stratigraphic trap with reservoir intervals contained within a series of stacked Upper Cretaceous Turonian-aged, deepwater turbidite fan lobe and channel deposits. The Owo-1, Owo-1 ST1 and Enyenra-2A wells have intersected multiple oil and natural gas bearing reservoirs in this Turonian turbidite sequence. Fluid samples recovered from the wells indicate an approximate oil gravity of approximately 32 degrees API, and natural gas condensate gravities between 42 and 48 degrees API. Lab measurements are underway to determine the gas condensate gravity and yield. We believe Enyenra is predominately an oil accumulation.

        Following additional appraisal, drilling and evaluation, a decision regarding the commerciality of the Enyenra discovery is expected to be made by the block partners in late 2012. Should the discovery be declared commercial, a PoD would be prepared for submission to Ghana's Ministry of Energy in mid-2013.

Tweneboa Deep Discovery

        Tweneboa Deep is located in the southern portion of the DT Block approximately 44 miles (70 kilometers) offshore Ghana in water depths of approximately 4,900 to 5,900 feet (1,500 to 1,800 meters). It comprises a north-south trending Upper Cretaceous Lower Turonian aged turbidite system with an updip thinning and is similar in age to the deeper reservoirs encountered in Mahogany East. The Enyenra-2A well tested a deeper Turonian fan where 16 feet (5 meters) of gas-condensate bearing sandstones were intersected. These results confirmed the existence of hydrocarbons in Tweneboa Deep. In place measurements of the condensate to gas ratio of approximately 100 bbl/Mmcf captured during logging indicate that "heavy" or "liquids rich" natural gas was encountered. The natural gas is considered "heavy" or "liquids rich" with condensate ratios ranging between 50 bbl/Mmcf to 100 bbl/Mmcf. We believe Tweneboa Deep is a predominately liquid-rich gas condensate discovery.

        Following additional appraisal, drilling and evaluation, a decision regarding the commerciality of the Tweneboa Deep discovery is expected to be made by the block partners in 2013. Should the discovery be declared commercial, a PoD would be prepared for submission to Ghana's Ministry of Energy in late 2013 or early 2014.

Our Ghanaian Prospects

        The following is a brief discussion of our prospects on our two blocks offshore Ghana.

Banda Campanian

        Banda Campanian is located in the eastern portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 2,600 to 4,000 feet (800 to 1,200 meters). It is approximately 3.7 miles (6 kilometers) east of the Odum discovery and characterized by a high resolution 3D seismic data survey as a combination structural-stratigraphic trap where a Campanian channel system is defined by a series of listric faults and encased in

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marine shale. Banda Campanian has similar geologic characteristics to the Odum discovery as detected through amplitude versus offset ("AVO") analysis, however it has been buried more deeply than Odum and this may result in improved fluid characteristics. The target interval is comprised of Upper Cretaceous Campanian aged stacked turbidite sequences interlayered with marine shale. The first well to drill Banda Campanian, Banda-1, was spud on March 31, 2011. This well will also test our Banda Cenomanian prospect, a portion of which lies beneath our Banda Campanian prospect.

Banda Cenomanian

        Banda Cenomanian is located in the southeastern portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 3,000 to 4,600 feet (900 to 1,300 meters). Based on high resolution 3D seismic data, the target reservoir is draped over the flank of a four-way closure thought to consist of channel and fan reservoirs within the Upper Cretaceous Cenomanian aged interval. The first well to drill Banda Cenomanian, Banda-1, was spud on March 31, 2011. This well will also test our Banda Campanian prospect, a portion of which lies above our Banda Cenomanian prospect.

Makore

        Makore is located in the south and central portion of the WCTP Block approximately 44 miles (70 kilometers) offshore Ghana in water depths of approximately 3,900 to 4,900 feet (1,200 to 1,500 meters). It targets Upper Cretaceous Turonian aged reservoirs expected to be similar in age and facies to those encountered in Jubilee. The first well to drill Makore is anticipated to be spud in 2011.

Odum East

        Odum East is located in the eastern portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 2,600 to 3,300 feet (800 to 1,000 meters). It is located 1.9 miles (3 kilometers) east of the Odum-1 and Odum-2 well penetrations and defined by a high resolution 3D seismic data survey as a combination structural-stratigraphic trap, and is very similar to the Odum discovery. The target interval is comprised of Upper Cretaceous Campanian aged stacked turbidite sequences. The first well to drill Odum East is anticipated to be spud in 2012.

Sapele

        Sapele is located in the northern portion of the WCTP Block approximately 22 miles (35 kilometers) offshore Ghana in water depths of approximately 300 to 2,600 feet (100 to 800 meters). It targets an Upper Cretaceous Middle Campanian age system of amalgamated channels forming an extensive depositional system with associated facies confining the width of the stratigraphic trap to approximately 6.2 miles (10 kilometers) wide. High resolution 3D seismic information indicates the presence of submarine fan channels. The first well to drill Sapele is anticipated to be spud in 2012.

Funtum

        Funtum is located in the northern portion of the WCTP Block approximately 22 miles (35 kilometers) offshore Ghana in water depths of approximately 300 to 1,600 feet (100 to 500 meters). It targets an Upper Cretaceous Middle Campanian age confined channel system approximately 1.3 miles (2 kilometers) wide with associated channel margin facies extending the stratigraphic trap to approximately 3.1 miles (5 kilometers) wide. High resolution 3D seismic

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information indicates the presence of a prospective submarine fan. The first well to drill Funtum is anticipated to be spud in 2012.

Assin

        Assin is located in the central portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 2,600 to 3,300 feet (800 to 1,000 meters). It is approximately 2.5 miles (4 kilometers) northwest and updip of the Odum discovery. The stratigraphic trap is defined by a high resolution 3D seismic survey and is very similar in nature to the Odum discovery. The target interval is comprised of Upper Cretaceous, Campanian aged stacked turbidite sequences interlayered with marine shale. The first well to drill Assin is anticipated to be spud in 2012.

Okoro

        Okoro is a tilted Albian fault block located in the central portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 2,600 to 3,000 feet (800 to 900 meters). It sits adjacent to the Jubilee field but in older and deeper stratigraphy. Oil samples from deeper wells within Tano Basin have also recovered oil samples from Albian formations. The first well to drill Okoro is anticipated to be spud post 2012.

Late Cretaceous WCTP Play

        Four additional Late Cretaceous targets are present on the WCTP Block offshore Ghana in water depths from 600 to 4,300 feet (190 to 1,300 meters). These targets range in age from Cenomanian to Companian. They comprise four-way closures to stratiographic channel traps. If a target matures into a prospect, the first well to drill one of these targets is anticipated to be spud post 2012.

Walnut

        Walnut is located along the northern edge of the DT Block approximately 28 miles (45 kilometers) offshore Ghana in water depths of approximately 1,600 to 2,600 feet (500 to 800 meters). It targets stratigraphic and downthrown fault closures varying in age from Turonian to Campanian. The first well to drill Walnut is anticipated to be spud in 2012.

DT Sapele

        DT Sapele is located in the eastern portion of the DT Block approximately 37 miles (60 kilometers) offshore Ghana in water depths of approximately 5,250 to 5,900 feet (1,600 to 1,800 meters). The target reservoir is a down-dip extension of the Upper Cretaceous Turonian age sand fairway at Jubilee. The combination structural stratigraphic reservoir is well defined with high resolution 3D seismic and well information from the surrounding Jubilee and Mahogany East discoveries. The first well to drill Odum East is expected to be spud in 2012.

Wassa

        Wassa is located in the south central portion of the DT Block approximately 44 miles (70 kilometers) offshore Ghana in water depths of approximately 5,900 to 6,200 feet (1,800 to 1,900 meters). It has a trapping geometry at multiple levels from Albian through Turonian with a stratigraphic trap element and a large three-way fault trap at the Albian level. The first well to drill Wassa is anticipated to be spud post 2012.

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Adinkra

        Adinkra is located along the northern edge of the DT Block approximately 28 miles (45 kilometers) offshore Ghana in water depths of approximately 1,600 to 2,600 feet (500 to 800 meters). It targets stratigraphic and downthrown fault closures varying in age from Turonian to Campanian. The first well to drill Adinkra is anticipated to be spud in 2012.

Oyoko

        Oyoko is located along the northern edge of the DT Block approximately 28 miles (45 kilometers) offshore Ghana in water depths of approximately 1,600 to 2,600 feet (500 to 800 meters). It targets stratigraphic and downthrown fault closures of Albian to Cenomanian age. The first well to drill Oyoko is anticipated to be spud in 2012.

Ananta

        Ananta is located in the western portion of the DT Block approximately 37 miles (60 kilometers) offshore Ghana in water depths of approximately 4,300 to 5,250 feet (1,300 to 1,600 meters). It is a stratigraphic trap of Campanian age located west of the existing Tweneboa wells. The Tweneboa-1 well encountered thick porous sands at this interval. Ananta contains similar facies as detected through AVO analysis. The first well to drill Ananta is anticipated to be spud post 2012.

Cameroon

Overview

        Kosmos has interests in two licenses in Cameroon, the Ndian River Block located in the Rio del Rey Basin, which it operates with a 100% equity interest, and the Perenco operated, Kombe-N'sepe Block located in the Douala Basin, in which Kosmos maintains a 35% interest. These licenses together comprise an area covering approximately 1.2 million acres (4,800 square kilometers), which is the equivalent of 205 standard deepwater U.S. Gulf of Mexico blocks.

        Licenses over the Kombe-N'sepe and Ndian River Blocks were obtained in 2005 and 2006, respectively, given Kosmos' view that, like other areas along the West African Transform Margin, the Cameroon coastal regions bordering the Gulf of Guinea have been both overlooked and under-explored, to date, from an oil exploration perspective. We believe that both the geology and exploration opportunities within our Cameroon licenses share substantial similarities to that of our offshore Ghana assets. In addition, given our management and technical teams' extensive exploration experience and success offshore nearby Equatorial Guinea, we believe we have a good understanding of the regional petroleum geology.

        To date, Kosmos has acquired gravity, magnetic and 2D seismic data over selected portions of our Cameroon licenses. In June 2010, we spud the Mombe-1 well on our Kombe-N'sepe Block which discovered hydrocarbons in sub-commercial quantities which was subsequently plugged and abandoned. Data from these activities has provided greater insight into the region's specific geology and petrophysical properties, including enhanced definition of multiple Tertiary (Miocene) and Late Cretaceous age prospects. In early 2011 we spud the N'gata-1 exploratory well which is currently being drilled.

        We have identified 10 prospects within our Cameroon licenses. These prospects are more fully described below.

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Geology

        Cameroon sits in the Gulf of Guinea adjacent to and south of the Niger Delta. The coastal and offshore portions of Cameroon are associated with two major but different geological basins. In the north and adjacent to the Niger delta is the Rio del Rey Basin which is a thick Tertiary aged depocenter. In addition to the oil province, there is a large outboard natural gas condensate province containing the Alba field. This province is separated from the southern Douala Basin by the Cameroon Tertiary volcanic line.

        The Douala Basin contains a thick Late Cretaceous sedimentary sequence which is overlain by a Tertiary sequence. This basin extends south into the neighboring country of Equatorial Guinea where hydrocarbons are produced from the Late Cretaceous Ceiba and Northern Block G hydrocarbon developments. This basin is associated with major transform faults resulting from the opening of the Atlantic Ocean as South America separated from Africa in the mid-Cretaceous period. This under-explored area has similar depositional trends and play elements as those basins in Ghana and Equatorial Guinea where the discovered fields are prolific in size.

        Kosmos' licenses in Cameroon consist of one license in the Rio del Rey Basin and one license in the Douala Basin. Each of these two geological provinces covered by the Kosmos license position constitute extensions of proven hydrocarbon plays. In the northern Rio del Rey Basin, Kosmos is operator and 100% equity holder in the Ndian River Block. This block is approximately 434,163 acres (1,757 square kilometers) in area and occupies the eastern, onshore and shallow water offshore portion of the prolific Rio del Rey Basin. Three prior wells have encountered sands and hydrocarbons within the licensed area and three recent exploration wells drilled in an adjacent license south of the Ndian River Block, have discovered oil in the last three years.

        In the Douala Basin, Kosmos has an interest in the license covering Kombe-N'sepe Block, which is operated by our block partner, Perenco, and is located in the onshore portion of this basin. The license is located approximately 150 miles (241 kilometers) from the Ceiba field offshore Equatorial Guinea and 4 miles (6 kilometers) from the Matanda natural gas condensate discoveries and 34 miles (55 kilometers) from the Alen/Aseng oil and gas fields. The Kombe-N'sepe Block contains a number of Late Cretaceous aged prospects consisting of four-way closures and three-way fault traps, the majority of which are enhanced by a stratigraphic trap component described in further detail below. The plays we are pursuing in these blocks are similar to those plays in which the Jubilee, Ceiba and Matanda accumulations have been made.

Our Cameroon Prospects

        The following is a brief discussion of our prospects on our two blocks onshore Cameroon.

N'gata

        N'gata is located in the onshore Kombe-N'sepe Block. This is a large structural three-way fault trap comprised of multiple stacked targets within Paleogene and Upper Cretaceous deepwater turbidite reservoir sequences. It is located north of the Kribi Field and southeast of the Matanda discoveries. An exploration well was spud in early 2011 and is currently being drilled.

N'donga

        N'donga, in the Kombe-N'sepe Block, is a large structural three-way fault trap comprised of multiple stacked reservoirs within Paleogene and Upper Cretaceous deepwater turbidite reservoir sequences. It is along trend and south of the North Matanda-1 and Matanda-2 wells. An exploration well is anticipated to be drilled post 2012.

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Disangue

        Disangue, in the Kombe-N'sepe Block, is a large structural three-way fault trap comprised of multiple stacked reservoirs within Paleogene and Upper Cretaceous deepwater turbidite reservoir sequences. It is east of the North Matanda-1 and Matanda-2 wells. An exploration well is anticipated to be drilled post 2012.

Pongo Songo

        Pongo Songo, in the Kombe-N'sepe Block, is a large structural three-way fault trap comprised of multiple stacked reservoirs within Paleogene and Upper Cretaceous deepwater turbidite reservoir sequences. It is along trend and south of the North Matanda-1 and Matanda-2 wells. An exploration well is anticipated to be drilled post 2012.

Bonongo

        Bonongo, in the Kombe-N'sepe Block, is a large structural three-way fault trap comprised of multiple stacked reservoirs within Paleogene and Upper Cretaceous deepwater turbidite reservoir sequences. It is along trend and south of the North Matanda-1 and Matanda-2 wells. An exploration well is anticipated to be drilled post 2012.

Coco East

        Coco East, in the Kombe-N'sepe Block, is a large structural three-way fault trap comprised of multiple stacked reservoirs within Paleogene and Upper Cretaceous deepwater turbidite reservoir sequences. It is along trend and south of the North Matanda-1 and Matanda-2 wells. An exploration well is anticipated to be drilled post 2012.

Liwenyi

        Liwenyi is located onshore, in the southern part of the Ndian River Block, within the Rio del Rey Basin. It is a large structurally trapped anticline associated with multiple stacked targets within the Miocene Isongo Formation. Liwenyi is located in the heart of the Isongo reservoir fairway which constitutes primary reservoir in the Alba and Esmeraldas fields in Equatorial Guinea and in Bowleven's recent IF and IE oil and natural gas condensate discoveries in the Etinde Block to the south. Liwenyi is also situated along trend from the Etinde Block discoveries and in a similar trap type. An exploration well is anticipated to be drilled late in 2012.

Liwenyi South

        Liwenyi South is located onshore, in the southern part of the Ndian River Block, within the Rio del Rey Basin. It is a structurally trapped anticline associated with multiple stacked targets within the Miocene Isongo Formation. Liwenyi South is located in the next thrust sheet south from Liwenyi. It is located in the heart of the Isongo reservoir fairway, which constitutes primary reservoir in the Alba and Esmeraldas Fields in Equatorial Guinea and in the recent IF and IE oil and natural gas condensate discoveries in the Etinde Block to the south. Liwenyi South is also situated along trend from the Etinde Block discoveries and in a similar trap type. An exploration well is anticipated to be drilled post 2012.

Meme

        Meme is located onshore, in the southern part of the Ndian River Block, within the Rio del Rey Basin. It is a faulted three-way closure trapped on the downthrown side of a three-way trapping fault and is comprised of several targets within the Miocene Isongo Formation. Meme is located along trend with the Alba and Esmeraldas Fields in Equatorial Guinea. An exploration well is scheduled to be drilled post 2012.

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Bamusso

        Bamusso is located onshore, in the southern part of the Ndian River Block, within the Rio del Rey Basin. It is a fault trap within the Upper Cretaceous section. An exploration well is anticipated to be drilled post 2012.

Morocco

        Kosmos is operator and has a 75% working interest in the Boujdour Offshore Block. This block is located within the Aaiun Basin, along the Atlantic passive margin. The block, as covered by the original Boujdour Offshore Petroleum Agreement, comprises an area of more than 10.87 million acres (44,000 square kilometers) (See "Risk Factors—Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects."), an area similar in scale to nearly the entire the deepwater fold belt of the U.S. Gulf of Mexico, or approximately 1,900 standard deepwater U.S. Gulf of Mexico blocks. Detailed seismic sequence analysis suggests the existence of stacked deepwater turbidite systems throughout the region. Given the immense scale of the license area, multiple distinct exploration fairways have been identified on this block by Kosmos, each having independent play risks, providing substantial exploration opportunities.

        We shot an approximately 2,056 square kilometer 3D seismic survey in 2009 over our high potential leads we identified based off of a database we possessed of approximately 25,000 line kilometers of vintage 2D seismic on the Boujdour Offshore Block. Combined, this detailed data imaging has enabled us to identify and high-grade our prospect inventory through trap identification, detailed structural analysis, and depositional history mapping. As a result, we have identified 19 attractive prospects trapped in very large four-way closures and three-way fault traps throughout the license area.

        An exploration well has been drilled in the shallow water between the Boujdour Offshore Block and the shoreline that demonstrates the presence of good-quality, Cretaceous-aged reservoir rocks. Recent onshore drilling by ONHYM has also recovered oil from Cretaceous horizons. These well results demonstrate the presence of a working petroleum system in the adjacent areas, which corroborates Kosmos' geologic models. The deepwater offshore Morocco has not yet proved to be an economically viable production area as to date there has not been a commercially successful discovery or production in this region. See "Industry—Morocco—Oil and Gas Industry."

        Kosmos believes that the geology offshore Morocco, like that of Ghana, constitutes an overlooked Cretaceous deepwater sandstone play. Given the size of the block and well-defined structural and stratigraphic traps identified to date, Kosmos' exploration opportunity presented in Morocco is substantial. As a result of the seismically supported geologic fundamentals of the basin, the number of play concepts and fairways within the block and the overall size of the block, we believe that a number of wells may likely be required to test the prospectivity of this license area. We have not yet made a decision as to whether or not to drill our Moroccan prospects. We have entered a memorandum of understanding with ONHYM to enter a new license covering the highest potential areas of this block under essentially the same terms as the original license. If we decide to continue into the drilling phase of such license we anticipate that the first well to drill within the Boujdour Offshore Block will be post 2012.

Lower Cretaceous Play Concept

        The main play elements of the prospectivity within the Boujdour Offshore Block consist of a Late Jurassic source rock, charging Early to Mid Cretaceous deepwater sandstones trapped in a number of different structural trends. In the inboard area a number of three-way fault closures are present which

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contain Early to Mid Cretaceous sandstone sequences some of which have been penetrated in wells on the continental shelf. Outboard of these fault trap trends, large four-way closure and combination structural stratigraphic traps are present in discrete northeast to southwest trending structurally defined fairways.

Our Moroccan Prospects

        The following is a brief discussion of our prospects on the Boujdour Offshore Block.

Gargaa

        Gargaa is located offshore in the southern part of the Boujdour Offshore Block, within the Aaiun Basin, in water depths of approximately 5,250 to 6,500 feet (1,600 to 2,000 meters). It is one of four large four-way closures which sit on a 328 mile (100 kilometer) long anticline containing multiple stacked targets within the Early Cretaceous Valanginian through Hauterivian sections. 3D seismic data has been used to define its depositional and structural history. An exploration well is anticipated to be drilled post 2012.

Argane

        Argane is located offshore, in the southern part of the Boujdour Offshore Block, within the Aaiun Basin, in water depths of approximately 4,600 to 6,000 feet (1,400 meters to 1,800 meters). It is one of four large four-way closures which sit on a 328 mile (528 kilometers) long anticline containing multiple stacked targets within the Early Cretaceous Valanginian through Hauterivian sections. 3D seismic data has been used to define its depositional and structural history. An exploration well is anticipated to be drilled post 2012.

Safsaf

        Safsaf is located offshore, in the southern part of the Boujdour Offshore Block, within the Aaiun Basin, in water depths of approximately 8,200 to 9,500 feet (2,500 to 2,900 meters). It is a large four-way closure with a stratigraphic trapping element located over a anticline and containing multiple stacked targets within the Early Cretaceous Valanginian through Hauterivian sections. 3D seismic data has been used to define its depositional and structural history. An exploration well is anticipated to be drilled post 2012.

Aarar

        Aarar is located offshore, in the southern part of the Boujdour Offshore Block, within the Aaiun Basin, in water depths of approximately 6,500 to 8,500 feet (2,000 to 2,600 meters). It is one of four, large, four-way closures which sit on a 328 mile (100 kilometer) long compressional anticline containing multiple stacked targets within the Early Cretaceous Valanginian through Hauterivian sections. 2D seismic data has been used to define its depositional and structural history. An exploration well is anticipated to be drilled post 2012.

Zitoune

        Zitoune is located offshore, in the southern part of the Boujdour Offshore Block, within the Aaiun Basin, in water depths of approximately 6,250 to 7,500 feet (1,900 to 2,300 meters). It is one of four, large, four-way closures which sit on a 328 mile (100 kilometer) long anticline containing multiple stacked targets within the Early Cretaceous Valanginian through Hauterivian sections. 2D seismic data has been used to define its depositional and structural history. An exploration well is anticipated to be drilled post 2012.

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Al Arz

        Al Arz is located offshore, in the southern part of the Boujdour Offshore Block, within the Aaiun Basin, in water depths of approximately 1,300 to 2,000 feet (400 to 600 meters). It is a large, three-way fault closure on the upthrown side of a three-way trapping fault containing multiple stacked targets within the Early Cretaceous Hauterivian through Albian sections. 2D seismic data has been used to define its depositional and structural history. An exploration well is anticipated to be drilled post 2012.

Felline

        Felline is located offshore, in the southern part of the Boujdour Offshore Block, within the Aaiun Basin, in water depths of approximately 7,200 to 7,900 feet (2,200 to 2,400 meters). It is a large, four-way closure containing multiple stacked targets within the Early Cretaceous through Albian sections. 2D seismic data has been used to define its depositional and structural history. An exploration well is anticipated to be drilled post 2012.

Nakhil

        Nakhil is located offshore, in the southern part of the Boujdour Offshore Block, within the Aaiun Basin, in water depths of approximately 3,600 to 4,250 feet (1,100 to 1,300 meters). It is a large, four-way closure containing multiple stacked targets within the Early Cretaceous through Albian sections. 2D seismic data has been used to define its depositional and structural history. An exploration well is anticipated to be drilled post 2012.

Barremian Tilted Fault Block Play

        An additional eleven prospects have been defined on our existing 2D and 3D seismic database; these consist of a variety of three-way fault closures with targets in the Early Cretaceous age. Exploration wells are anticipated to be drilled post 2012.

Our Reserves

        The following table sets forth summary information about our oil and natural gas reserves as of December 31, 2009 and December 31, 2010. As of December 31, 2009, all of our proved reserves were classified as proved undeveloped. Given the commencement of production from the Jubilee Field on November 28, 2010, a significant portion of our proved undeveloped reserves were reclassified as proved developed as of December 31, 2010. We did not have any proved reserves prior to the fiscal year ended December 31, 2009.
Summary of Oil and Gas Reserves

 
	 	Net Proved Reserves	 	
 
	 	December 31, 2009	 	December 31, 2010	 	
Reserves Category	 	Natural Gas	 	Oil,
Condensate,
NGLs	 	Total	 	Natural Gas(1)	 	Oil,
Condensate,
NGLs	 	Total	 	
 
	 	(Bcf)
	 	(Mmbbl)
	 	(Mmboe)
	 	(Bcf)
	 	(Mmbbl)
	 	(Mmboe)
	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Jubilee Field Phase 1	 	 	—	 	 	52	 	 	52	 	 	22	 	 	52	 	 	56	 	

(1)
These reserves represent only the quantities of fuel gas required to operate the FPSO during normal field operations. No natural gas volumes, outside of the fuel gas reported, have been classified as reserves. If and when a gas sales agreement is executed, a portion of the remaining gas may be reclassified as reserves. See "Risk Factors—We may not be able to commercialize our interests in any natural gas produced from our license areas in West Africa."

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        The following table sets forth the estimated future net revenues, excluding derivatives contracts, from net proved reserves and the expected benchmark prices used in projecting net revenues at December 31, 2010.

	 	Projected Net
Revenues
(in Millions
except $/bbl)	 	
Future net revenues	 	$	2,041	 	
Present value of future net revenues:	 	 	 	 	
 	PV-10(1)	 	 	1,530	 	
 	Future income tax expense (levied at a corporate parent and intermediate subsidiary level)	 	 	—	 	
 	Discount of future income tax expense (levied at a corporate parent and intermediate subsidiary level) at 10% per annum	 	 	—	 	
 	 	 	 	
 	Standardized Measure(2)	 	 	1,530	 	
Benchmark and differential oil price($/bbl)(3)	 	$	79.70	 	

(1)
PV-10 represents the present value of estimated future revenues to be generated from the production of proved oil and natural gas reserves, net of future development and production costs, royalties, additional oil entitlements and future tax expense levied at an asset level (in our case, future Ghanaian tax expense levied under the WCTP and DT Petroleum Agreements), using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10% to reflect the timing of future cash flows. PV-10 is a non-GAAP financial measure and often differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of future income tax expense related to proved oil and gas reserves levied at a corporate parent or intermediate subsidiary level on future net revenues. However, it does include the effects of future tax expense levied at an asset level (in our case, it does include the effects of future Ghanaian tax expense levied under the WCTP and DT Petroleum Agreements). Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas assets. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific corporate tax characteristics of such entities.

(2)
Standardized Measure represents the present value of estimated future cash inflows to be generated from the production of proved oil and natural gas reserves, net of future development and production costs, future income tax expense related to our proved oil and gas reserves levied at a corporate parent and intermediate subsidiary level, royalties, additional oil entitlements and future tax expense levied at an asset level (in our case, future Ghanaian tax expense levied under the WCTP and DT Petroleum Agreements), without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10% to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure often differs from PV-10 because Standardized Measure includes the effects of future income tax expense related to our proved oil and gas reserves levied at a corporate parent and intermediate subsidiary level on future net revenues. However, as we have been a tax exempted company incorporated pursuant to the laws of the

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Cayman Islands to date and will be a tax exempted company incorporated pursuant to the laws of Bermuda following the completion of the corporate reorganization to be completed in connection with this offering, and as the Company's intermediate subsidiaries positioned between it and the subsidiary that is a signatory to the WCTP and DT Petroleum Agreements will continue to be tax exempted companies, we have not been and do not expect to be subject to future income tax expense related to our proved oil and gas reserves levied at a corporate parent or intermediate subsidiary level on future net revenues. Therefore, the year-end 2010 estimate of PV-10 is equivalent to the Standardized Measure.(3)
The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months was $79.35/bbl for Dated Brent at December 31, 2010. The price was adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price expected to be received at the wellhead. Based on sales made to date and marketing surveys, the Jubilee oil is forecasted to ultimately sell for a $0.35/bbl premium relative to Dated Brent. The adjusted price utilized to derive the PV-10 is $79.70/bbl.

Estimated proved reserves

        Unless otherwise specifically identified in this prospectus, the summary data with respect to our estimated proved reserves presented above has been prepared by NSAI, our independent reserve engineering firm, in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities. The SEC has adopted new rules relating to disclosures of estimated reserves that are effective for fiscal years ending on or after December 31, 2009. These new rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month historical unweighted first-day-of-the-month average prices. For the twelve months ended December 31, 2010 and for future periods, our estimated proved reserves are determined using the preceding twelve months' unweighted arithmetic average of the first-day-of-the-month prices, rather than year-end prices. For a definition of proved reserves under the SEC rules, see the "Glossary of Selected Oil and Natural Gas Terms". For more information regarding our independent reserve engineers, please see "—Independent Petroleum Engineers" below.

        Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil, without giving effect to derivative transactions, and were held constant throughout the life of the assets.

        Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations at December 31, 2010 are based on costs in effect at December 31, 2010 and the 12-month unweighted arithmetic average of the first-day-of-the-month price for the fiscal year ending December 31, 2010, adjusted for anticipated market premium, without giving effect to derivative transactions, and are held constant throughout the life of the assets. There can be no assurance that the proved reserves will be produced within the periods indicated or that prices and costs will remain constant. See "Risk Factors—The present value of future net revenues from our proven reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves."

Independent petroleum engineers

        NSAI was established in 1961 and has offices in Dallas and Houston, Texas. Over the past 49 years, NSAI has provided services to the worldwide petroleum industry that include the issuance of reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration

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resources assessments, equity determinations, and management and advisory services. NSAI professionals subscribe to a code of professional conduct and NSAI is a Registered Engineering Firm in the State of Texas.

        Our estimated reserves at December 31, 2009 and December 31, 2010 and related future net revenues and PV-10 at December 31, 2010 are taken directly from reports prepared by NSAI, our independent reserve engineers, in accordance with petroleum engineering and evaluation principles which NSAI believes are commonly used in the industry and definitions and current regulations established by the SEC. These reports were prepared at our request to estimate our reserves and related future net revenues and PV-10 for the periods indicated therein. The December 31, 2010 report was completed on April 19, 2011 and the December 31, 2009 report was completed on February 4, 2010. Copies of these reports have been filed as exhibits to the registration statement containing this prospectus. NSAI's reserves report for December 31, 2009 and December 31, 2010 included a detailed review of the Jubilee Field, which contains 100% of our total proved reserves.

        In connection with the December 31, 2009 and December 31, 2010 reserves reports, NSAI prepared its own estimates of our proved reserves. In the process of the reserves evaluation, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. NSAI independently prepared reserves estimates to conform to the guidelines of the SEC, including the criteria of "reasonable certainty," as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(2) of Regulation S-X. NSAI issued a report on our proved reserves at December 31, 2009 and December 31, 2010, based upon its evaluation. NSAI's primary economic assumptions in estimates included an ability to sell oil at a price of $79.70/bbl, a certain level of capital expenditures necessary to complete the Jubilee Field Phase 1 development program and the exercise of GNPC's back-in right on the Jubilee Field Phase 1 development. The assumptions, data, methods and precedents were appropriate for the purpose served by these reports, and NSAI used all methods and procedures as it considered necessary under the circumstances to prepare the reports.

Technology used to establish proved reserves

        Under the new SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have proved effective by actual comparison of production from projects in the same reservoir interval, an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

        In order to establish reasonable certainty with respect to our estimated proved reserves, NSAI employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, acoustic logs, whole core analysis, sidewall core analysis,

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downhole pressure and temperature measurements, reservoir fluid samples, geochemical information, geologic maps, seismic data, well test and interference pressure and rate data. Reserves attributable to undeveloped locations were estimated using performance from analogous wells with similar geologic depositional environments, rock quality, and appraisal and development plans to assess the estimated ultimate recoverable reserves as a function of the original oil in place. These qualitative measures are benchmarked and validated against sound petroleum reservoir engineering principles and equations to estimate the ultimate recoverable reserves volume. These techniques include, but are not limited to, nodal analysis, material balance, and numerical flow simulation.

Internal controls over reserves estimation process

        We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Our Reservoir Engineering Managers are primarily responsible for overseeing the preparation of our reserves estimates. Our Reservoir Engineering Managers have over 40 combined years of industry experience between them with positions of increasing responsibility in engineering and evaluations. Each holds a Bachelor of Science degree in petroleum engineering. Eric Hass, our Director of Subsurface, is the primary technical person responsible for overseeing our reserve audits. Mr. Haas received a Bachelor of Science Degree in Petroleum Engineering with honors from The New Mexico Institute of Mining and Technology in 1984 and has worked in the industry for more than twenty-eight years in various engineering and management roles. His experience includes working in the following areas: Algeria, Azerbaijan, Danish North Sea, Egypt, Equatorial Guinea, Gabon, Ghana, Libya, Norway, Russia, the U.K. North Sea, onshore the United States and in the Gulf of Mexico (both on the continental shelf and in the deepwater). He spent more than 24 years of his career at a mid-sized NYSE listed E&P corporation. Prior to coming to Kosmos, Mr. Haas spent six years working as a Technical Manager in four different geographic regions. In those roles, he had direct responsibility for the review and approval of internal reserve and resource estimates, interfacing with the corporation's third party reserve auditor and participating on a management team to audit the corporation's reserves on an annual basis.

        Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review assets and discuss methods and assumptions used in preparation of the proved reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the reserve report is reviewed by our Senior Vice President, Exploration, Senior Vice President, Production and Operations, and senior technical staff with representatives of our independent reserve engineers and internal technical staff. Following the consummation of this offering, we anticipate that our Audit Committee will conduct a similar review on an annual basis.

Price history

        Oil and natural gas are commodities. The price that we will receive for the oil and natural gas we will produce will largely be a function of market supply and demand. While global demand for oil and natural gas has increased dramatically during this decade, world oil consumption in 2009 decreased to 84.1 million bopd from 85.2 million bopd in 2008 as a result of the global economic downturn that began in late 2007. However, demand for oil increased in 2010. Demand is impacted by general economic conditions, weather and other seasonal conditions. Oversupply or undersupply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position,

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results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.

        We commenced production on November 28, 2010. From this date through and including December 31, 2010, our net production volume held for sale was approximately 277,200 bbl. Our first volumes from the Jubilee Field were sold in early 2011.

License Areas

        The following table sets forth certain information regarding the developed and undeveloped portions of our license areas as of December 31, 2010 for the three countries in which we currently operate.

	 	Developed
Area (Acres)	 	Undeveloped Area (Acres)	 	Total Area (Acres)	 	
 
	 	Gross	 	Net(1)	 	Gross	 	Net(1)	 	Gross	 	Net(1)	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	West Cape Three Points	 	 	11,840	 	 	2,781	 	 	358,077	 	 	110,556	 	 	369,917	 	 	113,338	 	
 	Deepwater Tano(2)	 	 	15,226	 	 	3,577	 	 	258,567	 	 	46,542	 	 	273,793	 	 	50,119	 	
Cameroon	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Kombe-N'sepe	 	 	—	 	 	—	 	 	747,741	 	 	261,709	 	 	747,741	 	 	261,709	 	
 	Ndian River	 	 	—	 	 	—	 	 	434,163	 	 	434,163	 	 	434,163	 	 	434,163	 	
Morocco	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Boujdour Offshore Block(3)	 	 	—	 	 	—	 	 	10,869,672	 	 	8,152,254	 	 	10,869,672	 	 	8,152,254	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	27,066	 	 	6,358	 	 	12,668,220	 	 	9,005,225	 	 	12,695,286	 	 	9,011,583	 	

(1)
Net acreage based on Kosmos' working interest, before the exercise of any options or back-in rights. See "—Material Agreements—Exploration Agreements—Ghana" and "—Material Agreements—Exploration Agreements—Other." Our net acreage may be affected by any redetermination of interests in the Jubilee Unit. See "Risk Factors—The unit partners' respective interests in the Jubilee Unit are subject to redetermination and our interests in such unit may decrease as a result" and "—Material Agreements—Exploration Agreements—Ghana—Jubilee Field Unitization."

(2)
This acreage does not reflect the subsequent 25% relinquishment which occurred in January 2011 in connection with the extension of the DT Petroleum Agreement into the next phase.

(3)
This reflects the acreage covered by the original Boujdour Offshore Petroleum Agreement which expired on February 26, 2011. We have entered a memorandum of understanding with the ONHYM to enter a new petroleum agreement covering the highest potential areas of this block under essentially the same terms as the original license. See "Risk Factors—Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects."

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Drilling activity

        The results of oil and natural gas wells drilled and completed for each of the last three years were as follows:

	 	Exploratory and Appraisal Wells(1)	 	Development Wells(1)	 	 

 
	 	Productive	 	Dry	 	Total	 	Productive	 	Dry	 	Total	 	 

 
	 	 	 	 	 	 	 	 	 	 	 	 	 	Total
Net	 	Total
Gross	 	 	 	 	 	 	 	 	 	
 
	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	 	 	 	 	 	 	 	 	 	 	 	 	
Year Ended December 31, 2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	West Cape Three Points	 	 	1	 	 	0.31	 	 	1	 	 	0.31	 	 	2	 	 	0.62	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	0.62	 	 	2	 	 	 	 	 	 	 	 	 	
 	Deepwater Tano	 	 	3	 	 	0.54	 	 	1	 	 	0.18	 	 	4	 	 	0.72	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	0.72	 	 	4	 	 	 	 	 	 	 	 	 	
Cameroon	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Kombe-N'sepe(2)	 	 	1	 	 	0.35	 	 	—	 	 	—	 	 	1	 	 	0.35	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	0.35	 	 	1	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	5	 	 	1.20	 	 	2	 	 	0.49	 	 	7	 	 	1.69	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	1.69	 	 	7	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Year Ended December 31, 2009	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	West Cape Three Points	 	 	3	 	 	0.93	 	 	—	 	 	—	 	 	3	 	 	0.93	 	 	4	 	 	0.94	 	 	—	 	 	—	 	 	4	 	 	0.94	 	 	1.87	 	 	7	 	 	 	 	 	 	 	 	 	
 	Deepwater Tano	 	 	1	 	 	0.18	 	 	—	 	 	—	 	 	1	 	 	0.18	 	 	8	 	 	1.88	 	 	—	 	 	—	 	 	8	 	 	1.88	 	 	2.06	 	 	9	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	4	 	 	1.11	 	 	—	 	 	—	 	 	4	 	 	1.11	 	 	12	 	 	2.82	 	 	—	 	 	—	 	 	12	 	 	2.82	 	 	3.93	 	 	16	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Year Ended December 31, 2008	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	West Cape Three Points	 	 	3	 	 	0.85	 	 	—	 	 	—	 	 	3	 	 	0.85	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	0.85	 	 	3	 	 	 	 	 	 	 	 	 	
 	Deepwater Tano	 	 	1	 	 	0.24	 	 	—	 	 	—	 	 	1	 	 	0.24	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	0.24	 	 	1	 	 	 	 	 	 	 	 	 	
Nigeria(3)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	OPL 320	 	 	1	 	 	0.20	 	 	—	 	 	—	 	 	1	 	 	0.20	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	0.20	 	 	1	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	5	 	 	1.29	 	 	—	 	 	—	 	 	5	 	 	1.29	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	1.29	 	 	5	 	 	 	 	 	 	 	 	 	

(1)
The Jubilee Phase 1 PoD notionally specifies a total of seventeen wells. A total of twelve development wells have been drilled, with several completed and online. Four exploratory wells will be converted to development wells as the development program progresses. A final development well may be drilled and completed at a later date.

(2)
Although the Mombe-1 well successfully discovered gas, the quantities and phase were insufficient to commercialize the discovery. The well was plugged and abandoned.

(3)
Although the Echim-1 well successfully discovered oil, the quantities were insufficient to commercialize the discovery. Subsequently, the well was plugged and abandoned.

        The following table shows the number of wells that are in the process of being drilled or are in active completion stages, and the number of wells suspended or waiting on completion as of April 13, 2011:

	 	Wells in the Process
of Drilling or
in Active Completion	 	Wells Suspended or
Waiting on Completion	 	
 
	 	Exploration	 	Development	 	Exploration	 	Development	 	
 
	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	West Cape Three Points	 	 	1	 	 	0.31	 	 	1	 	 	0.23	 	 	8	 	 	2.47	 	 	4	 	 	0.94	 	
 	Deepwater Tano	 	 	1	 	 	0.18	 	 	—	 	 	—	 	 	5	 	 	0.9	 	 	2	 	 	0.47	 	
Cameroon	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Kombe-N'sepe	 	 	1	 	 	0.35	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
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Undeveloped license area expirations

        In Ghana, the current exploration phase over the undeveloped acreage of the WCTP Block expires on July 22, 2011. At that time, any acreage that is not within a discovery area, a development and production area or the area comprising the Jubilee Unit will be relinquished. In a letter dated July 6, 2010, Kosmos submitted a notice to GNPC under Article 4.10 of the WCTP Petroleum Agreement exercising its right as one of the WCTP Block partners to the granting of a new petroleum agreement covering such areas as would be relinquished upon expiry of the final exploration period on July 21, 2011. Kosmos and the other WCTP block partners have formally submitted a proposed new petroleum agreement for these areas in early 2011. The current exploration phase over the undeveloped acreage of the DT Block expired on January 19, 2011. In January 2011, Tullow, on behalf of the DT Block partners, formally extended the DT Petroleum Agreement into the second extension period and effectively relinquished 25% of the DT Block. Upon expiration of the final exploration period, the DT Block partners will have the ability to exercise their right to the granting of a new petroleum agreement covering such areas as would be relinquished, subject to the block partners submitting notice to GNPC one year prior to the expiration of that exploration period.

        Under the Ndian River Production Sharing Contract, the initial exploration phase to the Ndian River Block expired on November 20, 2010. On September 16, 2010, in compliance with the production sharing contract, we applied to Cameroon's Minister of Industry, Mines, and Technological Development for a two-year renewal of the exploration period (the first of two additional exploration periods of two years each). This application suspends the termination of the license until approval is obtained and upon submission of the application we were required to relinquish 30% of the original license area of the Ndian River Block. The Kombe-N'sepe License Agreements over the Kombe-N'sepe Block expires on June 30, 2011. The Kombe-N'sepe License Agreements provide for a subsequent two-year exploration period, but whether we enter such period will not be determined until after we analyze the results of our second exploration well on the Kombe-N'sepe Block spud in early 2011 and currently being drilled.

        Under the Boujdour Offshore Petroleum Agreement, the most recent exploration phase expired on February 26, 2011, however, we entered a memorandum of understanding with ONHYM to enter a new petroleum agreement covering the highest potential areas of this block under essentially the same terms as the original license.

Domestic Supply Requirements

        Each of the WCTP and the DT Petroleum Agreements, the Kombe-N'sepe License Agreements, the Ndian River Production Sharing Contract and the Boujdour Offshore Petroleum Agreement or, in some cases, the applicable law governing such agreements, grant a right to the respective host country to purchase certain amounts of oil produced pursuant to such agreements at international market prices for domestic consumption. In addition, in connection with the approval of the Jubilee Phase 1 PoD, we granted the first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to Ghana at no cost. See "Risk Factors—Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production."

Material Agreements

Exploration Agreements—Ghana

West Cape Three Points ("WCTP") Block

        Effective July 22, 2004, Kosmos Energy Ghana HC ("Kosmos Ghana"), a wholly owned subsidiary, the EO Group and GNPC entered into the WCTP Petroleum Agreement covering the WCTP Block

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offshore Ghana in the Tano Basin. Kosmos Ghana held an initial 86.5% working interest in the block. Pursuant to farm-out agreements for the WCTP Block dated September 1, 2006, Anadarko WCTP Company, Tullow Ghana Limited and Sabre Oil and Gas Limited farmed into the WCTP Block. As a result, Kosmos Ghana, Anadarko WCTP Company, Tullow Ghana Limited and Sabre Oil & Gas Holdings Limited's participating interests are 30.875%, 30.875%, 22.896% and 1.854%, respectively. Kosmos Ghana is the operator. The EO Group owns a 3.5% "carried" working interest and all of EO Group's share of costs to first production from the WCTP Block are 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, through future production proceeds. GNPC has a 10% participating interest and will be carried through the exploration and development phases. Under the WCTP Petroleum Agreement, GNPC exercised its option in December 2008 to acquire an additional paying interest of 2.5% in the Jubilee Field development (see "—Jubilee Field Unitization"). GNPC is obligated to pay its 2.5% share of all future petroleum costs as well as certain historical development and production costs attributable to its 2.5% additional paying interests in the Jubilee Unit. Furthermore, it is obligated to pay 10% of the production costs of the Jubilee Field development, as allocated to the WCTP Block. In August 2009, GNPC notified us and our unit partners it would exercise its right for the contractor group to pay its 2.5% WCTP block share of the Jubilee Field development costs and be reimbursed for such costs plus interest out of GNPC's production revenues under the terms of the WCTP Petroleum Agreement. Kosmos Ghana is required to pay a fixed royalty of 5% and a sliding-scale royalty ("additional oil entitlement") which escalates as the nominal project rate of return increases. These royalties are to be paid in-kind or, at the election of the government of Ghana, in cash. A corporate tax-rate of 35% is applied to profits at a country level.

        The WCTP Block as originally awarded comprised approximately 483,599 acres (1,957 square kilometers). Due to two contractual relinquishments at the commencement of contract periods, the WCTP Block currently comprises approximately 369,917 acres (1,497 square kilometers) in water depths ranging from 165 to 5,900 feet (approximately 50 to 1,800 meters). The term of the WCTP Petroleum Agreement is 30 years from the effective date of such agreement, being July 22, 2004. The initial exploration period of the block is three years, divided into two separate 18-month subperiods. In 2005, a 268,109 acre (1,085 square kilometers) 3D seismic survey was acquired, processed and interpreted by Kosmos Ghana. In 2006, Kosmos Ghana elected to proceed with the second subperiod with an exploration well commitment. The exploration well, Mahogany-1, was drilled and an oil discovery announced on June 18, 2007. The work and financial commitments were met for the initial exploration period. The next phase, the first extension period, commenced at the end of the initial exploration period and was for two years. The one exploration well commitment for this period was met by drilling the Odum-1 well, which tested a different prospect than the Mahogany-1 well. Odum-1 was announced as an oil discovery on February 25, 2008. In addition, the Mahogany-3 appraisal well was designed to test a deeper exploration objective and resulted in the Mahogany Deep discovery which was announced on January 8, 2009. In July 2009, Kosmos elected to enter the second and final two year extension period under the WCTP Petroleum Agreement. The commitment for this period was met by drilling of the Dahoma-1 well, which tested a different prospect from those tested by Mahogany-1 and Odum-1. All work and financial obligations for the exploration periods under the WCTP Petroleum Agreement have been met.

Deepwater Tano ("DT") Block

        Effective July 31, 2006, Kosmos Ghana, Tullow Ghana Limited and Sabre Oil and Gas Limited entered into the DT Petroleum Agreement with GNPC covering the DT Block offshore Ghana in the Tano Basin. Tullow Ghana Limited is the operator with a 49.95% working interest. Sabre Oil & Gas Holdings Limited has a 4.05% working interest. Kosmos Ghana originally held a 36% working interest in the block; however, as a result of a farmout by Kosmos Ghana to Anadarko WCTP Company effective September 1, 2006, Kosmos Ghana and Anadarko WCTP Company each have an 18%

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participating interest in the block. GNPC has a 10% participating interest and will be carried through the exploration and development phases. Under the DT Petroleum Agreement, GNPC exercised its option in January 2009 to acquire an additional paying interest of 5% in the commercial discovery with respect to the Jubilee Field development. GNPC is obligated to pay its 5% of all future petroleum costs, including development and production costs attributable to its 5% additional paying interest. Furthermore, it is obligated to pay 10% of the production costs of the Jubilee Field development, as allocated to the DT Block. In August 2009, GNPC notified us and our unit partners that it would exercise its right for the contractor group to pay its 5% 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 DT Petroleum Agreement. Kosmos Ghana is required to pay a fixed royalty of 5% and an additional oil entitlement which escalates as the nominal project rate of return increases. These royalties are to be paid in-kind or, at the election of the government of Ghana, in cash. A corporate tax rate of 35% is applied to profits at a country level.

        The DT Block comprises approximately 203,345 acres (823 square kilometers). The term of the DT Petroleum Agreement is 30 years from the effective date of such agreement, July 31, 2006. The initial exploration period is two and one-half years, divided into two subperiods. The first subperiod was for one year, and the contractor was obligated to reprocess 3D seismic data and acquire seabed logging. This commitment was met and the block partners entered the second subperiod. During the second subperiod of one and one-half years, the contractor was required to drill an exploration well, which was fulfilled by the drilling of the Tweneboa-1 exploration well and was announced as a light hydrocarbon/oil discovery on March 9, 2009. During December 2008, the block partners notified Ghana's Ministry of Energy of their intent to enter into the first extension period of two years commencing on January 19, 2009. Furthermore, on January 2011, Tullow, on behalf of the DT Block partners, formally extended the DT Petroleum Agreement into the second extension period. This second extension period requires the contractor to drill at least one exploration well in the contract area and incur a minimum expenditure of $20 million.

        The Ghanaian Petroleum Law and the WCTP and DT Petroleum Agreements form the basis of our exploration, development and production operations on these blocks. Pursuant to these petroleum agreements, most significant decisions, including PoDs and annual work program must be approved by a joint management committee, consisting of representatives of certain block partners and GNPC. Certain decisions require unanimity. See "Risk Factors—We are not, and may not be in the future, the operator on all of our license areas and do not, and may not in the future, hold all of the working interests in certain of our license areas. Therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and to an extent, any non-wholly owned, assets."

Jubilee Field Unitization

        The Jubilee Field, discovered by the Mahogany-1 well in June 2007, covers an area within both the WCTP and DT Blocks. Consistent with the Ghanaian Petroleum Law, the WCTP and DT Petroleum Agreements and as required by 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 results of the Mahogany-2 well. The Mahogany-2 well was announced as an oil 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.

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        Kosmos Ghana and its unit partners subsequently commenced development operations and negotiated a more comprehensive unit agreement, the UUOA, for the purpose of unitizing the Jubilee Field and governing each party's respective rights and duties in the Jubilee Unit. On July 13, 2009, Ghana's Ministry of Energy provided its written approval of the UUOA. The UUOA was executed by the unit partners and was effective as of July 16, 2009. As a result, for the Jubilee Unit, based on existing tract allocations (50% for each block) and GNPC electing to acquire their additional paying interest in both the WCTP and DT Blocks, Kosmos Ghana, Tullow Ghana Limited, Anadarko WCTP Company, Sabre Oil & Gas Holdings Limited, EO Group and GNPC's unit participating interests became 23.4913%, 34.7047%, 23.4913%, 2.8127%, 1.75% and 13.75%, respectively. Tullow Ghana Limited, a subsidiary of Tullow, is the Unit Operator, while Kosmos Ghana is the Technical Operator for Development of the Jubilee Unit. The Jubilee Unit holders' interests are subject to redetermination subject to the terms of the UUOA. See "Risk Factors—The unit partners' respective interests in the Jubilee Unit are subject to redetermination and our interests in such unit may decrease as a result." The accounting for the Jubilee Unit 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 interests in each block outside the boundary of the Jubilee Unit remains the same. Kosmos Ghana remains operator of the WCTP Block outside the Jubilee Unit area.

        The Technical Operator leads the IPT, which consists of several geoscience and engineering disciplines from within the unit partnership. The Technical Operator is tasked with evaluating the resource base, as well as developing an optimized reservoir depletion plan. This plan includes the design and placement of wells and the selection of topsides and subsea facilities. The Technical Operator's responsibilities also extend to the procurement, fabrication, inspection, testing, installation, and commissioning of the facilities. The Unit Operator's role is managerial in nature. The Unit Operator is responsible for providing in-country support for marine and air logistics, local goods & services procurement and community relations. In the field, the Unit Operator is responsible for the day-to-day operations and maintenance of the FPSO as well as drilling and completing the initial well plan according to the specifications outlined by the Technical Operator and the IPT. The Unit Operator oversees and optimizes the reservoir management plan, including any well work activity or additional infill drilling. The responsibility of the Technical Operator and the IPT for the Jubilee Field Phase 1 development will be completed as such development is brought fully online.

        On July 13, 2009, Ghana's Ministry of Energy provided its written approval of the Jubilee Phase 1 PoD. First oil from the Jubilee Field Phase 1 development commenced on November 28, 2010, and we intend to amend or submit PoDs for subsequent phases to Ghana's Ministry of Energy for approval in order to extend the producing plateau of the Jubilee Field.

Atwood Hunter drilling rig

        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 rig "Atwood Hunter." Noble Energy EG Ltd., an affiliate of Noble, also is a party to the contract. The contract, as amended, is for 1,152 days, with Kosmos Ghana and Noble allotted 797 days and 355 days, respectively. The initial rig rate is $537,097 per day and is subject to annual adjustments for cost increases. Effective July 27, 2010, the rig rate was $545,622 per day. Kosmos Ghana and Tullow Ghana Limited entered into a rig and services sharing agreement on October 18, 2009, for the use of the Atwood Hunter across the WCTP and DT Blocks during part of Kosmos Ghana's allocated time. In June 2010, the Atwood Hunter completed its first tranche of work for Kosmos Ghana and was assigned in accordance with the contract to Noble. In December 2010, the Atwood Hunter completed its first tranche of work for Noble and was returned to commence its second tranche of work for Kosmos Ghana. As of December 31, 2010, Kosmos has approximately 500 allocated days remaining for use of the Atwood Hunter drilling rig.

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Exploration Agreements—Other

        Effective June 26, 2006, Kosmos Energy Offshore Morocco HC, a wholly owned subsidiary, entered into the Boujdour Offshore Petroleum Agreement. Kosmos Energy Offshore Morocco HC has a 75% working interest and is the operator. The Moroccan national oil company, ONHYM, has a 25% working interest and is carried by us during the exploration phase. We are required to pay a royalty of 7%. These royalties are to be paid in-kind or, at the election of the government of Morocco, in cash. A corporate tax rate of 30% is applied to profits at the license level following a 10-year tax holiday post first production. The Boujdour Offshore Block, as covered by the original Boujdour Offshore Petroleum Agreement, comprises approximately 10.87 million acres (44,000 square kilometers) (See "Risk Factors—Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects.") The term of the Boujdour Offshore Petroleum Agreement is eight years and, as amended, includes an initial exploration period of four years and eight months followed by the first extension period of one year and the second extension period of two years and four months. A 2D seismic survey acquired and processed during 2008 indicated a 3D seismic survey was needed to enhance evaluation of an identified focus area in the block. A 2,056 square kilometer 3D seismic survey was acquired during early 2009 and interpretation of the survey is ongoing. On September 17, 2010 we entered a memorandum of understanding with ONHYM to enter into a new petroleum agreement covering the highest potential areas of the block under essentially the same terms as the original license.

        On November 16, 2005, Kosmos Energy Cameroon HC, a wholly owned subsidiary, acquired an interest in the Kombe-N'sepe Block onshore Cameroon from Perenco. The division of interests among the Kombe-N'sepe block partners is as follows: SNH, the national oil company of Cameroon, has a 25% working interest and an affiliate of Perenco has a 40% working interest. The Republic of Cameroon will back-in for a 60% revenue interest and a 50% carried paying interest in a commercial discovery on the Kombe-N'sepe block, with Kosmos then holding a 35% interest in the remaining interests of the block partners, which would result in Kosmos holding a 14% net revenue interest and a 17.5% paying interest. In addition, Kosmos and its block partners are reimbursed for 100% of the carried costs paid out of 35% of the total gross production coming from Cameroon's entitlement. We are guaranteed 50.63% of gross profit. An adjustment is made to taxable income to assure this guarantee. A corporate tax rate of 48.65% is applied to profits at the license level. The Kombe-N'sepe Block comprises approximately 748,000 acres (3,026 square kilometers) and is located along the coastal strip of the Douala Basin. The block extends more than 62 miles (100 kilometers) south of the city of Douala. The first exploration period of four years carries a minimum work program of acquisition, processing and interpretation of 62 miles (100 kilometers) of new 2D seismic data, drilling of one exploration well and an environmental impact study. There is a second exploration period of two years that carries no work obligations. In consideration of the acquisition, we are obligated to pay 100% of the first $5 million of costs incurred by Perenco for the minimum work program. It has been agreed by Perenco, SNH and us to drill two wells on the block in lieu of the original obligations of one well and to obtain 62 miles (100 kilometers) of 2D seismic data. Prior to expiration of the first exploration period on June 30, 2009, the operator, in consultation with SNH and Cameroon's Ministry of Energy, agreed on a process for entry into the second exploration period of two years during which the two wells will be drilled. Final government approval of entry into the second exploration period was received November 26, 2009.

        On December 19, 2006, Kosmos Energy Cameroon HC signed the Ndian River Production Sharing Contract covering the Ndian River Block located predominately onshore Cameroon. Kosmos has a 100% participating interest in the block and is the operator. SNH will be carried through the

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exploration and appraisal phases and has the option to back into the contract with an interest of up to 15% upon approval of a PoD. The Ndian River Production Sharing Contract provides for Kosmos to recover its share of expenses incurred ("cost recovery oil") and its share of remaining oil ("profit oil"). Cost recovery oil is apportioned to Kosmos from up to 60% of gross revenue prior to profit oil being split between the government of Cameroon and the contractor. Profit oil is then apportioned based upon "R-factor" tranches, where the R-factor is cumulative net revenues divided by cumulative net investment. A corporate tax rate of 40% is applied to profits. The initial period of the exploration phase is three years and there are two renewal periods of two years with each carrying a one-well obligation. The Ndian River Block comprises approximately 434,163 acres (approximately 1,757 square kilometers) and occupies a coastal strip of the Rio del Rey Basin in northwestern Cameroon. The block is located about 62 miles (100 kilometers) west-northwest of the city of Douala and extends to the Cameroon/Nigeria border. The license commitment requires us to conduct a 2D seismic survey (subject to a $5.5 million maximum spend commitment) as part of the multi-year exploration and exploitation agreement. Because of delays caused by difficulties in conducting seismic operations during the rainy season, the survey commenced in November 2009, causing a portion of the survey to be acquired beyond the initial exploration phase end date of November 19, 2009. In recognition of this, we, in consultation with SNH and Cameroon's Ministry of Industry, Mines and Technology Development, agreed to a process for receiving an extension to the initial period. On November 16, 2009, we received Ministry approval of a one year extension to the initial period of the exploration phase, which ended on November 19, 2010. A 2D seismic survey of 52 miles (85 kilometers) has been acquired in the block and interpretation of the survey is ongoing. On September 16, 2010, in accordance with the terms of the Ndian River Production Sharing Contract and after fulfillment of all the obligations of the initial period, we submitted an application for entry into the first renewal period of the exploration phase with an attendant one-well obligation. Formal approval by the Ministry is pending. Should such approval be obtained, we will have until November 19, 2012 to drill one exploratory well, pending ministerial approval. Planning for this well is ongoing.

Sales and Marketing

        Production from the Jubilee Field began on November 28, 2010, and we received our first oil revenues in early 2011. As provided under the UUOA and the WCTP and DT Petroleum Agreements, we are entitled to lift and sell our share of the Jubilee production in conjunction with the Jubilee Unit partners. We have entered an agreement with an oil marketing agent to market our share of the Jubilee oil on the international spot market, and we must approve the terms of each sale proposed by such agent. Oil from the Jubilee Field is currently selling at a premium to Dated Brent. We do not anticipate entering into any long term sales agreements at this time.

Competition

        The oil and gas industry is competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring and developing licenses. Many of these competitors have financial and technical resources and personnel substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses than our financial or personnel resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful wells, sustained periods of volatility in financial and commodities markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position.

        We are also affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment

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and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Over the past three years, oil and natural gas companies have experienced higher drilling and operating costs. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill wells and conduct our operations.

        Competition is also strong for attractive oil and natural gas producing assets, undeveloped license areas and drilling rights, and we cannot assure you that we will be able to successfully compete when attempting to make further strategic acquisitions.

Title to Property

        Other than as specified in this prospectus (for example, see "Risk Factors—A portion of our asset portfolio is in Western Sahara, and we could be adversely affected by the political, economic, and military conditions in that region. Our exploration licenses in this region conflict with exploration licenses issued by the Sahrawai Arab Democratic Republic"), we believe that we have satisfactory title to our oil and natural gas assets in accordance with standards generally accepted in the international oil and gas industry. Our licenses are subject to customary royalty and other interests, liens under operating agreements and other burdens, restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of or affect the carrying value of our interests.

Environmental Matters

General

        We and our operations are subject to various stringent and complex international, foreign, federal, state and local environmental, health and safety laws and regulations governing matters including the emission and discharge of pollutants into the ground, air or water; the generation, storage, handling, use and transportation of regulated materials; and the health and safety of our employees. These laws and regulations may, among other things:

•
require the acquisition of various permits before drilling commences;

•
enjoin some or all of the operations of facilities deemed not in compliance with permits;

•
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;

•
limit or prohibit drilling activities in certain locations lying within protected or otherwise sensitive areas; and

•
require remedial measures to mitigate or remediate pollution from our operations.

        These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. Compliance with these laws can be costly; the regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.

        Moreover, public interest in the protection of the environment continues to increase. Offshore drilling in some areas has been opposed by environmental groups and, in other areas, has been restricted. Our operations could be adversely affected to the extent laws are enacted or other governmental action is taken that prohibits or restricts offshore drilling or imposes environmental requirements that result in increased costs to the oil and gas industry in general, such as more stringent or costly waste handling, disposal or cleanup requirements.

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        For example, the Macondo spill described in "Risk Factors—Participants in the oil and gas industry are subject to numerous laws that can affect the cost, manner or feasibility of doing business" and "Risk Factors—Our operations could be adversely impacted by our block partner, whose affiliate is involved in the Macondo Gulf of Mexico oil spill" has resulted and will likely continue to result in increased scrutiny and regulation in the United States. The governments of the countries in which we currently or in the future will operate may also impose increased regulation as a result of this or similar incidents, which could materially delay or prevent our operations in those countries. Alternatively, increased scrutiny in the United States but not in the countries in which we operate could improve our competitive position if our competitors are themselves delayed or prevented from drilling in the United States.

        An Environmental Impact Assessment ("EIA") for the Jubilee Field was completed in November 2009. Extensive public consultation across Ghana was undertaken as part of the EIA program. This allowed for communication of information on the proposed development of the Jubilee Field, and consideration of concerns from key stakeholders that were then carried forward into the EIA process. We believe the EIA met both Ghanaian legislative requirements and international good practice standards. In December 2009, the Ghana EPA issued the first permit in a two-stage permit approval process, to cover installation and commissioning for the Jubilee Field Phase 1 development. In November 2010, the Ghana EPA issued the second permit covering offshore operations of the Phase 1 Jubilee Unit Area. Exploration appraisal activities outside the Jubilee Unit are covered by separate permits.

Climate Change

        Climate change regulation has gained momentum in recent years internationally and at the federal, regional, state and local levels. On the international front, representatives from 187 nations met in Bali, Indonesia in December 2007 as part of the United Nations Framework Convention on Climate Change, to discuss a program to limit greenhouse gas ("GHG") emissions after 2012. The convention adopted what is called the "Bali Action Plan." The Bali Action Plan contains no binding commitments, but concludes that "deep cuts in global emissions will be required" and provides a timetable for two years of talks to shape the first formal addendum to the 1992 United Nations Framework Convention on Climate Change treaty since the Kyoto Protocol. Various nations, including Ghana, Cameroon and Morocco have committed to reducing their GHG emissions pursuant to the Kyoto Protocol.

        In December 2009, an international meeting was held in Copenhagen, Denmark to further progress towards a new international treaty or agreement regarding GHG emissions reductions after 2012. A number of countries, including Ghana, Cameroon and Morocco, entered into the Copenhagen Accord, which represents a broad political consensus that reinforces the commitment to reducing GHG emissions contained in the Kyoto Protocol and contains non-binding emissions reductions targets. Further discussions towards an agreement took place in Cancun, Mexico at the end of 2010. Following discussions are scheduled for December 2011 in Durban, South Africa. Any treaty or other arrangement ultimately adopted by any of the countries in which we have operations or otherwise do business may increase our compliance costs, such as for monitoring or reducing emissions, and may have an adverse impact on the global supply and demand for oil and natural gas, which could have a material adverse impact on our business or results of operations.

        Furthermore, the physical effects of climate change could have an adverse effect on our operations through increased severity and frequency of weather events, including storms, floods and other events, which could increase costs to repair and maintain our facilities or delay or prevent our operations. If such effects were to occur, they could have an adverse effect on our exploration and production operations, or disrupt transportation or other process-related services provided by our third party contractors.

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Oil Spill Response

        Kosmos has developed and adopted an Oil Spill Contingency Plan ("OSCP") for the coordination of responses to oil spills arising from its operations in Ghana, including the WCTP Block. In addition, Tullow maintains an OSCP covering the Jubilee Field and DT Block. Under the OSCPs, emergency response teams may be activated to respond to oil spill incidents. We maintain a tiered response system for the mobilization of resources depending on the severity of an incident. Approximately 130 personnel (composed primarily of Tullow employees, Ghanaian Navy personnel and local contractors) have been trained on the assembly and operation of Tier 1 and Tier 2 onshore, nearshore and harbor response equipment. In the case of a Tier 3 incident, we engage the services of Oil Spill Response Limited ("OSRL") of Southampton, United Kingdom, an oil spill response contractor.

        Our associate membership with OSRL entitles us to utilize its oil spill response services comprising technical expertise and assistance, including access to response equipment and dispersant spraying systems. Kosmos does not own any oil spill response equipment. Instead, Kosmos and Tullow each maintain separate lease agreements with OSRL for Tier 1 and Tier 2 packages of oil spill response equipment. Tier 1 equipment, which is stored in "ready to go trailers" for effective mobilization and rapid deployment, includes booms and ancillaries, recovery systems, pumps and delivery systems, oil storage containers, personal protection equipment, sorbent materials, hand tools, containers and first aid equipment. Tier 2 equipment consists of larger boom and oil recovery systems, pump and delivery systems and auxiliary equipment such as generators and lighting sets, and is also containerized and pre-packed in trailers and ready for quick mobilization.

        As Unit Operator for the Jubilee Field, Tullow has additional response capability to handle an offshore Tier 1 response. Further, our membership in the West and Central Africa Aerial Surveillance and Dispersant Spraying Service gives us access to aircraft for surveillance and spraying of dispersant, which is administered by OSRL for a Tier 2 offshore response. The aircraft is based at the Kotoka International Airport in Accra, Ghana with a contractual response time, fully loaded with dispersant, of six hours. Additional stockpiles of dispersant are maintained in Takoradi.

        In the case of a Tier 3 event, our associate membership in OSRL provides us with access to the large stockpile of equipment in Southampton, United Kingdom along with access to additional dispersant spraying aircraft. Kosmos would hire additional resources such as boats, earth moving equipment and personnel as necessary to respond to such an event.

        Per common industry practice, under the agreements currently in place governing the terms of use of the drilling rigs used by us or our block partners, the drilling rig contractors indemnify us and our block partners in respect of pollution and environmental damage arising out of operations which originate above the surface of the water and from a drilling rig contractor's property, including, but not limited to, their drilling rig and other related equipment. Furthermore, pursuant to the terms of the operating agreements covering the blocks in which we or our block partners are currently drilling, except in certain circumstances, each block partner is responsible for the share of liabilities in proportion to its respective working interest in the block incurred as a result of pollution and environmental damage, containment and clean-up activities, loss or damage to any well, loss of oil or natural gas resulting from a blowout, crater, fire, or uncontrolled well, loss of stored oil and natural gas, and liabilities incurred in connection with plugging or bringing under control any well. Kosmos maintains insurance coverage for an incident concerning a well that results in pollution and environmental damage. The amount of annual insurance coverage maintained is proportional to our interest in a given well; with our current annual well control coverage being $300 million per incident multiplied by our working interest in a well for well control, re-drilling, pollution, clean up and containment, less a deductible of $5 million multiplied by our working interest. In addition we maintain annual third party liability coverage of $300 million multiplied by our working interest in a well for third party liabilities including pollution coverage, environmental damages liabilities and/or claims made

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by or on behalf of third party individuals in the event of such party's bodily injury or death. For example, if there were a well blowout in the Jubilee Unit (in which we have a 23.4913% working interest) our limit of well control, redrill and pollution clean up and containment coverage would be 23.4913% of $300 million (being $70.4 million) less a deductible of 23.4913% of $5 million (being $1.1 million), and our limit of liability coverage including pollution liability would be 23.4913% of $300 million (being $70.4 million).

Other Regulation of the Oil and Gas Industry

Ghana

        The Ghanaian Petroleum Law currently governs the upstream Ghanaian oil and natural gas regulatory regime and sets out the policy and framework for industry participants. All petroleum found in its natural state within Ghana is deemed to be national property and is to be developed on behalf of the people of Ghana. GNPC is empowered to carry out exploration and development work either on its own or in partnership with local or foreign partners. Companies who wish to gain rights to explore and produce in Ghana can only do so by entering into a petroleum agreement with Ghana and GNPC. The law requires for the terms of the petroleum agreement to be negotiated and agreed between GNPC and oil and gas companies. The Parliament of Ghana has final approval rights over the negotiated petroleum agreement. Ghana's Ministry of Energy represents the state in its regulatory capacity. GNPC has rights to undertake petroleum operations in any acreage declared open by Ghana's Ministry of Energy and has a carried interest in each petroleum agreement and is typically increased by a certain agreed upon amount at the option of GNPC following the declaration of any commercial discovery. Petroleum agreements are required to include certain domestic supply requirements, including the sale to Ghana of oil for consumption in Ghana at international market prices.

        The Ghanaian Petroleum Law and Ghanaian petroleum agreements contain provisions restricting the direct or indirect assignment or transfer of such petroleum agreements or other license interests without the prior written consent of GNPC and Ghana's Ministry of Energy. The Petroleum Law also imposes certain restrictions on the direct or indirect transfer by a contractor of shares of its incorporated company in Ghana to a third party without the prior written consent of Ghana's Minister of Energy. The Ghanaian Tax Law may impose certain taxes upon the direct or indirect transfer of interests in the petroleum agreements or other license interests.

        Ghana's Parliament is considering the enactment of a new Petroleum Exploration and Production Act and a new Petroleum Revenue Management Act. Industry participant commentary has been sought and submitted and these laws are currently in their draft stages. We currently believe that such laws will only have prospective application, and as such will not modify the terms of or interests under the agreements governing our license interests in Ghana, including the WCTP and DT Petroleum Agreements (which include stabilization clauses) and the UUOA, and will not impose restrictions on the direct or indirect transfer of our license interests, including upon a change of control. See "Risk Factors—Participants in the oil and gas industry are subject to numerous laws that can affect the cost, manner or feasibility of doing business."

Cameroon

        In 1999/2000, the government of Cameroon approved the Petroleum Code (the "Cameroon Petroleum Code") and Petroleum Regulations that were designed to rationalize regulation of the upstream local oil and gas industry. The Cameroon Petroleum Code applies to all license awards granted post 2000, which include thirteen production sharing contracts and three concession contracts. Arrangements entered into prior to 2000 are grandfathered under the former law. Companies who wish to gain rights to explore and produce in Cameroon can only do so by entering into a petroleum contract with Cameroon, represented by SNH, the Cameroon national oil company, and assignments of

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such contracts require the consent of the government. SNH, established in March 1980, participates in the form of joint ventures with the "contractors." Assignment of license interests requires the consent of SNH.

Morocco

        The two main legislative acts in Morocco relevant to petroleum exploration and production are (i) the Law 21-90 (1 April 1992) as amended and completed by the Law 27-99 (15 February 2000) and (ii) the Decree 2-93-786 (3 November 1993) as amended and completed by decree 2-99-210 (16 March 2000) (together, "Morocco's Petroleum Laws"). The regulatory authority in Morocco is the Ministry of Energy, Mines, Water and Environment and the national oil company acting on his behalf is the Office National des Hydrocarbures et des Mines  generally referred to as "ONHYM." ONHYM is a public establishment ( établissement public ) with the legal personality and financial autonomy created pursuant to the Law 33-01 (11 November 2003) which was further completed by the Decree 2-04-372 (29 December 2004).

        Pursuant to the Law 21-90, it is provided that the granting of an exploration permit is subject to the conclusion of a petroleum agreement with the Moroccan State. Therefore, companies who wish to gain rights to explore and produce in Morocco can only do so by entering into a petroleum agreement with ONHYM acting on behalf of the State. It is further provided that the State of Morocco (via ONHYM) shall retain a participation in exploration permits or exploitation concessions which shall not be in excess of 25%. More generally, ONHYM is representing the State of Morocco for licensing, exploration and exploitation matters within the limit of its prerogatives set out pursuant to the Law 33-01. Assignments of percentage interests in field developments also require the consent of the administration pursuant to the Law 21-90.

        The SADR has claimed sovereignty over the Western Sahara territory and has issued exploration licenses which conflict with those issued by Morocco, including certain licenses which conflict with the Boujdour Offshore license issued to Kosmos. See "Risk Factors—A portion of our asset portfolio is in Western Sahara, and we could be adversely affected by the political, economic, and military conditions in that region. Our exploration licenses in this region conflict with exploration licenses issued by the Sahrawai Arab Democratic Republic and "Industry—Morocco—Country Overview."

Certain Bermuda Law Considerations

        As a Bermuda exempted company, we are subject to regulation in Bermuda. Among other things, we must comply with the provisions of the Bermuda Companies Act regulating the payment of dividends and making of distributions from contributed surplus. See "Description of Share Capital" and "Dividend Policy."

        We have been designated by the Bermuda Monetary Authority as a non-resident for Bermuda exchange control purposes. This designation allows us to engage in transactions in currencies other than the Bermuda dollar, and there are no restrictions on our ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda or to pay dividends to United States residents who are holders of our common shares.

        Under Bermuda law, "exempted" companies are companies formed for the purpose of conducting business outside Bermuda from a principal place of business in Bermuda. As an exempted company, we may not, without a license or consent granted by the Minister of Finance, participate in certain business transactions, including transactions involving Bermuda landholding rights and the carrying on of business of any kind for which we are not licensed in Bermuda.

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Employees

        As of December 31, 2010, we had approximately 130 employees. All employees are currently located in the United States, Ghana, Cameroon or Morocco. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are satisfactory.

Legal Proceedings

        We are not currently party to any material legal proceedings. 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.

Corporate Information

        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. Kosmos Energy Holdings was formed as an exempted company limited by guarantee on March 5, 2004 pursuant to the laws of the Cayman Islands. Pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the closing of this offering, all of the interests in Kosmos Energy Holdings will be exchanged for newly issued common shares of Kosmos Energy Ltd. and as a result Kosmos Energy Holdings will become wholly-owned by Kosmos Energy Ltd.

        We maintain a registered office in Bermuda at Clarendon House, 2 Church Street, Hamilton HM 11, Bermuda. The telephone number of our registered offices is (441) 295-5950. Our U.S. subsidiary maintains its headquarters at 8176 Park Lane, Suite 500, Dallas, Texas 75231 and its telephone number is (214) 445-9600. Our web site is www.kosmosenergy.com . The information on our web site does not constitute part of this prospectus.

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MANAGEMENT

        The following table sets forth certain information concerning our board of directors, executive officers and key employees:
 	 	 	 	 	 	
Name	 	Age	 	Position	
John R. Kemp III	 	 	65	 	Chairman of the Board of Directors	
Brian F. Maxted	 	 	53	 	Director and Chief Executive Officer	
David I. Foley	 	 	43	 	Director	
Jeffrey A. Harris	 	 	55	 	Director	
David B. Krieger	 	 	37	 	Director	
Prakash A. Melwani	 	 	52	 	Director	
Adebayo ("Bayo") O. Ogunlesi	 	 	57	 	Director	
Chris Tong	 	 	54	 	Director	
Christopher A. Wright	 	 	63	 	Director	
W. Greg Dunlevy	 	 	55	 	Executive Vice President and Chief Financial Officer	
Paul Dailly	 	 	47	 	Senior Vice President, Exploration	
Marvin M. Garrett	 	 	54	 	Senior Vice President, Production and Operations	
William S. Hayes	 	 	56	 	Senior Vice President and General Counsel	
Dennis C. McLaughlin	 	 	59	 	Senior Vice President, Development	
Biographical information

        John R. Kemp III has served as a Director since 2005 and Chairman of our board of directors since January 2011. Mr. Kemp has nearly 15 years of experience in the oil and gas industry's international arena. Mr. Kemp has served on the board of Newfield Exploration Company since 2003. He is currently Chairman of Newfield Exploration's Compensation & Management Development Committee and a member of the Nominating & Corporate Governance Committee. From 1998 to 1999 he served in the role of President of Exploration and Production for the Americas at Conoco (now ConocoPhillips), where he managed the company's upstream operations and led growth efforts in North, South and Central America. Mr. Kemp joined Conoco in 1966 as an Engineer and went on to serve in various key engineering and management positions around the world throughout his career there. Mr. Kemp holds a Bachelor of Science in Petroleum and Natural Gas Engineering from Pennsylvania State University. He was named a Centennial Fellow and Alumni Fellow in 1996 and 1999, respectively, of Pennsylvania State's College of Earth and Mineral Sciences.

        Brian F. Maxted is one of the founding partners of Kosmos and has been our Chief Executive Officer since January 2011. Prior to this he served as our Senior Vice President, Exploration from 2003 to 2008 and our Chief Operating Officer between 2008 and 2011. He has also served as a Director of Broad Oak Energy since February 2008. Prior to co-founding Kosmos in late 2003, Mr. Maxted was the Senior Vice President of Triton where he led a series of discoveries offshore Equatorial Guinea, several of which are currently producing. Mr. Maxted holds a Master of Organic Geochemistry from the University of Newcastle-upon-Tyne and a Bachelor of Science in Geology from the University of Sheffield.

        David I. Foley has served as a Director since 2004. Mr. Foley is a Senior Managing Director in the Private Equity Group at Blackstone and is based in New York. Mr. Foley currently leads Blackstone's investment activities in the energy and natural resource sector. Since joining Blackstone in 1995, Mr. Foley has been responsible for the execution of virtually all of Blackstone's energy and natural resources investments, including: Premcor, Kosmos Energy, Foundation Coal, Texas Genco, Sithe Global Power, American Petroleum Tankers, OSUM, PBF Energy, Meerwind, Moser Baer and Monnet.

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Before joining Blackstone, Mr. Foley worked with AEA Investors in that firm's private equity business, and prior to that served as a consultant for the Monitor Company. Mr. Foley received a Bachelor of Arts and a Masters of Arts in Economics from Northwestern University and received a Master of Business Administration with distinction from Harvard Business School.

        Jeffrey A. Harris has served as a Director since 2005. Mr. Harris is a Managing Director at Warburg Pincus and has been with the firm since 1983. During his career, he has worked extensively in the industrial and technology sectors. Currently, he co-leads the firm's investment activities in the energy sector. Mr. Harris worked in Warburg Pincus' London office from 1991 to 1994 to help develop the firm's European investment activities. He is a director of Competitive Power Ventures Holdings, LLC, ElectroMagnetic GeoServices AS (emgs), Gulf Coast Energy Resources, Inc., Knoll, Inc., Laredo Petroleum, Inc., Osum Oil Sands Corp., Sheridan Production Partners and Spectraseis AG. Mr. Harris served previously on the boards of Bill Barrett Corporation, Comcast UK Cable, Newfield Exploration Company, and Spinnaker Exploration Company. He is past Chairman of the National Venture Capital Association. Currently he is Vice Chairman of the Board of Trustees for the Cranbrook Educational Community, and a member of the Board of Trustees of New York-Presbyterian Hospital. In addition, Mr. Harris is an adjunct professor at the Columbia University Graduate School of Business where he teaches courses on venture capital and innovation. Mr. Harris holds a Bachelor of Science from The Wharton School, University of Pennsylvania and a Master of Business Administration from Harvard Business School.

        David B. Krieger has served as a Director since 2004. Mr. Krieger is a Managing Director of Warburg Pincus and has been with the firm since 2000. Mr. Krieger is involved primarily with the firm's investment activities in the energy sector. Mr. Krieger is currently a Director of MEG Energy Corp. and several private companies. He received a Bachelor of Science in Economics from The Wharton School at the University of Pennsylvania, a Master of Science from the Georgia Institute of Technology, and a Master of Business Administration from Harvard Business School.

        Prakash A. Melwani has served as a Director since 2004. Mr. Melwani is a Senior Managing Director in the Private Equity group at Blackstone. Since joining Blackstone in 2003, Mr. Melwani has led Blackstone's investments in Ariel Re, Foundation Coal Holdings, Inc., Performance Food Group Company, Pinnacle Foods Group Inc., RGIS Inventory Specialists, and Texas Genco Holdings, Inc. Prior to joining Blackstone, Mr. Melwani was a founding partner of Vestar Capital Partners and served as its Chief Investment Officer. Previous to that, he was with the management buyout group at The First Boston Corporation and with N.M. Rothschild & Sons in Hong Kong and London. Mr. Melwani is currently a Director of Ariel Re, Performance Food Group, Pinnacle Foods and RGIS Inventory Specialists. He is also President and a Director of the India Fund and The Asia Tigers Fund. Mr. Melwani graduated with a First Class Honors degree in Economics from Cambridge University. He received a Master of Business Administration with High Distinction from the Harvard Business School and graduated as a Baker Scholar and a Loeb Rhoades Fellow.

        Adebayo ("Bayo") O. Ogunlesi has been a Director since 2004. Mr. Ogunlesi has been Chairman and Managing Partner of Global Infrastructure Partners ("GIP") since 2006, a private equity firm that invests in infrastructure assets in the energy, transport and water sectors, in both OECD and select emerging markets countries. Mr. Ogunlesi previously served as Executive Vice Chairman and Chief Client Officer of Credit Suisse's Investment Banking Division with senior responsibility for Credit Suisse's corporate and sovereign investment banking clients. From 2002 to 2004, he was Head of Credit Suisse's Global Investment Banking Department. Mr. Ogunlesi holds a Bachelor of Arts in Politics, Philosophy and Economics with first class honours from Oxford University, a Juris Doctor (magna cum laude) from Harvard Law School and a Master of Business Administration from Harvard Business School. From 1980 to 1981, he served as a Law Clerk to the Honorable Thurgood Marshall, Associate Justice of the United States Supreme Court.

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        Chris Tong has served as a Director since February 2011. Mr. Tong also serves as a director and Chairman of the Audit Committee of Targa Resources Corp. and Cloud Peak Energy Inc. He served as Senior Vice President and Chief Financial Officer of Noble Energy, Inc. from January 2005 until August 2009. He also served as Senior Vice President and Chief Financial Officer for Magnum Hunter Resources, Inc. from August 1997 until December 2004. Prior thereto, he was Senior Vice President of Finance of Tejas Acadian Holding Company and its subsidiaries, including Tejas Gas Corp., Acadian Gas Corporation and Transok, Inc., all of which were wholly-owned subsidiaries of Tejas Gas Corporation. Mr. Tong held these positions from August 1996 until August 1997, and had served in other treasury positions with Tejas since August 1989. Mr. Tong holds a Bachelor of Arts in Economics from the University of Louisiana Lafayette (formerly the University of Southwestern Louisiana).

        Christopher A. Wright has served as a Director since June 2004. From November 2005 to December 2010, Dr. Wright was the Executive Chairman of Fairfield Energy Limited before being appointed Chief Executive Officer in January 2011. From July 2004 to June 2010, he was a Director of ElectroMagnetic GeoServices AS (emgs). From 2001 to 2004, Dr. Wright was Senior Vice President, Global Exploration and Technology, for Unocal based in Houston. Before joining Unocal, between 1997 and 1999 he was first Director, New Business and then Chief Operating Officer for Lasmo plc in London. Prior to Lasmo plc, from 1996 to 1997 Dr. Wright led the Asia-Pacific and Middle East new business development efforts for the Mobil Oil Corporation, based out of Dallas and London. The major part of his career was with British Petroleum plc where he spent over 20 years in various technical and managerial roles of increasing seniority in locations both in the U.S. and the U.K. His final position with the company was Chief Executive, Frontier and International, which he held from 1991 to 1995. Dr. Wright holds both a Bachelor of Science and a Doctor of Philosophy in Geology from Bristol University and has also completed the Advanced Management Program at Harvard University.

        W. Greg Dunlevy is one of the founding partners of Kosmos and has served as our Executive Vice President and Chief Financial Officer since 2003. Prior to co-founding Kosmos in late 2003, Mr. Dunlevy was the Chief Executive Officer of Moncrief Oil International Incorporated between 2002 and 2003 and was also previously the Senior Vice President, Chief Financial Officer and treasurer of Triton Energy Limited. Mr. Dunlevy has extensive experience and expertise in oil and gas finance, planning, treasury and banking and has worked with major and mid-cap U.S. independents for more than 25 years. Mr. Dunlevy holds a Bachelor of Science from the College of William and Mary and a Masters of Business Administration from Harvard Business School.

        Paul Dailly is one of the founding partners of Kosmos and has served as Senior Vice President, Exploration since 2003. Mr. Dailly worked for British Petroleum plc between 1989 and 1994 and Triton Energy Limited between 1994 and 2001. While at Triton, Mr. Dailly was the geologist and technical team leader responsible for exploration and appraisal of that company's eight oil field discoveries offshore Equatorial Guinea. Mr. Dailly holds a Bachelor of Science (Honors) from Edinburgh University and a Doctor of Philosophy in Geology from the University of Oxford.

        Marvin M. Garrett has served as our Senior Vice President, Production and Operations since 2010, prior to which he served as our Senior Vice President of Operations and Development from January 2006. Before joining Kosmos in January 2006, Mr. Garrett was the Vice President of Operations for Triton where he led the development of the deepwater Ceiba oil field discovery offshore Equatorial Guinea and managed that company's drilling program in Argentina, China, Ecuador, Greece, Guatemala and Italy. Mr. Garrett has nearly three decades of experience managing oil and gas drilling, production and development activities worldwide. Mr. Garrett holds a Bachelor of Science degree in Petroleum Engineering from the University of Louisiana—Lafayette.

        William S. Hayes has served as our General Counsel since 2007. Prior to joining Kosmos, Mr. Hayes was Senior Vice President and General Counsel for Urals Energy PLC in 2007 and Cardinal Resources PLC from 2004 until 2007. Mr. Hayes has worked for or represented public and private,

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major and independent exploration and production companies in some 30 countries. Mr. Hayes holds a Juris Doctor from St. Mary's University School of Law and a Bachelor of Journalism from the University of Texas. He is a member of the State Bar of Texas, the International Bar Association and the Association of International Petroleum Negotiators.

        Dennis C. McLaughlin served as our Senior Vice President, Development since 2010, prior to which he served as our Vice President and Jubilee Project Director since 2008. Prior to joining Kosmos, Mr. McLaughlin worked for BHP Billiton Petroleum from 2000 to 2008 where he led the development of two large oil fields in the Gulf of Mexico. Mr. McLaughlin holds a Bachelor of Science in Mechanical Engineering with honors from Michigan State University.

Board of Directors

Board Composition

        Our bye-laws provide that the board of directors shall consist of not less than five directors and not more than 15 directors, and the number of directors may be changed only by resolution adopted by the affirmative vote of a majority of the entire board of directors. Upon the conclusion of this offering, we will have nine directors: Messrs. Kemp, Maxted, Foley, Harris, Krieger, Melwani, Ogunlesi, Tong and Wright.

        Initially, our board of directors will consist of a single class of directors each serving one year terms. Once the Investors, in the aggregate, no longer beneficially own more than 50% of the issued and outstanding common shares, our board of directors will be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms (other than directors which may be elected by holders of preferred shares, if any).

Director Independence

        We intend to avail ourselves of the "controlled company" exception under the NYSE rules, which exempts us from the requirements that a listed company must have a majority of independent directors on its board of directors and that its compensation and nominating and corporate governance committees be composed entirely of independent directors.

        In any event, our board of directors has reviewed the materiality of any relationship that each of our directors has with us, either directly or indirectly. Based on this review, the board has determined that each of Messrs. Wright, Ogunlesi and Tong is an "independent director" as defined by the NYSE rules and Rule 10A-3 of the Exchange Act.

Committees of the Board of Directors

        We are a "controlled company" as that term is set forth in Section 303A of the NYSE Listed Company Manual because more than 50% of our voting power is held by funds affiliated with our Investors, acting as a group. Under the NYSE rules, a "controlled company" may elect not to comply with certain NYSE corporate governance requirements, including (1) the requirement that a majority of the board of directors consist of independent directors, (2) the requirement that the nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities, (3) the requirement that the compensation committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities and (4) the requirement for an annual performance evaluation of the nominating and corporate governance and compensation committees. After completion of this offering more than 50% of our voting power will continue to be held by the Investors, and we intend to elect to be treated as a controlled company and thus avail ourselves of these exemptions. As a result, although we have adopted charters for our audit, nominating and corporate governance and

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compensation committees and intend to conduct annual performance evaluations of these committees, our board of directors does not consist of a majority of independent directors nor do our nominating and corporate governance and compensation committees consist of independent directors. Accordingly, so long as we are a "controlled company," you will not have the same protections afforded to shareholders of companies that are subject to all of the corporate governance requirements of the NYSE.

        Our board of directors has an audit committee, compensation committee and nominating and governance committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors has the composition and responsibilities described below.

        Audit committee.    The members of our audit committee are Messrs. Foley, Krieger, Ogunlesi and Tong, each of whom our board of directors has determined is financially literate. Mr. Tong is the Chairman of this committee. Our board of directors has determined that Mr. Tong is an audit committee financial expert. We will rely on the phase-in rules of the SEC and NYSE with respect to the independence of our audit committee. These rules permit us to have an audit committee that has one member that is independent upon the effectiveness of the registration statement of which this prospectus forms a part, a majority of members that are independent within 90 days thereafter and all members that are independent within one year thereafter. Our audit committee is authorized to:

•
recommend, through the Board, to the shareholders on their appointment and termination (subject to Bermuda law) of our independent auditors;

•
review the proposed scope and results of the audit;

•
review and pre-approve the independent auditors' audit and non-audit services rendered;

•
approve the audit fees to be paid (subject to authorization by our shareholders to do so);

•
review accounting and financial controls with the independent auditors and our financial and accounting staff;

•
review and approve transactions between us and our directors, officers and affiliates;

•
recognize and prevent prohibited non-audit services;

•
establish procedures for complaints received by us regarding accounting matters;

•
oversee internal audit functions; and

•
prepare the report of the audit committee that SEC rules require to be included in our annual meeting proxy statement.

        Compensation committee.    The members of our compensation committee are Messrs. Harris, Kemp and Melwani. Mr. Melwani is the Chairman of this committee. Our compensation committee is authorized to:

•
review and recommend the compensation arrangements for management, including the compensation for our Chairman and Chief Executive Officer;

•
establish and review general compensation policies with the objective to attract and retain superior talent, to reward individual performance and to achieve our financial goals;

•
administer our equity based incentive plan; and

•
prepare the report of the compensation committee that SEC rules require to be included in our annual meeting proxy statement.

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        Nominating and corporate governance committee.    The members of our nominating and corporate governance committee are Messrs. Harris, Kemp, Melwani and Ogunlesi. Mr. Ogunlesi is the Chairman of this committee. Our nominating and corporate governance committee is authorized to:

•
identify and nominate members for election to the board of directors;

•
develop and recommend to the board of directors a set of corporate governance principles applicable to our company; and

•
oversee the evaluation of the board of directors and management.

Compensation Committee Interlocks and Insider Participation

        No member of our compensation committee has been at any time an employee of ours. None of our executive officers will serve as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving as a member of our board of directors or compensation committee.

        To the extent any members of our compensation committee and affiliates of theirs have participated in transactions with us, a description of those transactions is described in "Certain Relationships and Related Person Transactions."

Code of Business Conduct and Ethics

        Our board of directors has adopted a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Corporate Governance Guidelines

        Our board of directors has adopted corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

Shareholders Agreement

        Prior to the consummation of this offering, we will enter into a shareholders agreement with affiliates of the Investors pursuant to which the Investors, collectively, will have the right to designate four members of our board of directors. Upon the consummation of this offering, each Investor will have the right to designate: (i) two directors (or, if the size of the board is increased, 25% of the board, rounded to the nearest whole number) if it owns 20% or more of the issued and outstanding common shares eligible to vote at an annual general meeting of shareholders and 50% or more of the common shares owned by such Investor immediately prior to the consummation of this offering, and (ii) one director (or, if the size of the board is increased, 12.5% of the board, rounded to the nearest whole number) if it owns 7.5% or more of the issued and outstanding common shares eligible to vote at an annual general meeting of shareholders. Under the shareholders agreement, subject to the corporate governance requirements of the NYSE, and for as long as the Investors constitute a group that beneficially owns more than 50% of the Company's voting power, the Investors shall have the right to designate 50% of the members of the nominating and corporate governance committee and a majority of the members of the compensation committee. After the Investors no longer constitute a group beneficially owning more than 50% of the Company's voting power, each Investor entitled to designate a director shall have the right to nominate one of its director designees to each committee of the board (other than the audit committee, which will include Investor-designated directors on a transition basis to the extent consistent with the corporate governance requirements of the NYSE). An Investor shall cease to have the right to designate committee members in the event that the Investor holds less than 7.5% of the issued and outstanding common shares eligible to vote at an annual general meeting of shareholders.

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Compensation Discussion and Analysis

        This section describes and explains our compensation program for 2010 for our named executive officers, who are listed as follows:

•
James Musselman, who served as our Chief Executive Officer during 2010, and who retired from his employment with Kosmos effective as of December 31, 2010;

•
Brian Maxted, who served as our Chief Operating Officer during 2010 and who became our Chief Executive Officer effective as of January 1, 2011;

•
Greg Dunlevy, Executive Vice President and Chief Financial Officer;

•
William Hayes, Senior Vice President and General Counsel; and

•
Dennis McLaughlin, Senior Vice President, Development.

This section also explains how the compensation that our named executive officers received prior to this offering will be treated in this offering and describes how we expect our compensation program for our named executive officers will change following this offering.

Objectives

        As a private company, our executive compensation program has been designed to meet the following objectives:

•
attract and retain highly talented and experienced executives who may have attractive opportunities with more well-established companies;

•
incentivize these executives to successfully grow our business and prepare us for this offering; and

•
maintain a strong ownership culture and align our executives' interests with those of our Investors by providing a substantial portion of the executives' compensation in the form of long-term equity-based incentives.

        Following this offering, we expect that, although the design of our compensation program will more closely resemble that of other public companies in our industry, the program will continue to be aimed at building long-term shareholder value by attracting, retaining and incentivizing talented, experienced executives.

Elements of Compensation

        To date, we have provided our executive officers with base salaries, annual cash bonuses, long-term equity-based incentive awards and retirement and health and welfare benefits. Following this offering, we expect that these elements will remain the same, although there may be changes in the relative amounts of compensation provided through each element and the design of each element. In particular, the design of our equity-based incentive awards will change, as we will be a public company with common shares rather than a private company with partnership interests.

Base Salary

        Each of our named executive officers receives a base salary that comprises a relatively modest portion of his compensation. In determining our named executive officers' base salaries, we consider factors such as the executive's experience and responsibilities and the salaries paid to our other executives and employees. We review their salaries annually for possible increases. In December 2010, each of our named executives (other than Mr. Musselman, who retired effective December 31, 2010) received a salary increase as follows: Mr. Maxted from $533,000 to $600,000, Mr. Dunlevy from $427,000 to $450,000, Mr. Hayes from $337,050 to $350,000 and Mr. McLaughlin from $331,700 to

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$350,000. For the amounts of base salary that the executives received in 2010, see "Summary Compensation Table—Salary".

Annual Bonus

        Each of our named executive officers is eligible for a discretionary annual cash bonus in an amount determined based on one or more of the following performance factors as related to his responsibilities: financial performance, operating performance, significant strategic initiatives, resolution of unforeseen events and organizational leadership. Although our compensation committee considers the level of achievement of each of these factors, other factors may be considered, and the bonuses are not calculated formulaically. The table below summarizes our named executive officers' achievement of the performance factors for 2010 (other than for Mr. Musselman, who, due to his retirement, was not eligible for a bonus for 2010). For the amounts of the bonuses paid to the executives for 2010, see "Summary Compensation Table—Bonus".
 	 	 	 	 	
Executive	 	Performance Factor	 	Achievement of Factor	
Mr. Maxted	 	Significant strategic initiatives	 	•       Pursued consummation of a commercial agreement to sell our Ghanaian assets to ExxonMobil	
 	 	 	 	•       Positioned Kosmos to pursue this offering	
 	 	Resolution of unforeseen events	 	•       Strengthened relationships with U.S. and Ghanaian governmental agencies	
 	 	Organizational leadership	 	•       Managed and expanded business and maintained employee morale during challenging period	
Messrs. Dunlevy and Hayes	 	Financial performance	 	•       Secured increase in project finance commercial bank facilities from $900 million to $1.25 billion to support Kosmos' share of Jubilee Field Phase 1 development expenditure	
 	 	Significant strategic initiatives	 	•       Initiated accelerated public offering and private placement funding processes	
 	 	Resolution of unforeseen events	 	•       Received DOJ letter of declination regarding closure of inquiry into alleged FCPA violations in connection with the WCTP Petroleum Agreement	
 	 	 	 	•       Managed ongoing FCPA review	
 	 	Organizational leadership	 	•       Engaged in ongoing corporate development in support of this offering and business growth	
 	 	 	 	•       Developed and enhanced existing internal controls to ensure compliance with laws applicable to public companies (e.g., Sarbanes-Oxley Act and NYSE listing requirements)	
Mr. McLaughlin	 	Operating performance	 	•       Actual total recordable incident rate and lost time incident rate of 1.38 and 0.46, respectively, substantially exceeded goals of 2.5 and 0.6, respectively	
 	 	Resolution of unforeseen events	 	•       Implemented recovery plans from potential delay-causing events with no material impact on first oil production	
 	 	Organizational leadership	 	•       Integrated project activities with internal functions and external unit operator, achieving seamless transition to production asset	
 	 	 	 	•       Assumed interim team leader role for Mahogany East	
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        Following this offering, we expect that our named executive officers will continue to be eligible for annual cash bonuses on terms to be determined by our compensation committee. For additional information on the annual bonuses for which our named executive officers and employees are eligible, see "Annual Incentive Plan."

Equity-based incentive awards

        Each of our named executive officers has received grants of profit units in Kosmos Energy Holdings, which are governed by Kosmos Energy Holdings' current operating agreement and individual certificates. The profit units provide the executives with the potential to receive a distribution on a sale of the assets of the partnership and a distribution of the proceeds in liquidation of the partnership. In connection with this offering, the executives' profit units will be exchanged for common shares and awards on common shares (see "—Awards under the LTIP"). The grants align our executives' interests with those of our Investors by tying a substantial portion of their compensation to the long-term success of the company.

        The profit units granted to Messrs. Musselman, Dunlevy and Maxted were granted with 20% vested on the grant date and an additional 20% scheduled to vest on each of the first four anniversaries of the grant date. The profit units granted to Messrs. Hayes and McLaughlin are scheduled to vest 50% on each of the second and fourth anniversaries of the grant date. Vesting of the unvested profit units held by Messrs. Dunlevy, Maxted, Hayes and McLaughlin would fully accelerate on termination of their employment due to their death or disability or on a change in control. See "—Potential Payments Upon Termination or Change in Control—Messrs. Maxted, Dunlevy, Hayes and McLaughlin." Mr. Musselman's unvested profit units became fully vested on his retirement effective December 31, 2010. See "—Potential Payments Upon Termination or Change in Control—Mr. Musselman."

        In 2010, we granted profit units to Messrs. Hayes and McLaughlin in light of their outstanding performance and to bring their equity compensation more in line with other executive officers of the company and did not grant profit units to any of our other named executive officers. See "—Summary Compensation Table—Option Awards" and "—Grants of Plan-Based Awards."

        We have adopted an omnibus long-term incentive plan that will become effective on the closing of this offering. The plan will provide for grants of equity-based awards such as share options, restricted shares, restricted share units and share appreciation rights. We believe that this omnibus plan will provide us with significant flexibility as a public company to create equity-based incentives for our executive officers, employees and directors. See "—Long Term Incentive Plan."

Retirement and Health and Welfare Benefits

        Our named executive officers are eligible to participate in our 401(k) savings plan on the same basis as our employees generally. We currently provide a 100% match of the first 6% of eligible compensation deferred by participants under the plan. We do not maintain any pension or nonqualified deferred compensation plans.

        Our named executive officers are eligible for health and welfare benefits on the same basis as our employees generally, including medical and dental coverage and life and disability insurance.

Severance and Change in Control Benefits

        Our named executive officers are not entitled to payments or benefits on termination of their employment or a change in control, other than the accelerated vesting of their unvested profit units on termination due to their death or disability or a change in control, as described above and under "—Potential Payments Upon Termination or Change in Control."

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Compensation Process

        For most of the period since our formation in 2003, our board of directors reviewed the recommendations of the compensation committee and determined our named executive officers' compensation. Following this offering, our compensation committee, in consultation with our Chief Executive Officer as to executives other than himself, will determine the compensation of our named executive officers. See "—Committees of the Board of Directors—Compensation committee."

Summary Compensation Table

        The following table summarizes the compensation of our named executive officers for 2010: our Chief Executive Officer, our Chief Financial Officer and our three other most highly compensated executive officers as determined by their total compensation set forth in the table. Mr. Musselman, who served as our Chief Executive Officer during 2010, retired from his employment with Kosmos effective as of December 31, 2010. Mr. Maxted, who served as our Chief Operating Officer during 2010, became our Chief Executive Officer effective as of January 1, 2011.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Name and
Principal Position	 	Year	 	Salary
($)(1)	 	Bonus
($)	 	Stock
Awards
($)	 	Option
Awards
($)(2)	 	Non-Equity
Incentive Plan
Compensation
($)	 	Change in
Pension
Value and
Non-qualified
Deferred
Compensation
Earnings
($)	 	All Other
Compensation
($)(3)	 	Total
($)	 	
James C. Musselman
Chairman and Chief Executive Officer	 	 	2010	 	 	593,000	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	11,792,648	 	 	12,385,648	 	
W. Greg Dunlevy
Executive Vice President and Chief Financial Officer	 	 	
2010	 	 	
428,917	 	 	
469,700	 	 	
—	 	 	
—	 	 	
—	 	 	
—	 	 	
14,785	 	 	
913,402	 	
Brian F. Maxted
Executive Vice President and Chief Operating Officer	 	 	
2010	 	 	
538,583	 	 	
900,000	 	 	
—	 	 	
—	 	 	
—	 	 	
—	 	 	
85	 	 	
1,438,668	 	
William S. Hayes
Senior Vice President and General Counsel	 	 	
2010	 	 	
338,130	 	 	
337,050	 	 	
—	 	 	
782,550	 	 	
—	 	 	
—	 	 	
26,900	 	 	
1,484,630	 	
Dennis C. McLaughlin
Senior Vice President of Development	 	 	
2010	 	 	
333,225	 	 	
406,700	 	 	
—	 	 	
782,550	 	 	
—	 	 	
—	 	 	
28,247	 	 	
1,550,722	 	

(1)
The amounts in this column are the actual amounts of salary paid to our named executive officers in 2010. Effective December 1, 2010, the annual salary rates of Messrs. Dunlevy, Maxted, Hayes and McLaughlin were increased to the following: Mr. Dunlevy ($450,000), Mr. Maxted ($600,000), Mr. Hayes ($350,000) and Mr. McLaughlin ($350,000). Mr. Musselman, who retired effective as of December 31, 2010, was not eligible for a salary increase.

(2)
The amounts in this column reflect the aggregate grant date fair values of profit units in Kosmos Energy Holdings that were granted to Messrs. Hayes and McLaughlin in 2010. These amounts are calculated in accordance with FASB ASC Topic 718, excluding the effect of estimated forfeitures. For the assumptions made in calculating these amounts, see footnote 18 to the unaudited consolidated financial statements of Kosmos Energy Holdings included in this prospectus. For additional information on these profit units, see "—Grants of Plan-Based Awards".

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(3)
The following items are reported in this column:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Name	 	401(k) Matching
Contributions
($)(4)	 	Vacation
Payments
($)(5)	 	Life
Insurance
($)(6)	 	Retirement
Payments
($)(7)	 	Total
($)	 	
James C. Musselman	 	 	—	 	 	—	 	 	85	 	 	11,792,563	 	 	11,792,648	 	
W. Greg Dunlevy	 	 	14,700	 	 	—	 	 	85	 	 	—	 	 	14,785	 	
Brian F. Maxted	 	 	—	 	 	—	 	 	85	 	 	—	 	 	85	 	
William S. Hayes	 	 	14,700	 	 	12,115	 	 	85	 	 	—	 	 	26,900	 	
Dennis C. McLaughlin	 	 	14,700	 	 	13,462	 	 	85	 	 	—	 	 	28,247	 	

(4)
Our named executive officers are eligible to participate in our 401(k) savings plan on the same basis as our employees generally. We provide a 100% match of the first 6% of eligible compensation deferred by participants under the plan.

(5)
Payments for accrued unused vacation time. We generally provide our employees, other than our Chief Executive Officer and our Chief Financial Officer, with annual payments for their accrued unused vacation time.

(6)
Employer portion of premiums paid with respect to life insurance for the benefit of our named executive officers on the same basis as our employees generally.

(7)
Includes severance in the amount of $593,000, accelerated vesting of unvested profit units in the amount of $11,107,063 and payment of $92,500 in legal fees provided to Mr. Musselman under his retirement agreement. The actual amount of severance that Mr. Musselman receives may be less than $593,000, as the monthly severance payments will cease prior to payment of the full amount on the completion of the lock-up period under agreements entered into with the underwriters of this offering. The value of such accelerated vesting is based on the valuation of the profit units as of December 31, 2010. See "—Potential Payments on Termination or Change in Control—Mr. Musselman."

2010 Grants of Plan-Based Awards

        The following table provides information on grants of plan-based awards made to our named executive officers during 2010. The awards were granted in the form of profit units in Kosmos Energy Holdings and will be exchanged for awards on common shares in connection with this offering (see "—Awards under the LTIP"). The share numbers set forth in the table assume solely for this purpose that this exchange had occurred as of the grant date of these units (based on an assumed initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price range set forth on the cover page of this prospectus).

	 	 

	 	 

	 	 
	 	All Other
Stock
Awards:
Number of
Shares of
Stock or
Units
(#)	 	All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#)	 	 

 
	 	 
	 	Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards	 	Estimated Future Payouts
Under Equity
Incentive Plan Awards	 	 	 	 	 	 
	 	Grant Date
Fair Value of
Stock and
Option
Awards
($)	 	 	 	 	 	 	 	 	

	 	 	 	 	 	 	 	 	 	Exercise or
Base Price of
Option
Awards
($/Sh)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Name	 	Grant
Date(1)	 	Threshold
($)	 	Target
($)	 	Maximum
($)	 	Threshold
(#)	 	Target
(#)	 	Maximum
(#)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
James C. Musselman	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	
W. Greg Dunlevy	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	
Brian F. Maxted	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	
William S. Hayes	 	 	12/9/2010	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	351,850	 	 	—	 	 	782,550	 	 	 	 	 	 	 	 	 	 	 	 	
Dennis C. McLaughlin	 	 	12/9/2010	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	351,850	 	 	—	 	 	782,550	 	 	 	 	 	 	 	 	 	 	 	 	

(1)
These profit units are scheduled to vest 50% on December 9 of each of 2012 and 2014. See "—Summary Compensation Table—Option Awards".

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Outstanding Equity Awards at 2010 Fiscal Year End

        The following table provides information on the outstanding equity awards held by our named executive officers as of December 31, 2010. These awards were granted in the form of profit units in Kosmos Energy Holdings and will be exchanged for common shares and awards on common shares in connection with this offering (see "—Awards under the LTIP"). The amounts set forth in the table assume solely for this purpose that this exchange had occurred as of December 31, 2010 (based on an assumed initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price range set forth on the cover page of this prospectus).

	 	 
	 	Option Awards	 	Stock Awards	 	
Name	 	Grant
Date	 	Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable	 	Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable	 	Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexercised
Unearned
Options
(#)	 	Option
Exercise
Price
($)	 	Option
Expiration
Date	 	Number of
Shares or
Units of
Stock
That Have
Not
Vested
(#)(1)	 	Market
Value of
Shares or
Units of
Stock
That Have
Not
Vested
($)	 	Equity
Incentive
Plan
Awards:
Number of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested
(#)	 	Equity
Incentive
Plan
Awards:
Market or
Payout
Value of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested
($)	 	
W. Greg Dunlevy	 	6/13/2007	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	123,311	 	 	2,096,285	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	1,134,108	 	 	19,279,829	 	 	—	 	 	—	 	
Brian F. Maxted	 	6/13/2007	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	184,965	 	 	3,144,412	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	1,701,160	 	 	28,919,721	 	 	—	 	 	—	 	
William S. Hayes	 	10/11/2007	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	82,208	 	 	1,397,528	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	38,163	 	 	648,764	 	 	—	 	 	—	 	
 	 	12/10/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	48,311	 	 	821,291	 	 	—	 	 	—	 	
 	 	12/9/2010	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	351,850	 	 	5,981,458	 	 	—	 	 	—	 	
Dennis C. McLaughlin	 	2/6/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	82,208	 	 	1,397,528	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	9,541	 	 	162,191	 	 	—	 	 	—	 	
 	 	12/10/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	48,311	 	 	821,292	 	 	—	 	 	—	 	
 	 	12/9/2010	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	351,850	 	 	5,981,458	 	 	—	 	 	—	 	

(1)
The profit units granted to Messrs. Musselman, Dunlevy and Maxted were granted 20% vested on the grant date, with an additional 20% scheduled to vest on each of the first four anniversaries of the grant date. The profit units granted to Messrs. Hayes and McLaughlin are scheduled to vest 50% on each of the second and fourth anniversaries of the grant date.

2010 Option Exercises and Stock Vested

        The following table provides information on our named executive officers' equity awards that vested in 2010. These awards were granted in the form of profit units in Kosmos Energy Holdings and will be exchanged for common shares in connection with this offering. The number of shares and value realized in the table assume solely for this purpose that this exchange had occurred as of the vesting date of the interests (based on an assumed initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price on the cover page of this prospectus).

	 	Option Awards	 	Stock Awards	 	
Name	 	Number of Shares
Acquired on Exercise
(#)	 	Value Realized
on Exercise
($)	 	Number of Shares
Acquired on Vesting
(#)	 	Value Realized
on Vesting
($)	 	
James C. Musselman	 	 	—	 	 	—	 	 	4,220,193	 	 	71,743,283	 	
W. Greg Dunlevy	 	 	—	 	 	—	 	 	690,365	 	 	11,736,200	 	
Brian F. Maxted	 	 	—	 	 	—	 	 	1,036,545	 	 	17,604,272	 	
William S. Hayes	 	 	—	 	 	—	 	 	86,474	 	 	1,470,056	 	
Dennis C. McLaughlin	 	 	—	 	 	—	 	 	140,060	 	 	2,381,010	 	
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Pension Benefits

        We do not maintain any defined benefit pension plans.

Nonqualified Deferred Compensation

        We do not maintain any nonqualified deferred compensation plans.

Potential Payments Upon Termination or Change in Control

        This section describes and quantifies the payments and benefits that each of Messrs. Dunlevy, Maxted, Hayes and McLaughlin would have received had his employment terminated under specified circumstances or had we undergone a change in control, in each case on December 31, 2010, and the payments and benefits that Mr. Musselman received on his retirement from his employment with Kosmos effective as of December 31, 2010.

Messrs. Dunlevy, Maxted, Hayes and McLaughlin

        Each of Messrs. Dunlevy, Maxted, Hayes and McLaughlin holds profit units in Kosmos Energy Holdings that were unvested as of December 31, 2010 (see "—Outstanding Equity Awards at Fiscal Year End"). Under Kosmos Energy Holdings' current operating agreement, these profit units would have become fully vested on December 31, 2010 if on such date the executives' employment had terminated due to their death or "disability" (as defined below) or had we undergone a "change in control" (as defined below). The estimated aggregate values of these units (based on an assumed initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price on the cover page of this prospectus) are as follows: Mr. Dunlevy ($21,376,115), Mr. Maxted ($32,064,133), Mr. Hayes ($8,849,041) and Mr. McLaughlin ($8,362,468).

        Messrs. Dunlevy, Maxted, Hayes and McLaughlin would not have been entitled to any other payments or benefits had their employment terminated due to their death or disability or had we undergone a change in control on December 31, 2010. In addition, the executives would not have been entitled to any payments or benefits of any kind had their employment terminated on December 31, 2010 for any reason other than due to their death or disability.

        "Disability" generally means the executive's incapacitation by accident, sickness or other circumstance that renders him mentally or physically incapable of performing his duties on a full-time basis for at least 180 days during any 12 month period.

        "Change in control" generally means:

•
a consolidation, conversion or merger involving Kosmos Energy Holdings in which the owners of the equity interests in Kosmos Energy Holdings immediately prior to such transaction do not, immediately after such transaction, own equity securities representing a majority of the outstanding voting power of the surviving entity; or

•
the sale, lease or transfer of all or substantially all of the assets of Kosmos Energy Holdings;

in either case, other than any such transaction that is approved by the holders of specified equity interests in Kosmos Energy Holdings.

Mr. Musselman

        On December 17, 2010, we entered into a retirement agreement with our then chief executive officer Mr. Musselman, which sets forth the terms of his retirement from his employment with Kosmos effective as of December 31, 2010. Pursuant to the retirement agreement, in consideration of

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Mr. Musselman's release of claims against us and our affiliates and his agreement to the restrictions described below, we provided him with the following payments and benefits:

•
Severance in an aggregate amount equal to his annual base salary of $593,000, paid in monthly installments through December 31, 2011. However, these payments will cease on the completion of the lock-up period under agreements to be entered into with the underwriters of this offering (but in no event earlier than March 31, 2011);

•
1,176,961 profit units in Kosmos Energy Holdings that were unvested as of his retirement date became fully vested as of such date. The estimated aggregate value of such interests is $46,314,878 (based on an assumed initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price on the cover page of this prospectus);

•
We paid his legal fees of $92,500 in connection with the negotiation of the retirement agreement;

•
We agreed not to exercise our right to repurchase his units in Kosmos Energy Holdings or to cause his units to be forfeited; and

•
We agreed to waive our right of first refusal under his employment agreement with respect to business opportunities referenced in the agreement and that the restrictions on competition and solicitation in the agreement would not apply to him after his retirement.

        In connection with this offering, all of Mr. Musselman's equity interests in Kosmos Energy Holdings (including those held in a family limited partnerhip), will be exchanged for common shares of Kosmos Energy Ltd. on the same basis as other equity holders, and such shares will be subject to the same restrictions on transfer as apply to our officers and directors and certain of our shareholders (see "Underwriting"). We also agreed that, after the expiration of these restrictions, he will not be subject to any future transfer restrictions or entitled to any registration rights with respect to his shares.

Employment Agreements

        We anticipate entering into an employment agreement with each of our named executive officers (other than Mr. Musselman, who retired from his employment with Kosmos effective December 31, 2010). The following is a summary of the material terms of these agreements.

        Terms.    The employment agreements will become effective immediately prior to the closing of this offering and will remain in effect for two years, in the case of Mr. Maxted, and one year, in the case of each of Messrs. Dunlevy, Hayes and McLaughlin. The term of each agreement will automatically extend for successive one-year periods unless either we or the executive provides the other with at least six months' written notice to the contrary.

        Positions.    The employment agreements set forth the executives' positions as follows: Mr. Maxted (Chief Executive Officer), Mr. Dunlevy (Executive Vice President and Chief Financial Officer), Mr. Hayes (Senior Vice President and General Counsel) and Mr. McLaughlin (Senior Vice President, Development).

        Base Salaries and Annual Bonuses.    The agreements provide for initial base salaries in the following amounts: Mr. Maxted ($600,000), Mr. Dunlevy ($450,000), Mr. Hayes ($350,000) and Mr. McLaughlin ($350,000). The salaries may be increased at the discretion of our board of directors. Each executive is eligible to receive an annual bonus based on the attainment of performance criteria determined by our board of directors or a board committee. Each agreement specifies a target annual bonus, which is expressed as a percentage of base salary, as follows: Mr. Maxted (150%), Mr. Dunlevy (100%), Mr. Hayes (75%) and Mr. McLaughlin (75%).

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        Benefits.    Each agreement provides that the executive is entitled to participate in our benefit plans and programs and to sick leave and paid vacation on the same terms as apply to our senior executives. In addition, each executive is entitled to club dues, financial planning and an executive health program.

        Death or Disability.    If the executive's employment terminates due to his death or "disability" (as defined in the agreement), he will be entitled to a pro rata portion of the annual bonus, if any, that he would have received for the year of termination, based on actual performance through the end of the year.

        Termination by Us without Cause or by the Executive for Good Reason.    If the executive's employment is terminated by us without "cause" or by the executive for "good reason" (as such terms are defined below), subject to his execution of a release in our favor, he will be entitled to the following payments and benefits:

•
a lump sum cash payment in an amount equal to the sum of his base salary and target bonus, and, for Messrs. Maxted and Dunlevy, if such termination occurs on or within two years after a "change in control" (as defined below), the lump sum cash payment will equal two times the sum of his base salary and target bonus;

•
a pro rata portion of the annual bonus, if any, that he would have received for the year of termination, based on actual performance through the end of the year; and

•
continued coverage under our group health plans at a cost to the executive that does not exceed the amount, if any, that we charge active senior executives for similar coverage until the earlier of 18 months after such termination or December 31 of the year after such termination. If such coverage ends before the expiration of the 18 month period, then, for the balance of the 18 month period, the executive will receive a cash payment equal to the company's portion of such coverage for active senior executives.

        The employment agreements generally define "cause" to mean the executive's:

•
willful failure to substantially perform his duties;

•
having engaged in willful misconduct, gross negligence, a breach of fiduciary duty or willful breach of his employment agreement that results in demonstrable harm to us;

•
conviction of a felony under U.S. law or a crime of similar import in a foreign jurisdiction;

•
breach of any of the restrictive covenants in the employment agreement, other than any such breach that causes no demonstrable or non-trivial damage to us;

•
material breach of any company policy, including any such policy that relates to expense management, human resources or the Foreign Corrupt Practices Act;

•
unlawful use or possession of illegal drugs on our premises or while performing his duties; or

•
commission of an act of fraud, embezzlement or misappropriation against us.

In each case other than for conviction, use or possession of illegal drugs or commission of fraud, embezzlement or misappropriation, we are required to provide the executive with written notice specifying the circumstances alleged to constitute cause, and, if possible, the executive will have 30 days to cure such circumstances.

        The employment agreements generally define "good reason" to mean:

•
a reduction in the executive's base salary or target bonus, other than any such reduction that applies generally to similarly situated employees;

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•
relocation of the geographic location of the executive's principal place of employment by more than 50 miles from Dallas, Texas;

•
the expiration of the term of the agreement after our election not to extend the term; or

•
a material reduction in the executive's duties or responsibilities that occurs within two years after a change in control.

In each case, the executive must provide us with written notice specifying the circumstances alleged to constitute good reason within 90 days after the first occurrence of such circumstances, and we will have 30 days to cure such circumstances. If we fail to cure such circumstances within 30 days, then the executive must terminate his employment not later than 60 days after the end of such 30-day period.

        Restrictive Covenants.    Each employment agreement prohibits the executive from competing with us or soliciting our employees, consultants, customers, suppliers, licensees and other business relations during his employment and for one year thereafter. Each agreement also contains perpetual restrictions on disclosing our confidential and proprietary information, a covenant regarding assignment of inventions and a mutual non-disparagement provision.

Long Term Incentive Plan and Awards

        We have adopted the Kosmos Energy Ltd. Long Term Incentive Plan, or LTIP, which permits us to grant an array of equity-based and cash incentive awards to our named executive officers and other employees and service providers. On the closing of this offering, we intend to issue restricted stock awards under the LTIP in exchange for unvested profit units in Kosmos Energy Holdings held by our named executive officers (other than Mr. Musselman, who retired effective December 31, 2010) and other employees. We also intend to issue additional equity awards to these named executive officers and to other employees on the closing of this offering. The following is a summary of the material terms of the LTIP and these awards.

Long Term Incentive Plan

        Purpose.    The purpose of the LTIP is to motivate and reward those employees and other individuals who are expected to contribute significantly to our success to perform at the highest level and to further our best interests and those of our shareholders.

        Eligibility.    Our employees, consultants, advisors, other service providers and non-employee directors are eligible to receive awards under the LTIP.

        Authorized Shares.    Subject to adjustment as described below, 24,503,000 shares of our common stock will be available for awards to be granted under the LTIP. Other than during the current calendar year, no participant may receive under the plan in any calendar year more than 2,450,300 shares in respect of each of the following three categories of awards: stock options and stock appreciation rights; restricted stock, restricted stock units and other stock-based awards; and performance awards. Shares underlying replacement awards (i.e., awards granted as replacements for awards granted by a company that we acquire or with which we combine) and awards that we grant on the closing of this offering will not reduce the number of shares available for issuance under the plan. If an award (other than a replacement award or an award granted on the closing of this offering) expires or is canceled or forfeited, the shares covered by the award again will be available for issuance under the plan. Shares tendered or withheld in payment of an exercise price or for withholding taxes also again will be available for issuance under the plan.

        Administration.    Our compensation committee administers the LTIP and has authority to:

•
designate participants;

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•
determine the types of awards to grant, the number of shares to be covered by awards, the terms and conditions of awards, whether awards may be settled or exercised in cash, shares, other awards, other property or net settlement, the circumstances under which awards may be canceled, repurchased, forfeited or suspended, and whether awards may be deferred automatically or at the election of the holder or the committee;

•
interpret and administer the plan and any instrument or agreement relating to, or award made under, the plan;

•
establish, amend, suspend or waive rules and regulations and appoint agents; and

•
make any other determination and take any other action that it deems necessary or desirable to administer the plan.

        Types of Awards.    The LTIP provides for grants of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units (RSUs), performance awards and other stock-based awards.

•
Stock Options.  A stock option is a contractual right to purchase shares at a future date at a specified exercise price. The per share exercise price of a stock option (other than a replacement award) will be determined by our compensation committee and may not be less than the closing price of a share of our common stock on the grant date. The committee will determine the date after which each stock option may be exercised and the expiration date of each option, provided that no option will be exercisable more than ten years after the grant date. Options that are intended to qualify as incentive stock options must meet the requirements of Section 422 of the Internal Revenue Code.

•
SARs.  SARs represent a contractual right to receive, in cash or shares, an amount equal to the appreciation of one share of our common stock from the grant date. Any SAR will be granted subject to the same terms and conditions as apply to stock options.

•
Restricted Stock.  Restricted stock is an award of shares of our common stock that are subject to restrictions on transfer and a substantial risk of forfeiture.

•
RSUs.  RSUs represent a contractual right to receive the value of a share of our common stock at a future date, subject to specified vesting and other restrictions.

•
Performance Awards.  Performance awards, which may be denominated in cash or shares, will be earned on the satisfaction of performance conditions specified by our compensation committee. The committee has authority to specify that any other award granted under the LTIP will constitute a performance award by conditioning the exercisability or settlement of the award on the satisfaction of performance conditions. The performance conditions for awards that are intended to qualify as "performance-based compensation" for purposes of Section 162(m) of the Internal Revenue Code will be limited to the following: captured prospects, prospecting licenses signed, operated prospects matured to drill ready, drilling programs commenced, drillable prospects, capabilities and critical path items established, operating budget, third-party capital sourcing, captured net risked resource potential, acquisition cost efficiency, acquisitions of oil and gas interests, increases in proved, probable or possible reserves, finding and development costs, recordable or lost time incident rates, overhead costs, general and administration expense, market price of a share of our common stock, cash flow, reserve value, net asset value, earnings, net income, operating income, cash from operations, revenue, margin, EBITDA (earnings before interest, taxes, depreciation and amortization), EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration expense), net capital employed, return on assets, shareholder return, reserve replacement, return on equity, return on capital employed, production, assets, unit volume, sales, market share, or strategic business criteria consisting of one or more objectives based on meeting specified goals relating to acquisitions or divestitures,

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each as determined in accordance with generally accepted accounting principles, where applicable, as consistently applied by us. These performance criteria may be measured on an absolute (e.g., plan or budget) or relative basis. Relative performance may be measured against a group of peer companies, a financial market index or other acceptable objective and quantifiable indices.•
Other Stock-Based Awards.  Our compensation committee is authorized to grant other stock-based awards, which may be denominated in shares of our common stock or factors that may influence the value of our shares, including convertible or exchangeable debt securities, other rights convertible or exchangeable into shares, purchase rights for shares, awards with value and payment contingent on our performance or that of our business units or any other factors that the committee designates.

        Adjustments.    In the event that, as a result of any dividend or other distribution, recapitalization, stock split, reverse stock split, reorganization, merger, amalgamation, consolidation, split-up, spin-off, combination, repurchase or exchange of shares of our common stock or other securities, issuance of warrants or other rights to purchase our shares or other securities, issuance of our shares pursuant to the anti-dilution provisions of our securities, or other similar corporate transaction or event affecting our shares, an adjustment is appropriate to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the LTIP, the compensation committee will adjust equitably any or all of:

•
the number and type of shares or other securities that thereafter may be made the subject of awards, including the aggregate and individual limits under the plan;

•
the number and type of shares or other securities subject to outstanding awards; and

•
the grant, purchase, exercise or hurdle price for any award or, if deemed appropriate, make provision for a cash payment to the holder of an outstanding award.

        Termination of Service and Change in Control.    Our compensation committee will determine the effect of a termination of employment or service on outstanding awards, including whether the awards will vest, become exercisable, settle or be forfeited (including by way of repurchase by the company at par value). The committee may set forth in the applicable award agreement the treatment of an award on a change in control. In addition, in the case of a stock option or SAR, except as otherwise provided in the applicable award agreement, on a change in control, a merger or consolidation involving us or any other event for which the committee deems it appropriate, the committee may cancel the award in consideration of:

•
a substitute award that preserves the intrinsic value of the canceled award; or

•
the full acceleration of the award and either:

•
a period of ten days to exercise the award; or

•
a payment in cash or other consideration in an amount equal to the intrinsic value of the canceled award.

        The LTIP generally defines a "change in control" to mean the occurrence any one or more of the following events:

•
the acquisition (other than by our Investors) of 50% or more of the combined voting power of our outstanding securities (other than by any company owned, directly or indirectly, by our shareholders in substantially the same proportions as their ownership of our common stock);

•
the replacement of the majority of our directors during any 12-month period (other than by directors approved by a majority of our remaining directors);

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•
the consummation of our merger or consolidation with another entity (unless our voting securities outstanding immediately prior to such transaction continue to represent more than 50% of the combined voting power of the surviving or resulting entity outstanding immediately after such transaction); or

•
the consummation of a transaction (or series of transactions within a 12-month period) that constitutes the sale or disposition of all or substantially all of our consolidated assets having a gross fair market value of 50% or more of the total gross fair market value of all of our consolidated assets (other than any such transaction immediately after which such assets will be owned directly or indirectly by our shareholders in substantially the same proportions as their ownership of our common stock immediately prior to such transaction), and the subsequent distribution of proceeds from such transaction (or series of transactions) to our shareholders having a fair market value that is greater than 50% of our fair market value immediately prior to such transaction (or series of transactions).

        Amendment and Termination.    Our board of directors may amend, alter, suspend, discontinue or terminate the LTIP, subject to approval of our shareholders if required by the rules of the stock exchange on which our shares are principally traded. Our compensation committee may amend, alter, suspend, discontinue or terminate any outstanding award. However, no such board or committee action that would materially adversely affect the rights of a holder of an outstanding award may be taken without the holder's consent, except to the extent that such action is taken to cause the LTIP to comply with applicable law, stock market or exchange rules and regulations or accounting or tax rules and regulations. In addition, the committee may amend the LTIP in such manner as may be necessary to enable the plan to achieve its stated purposes in any jurisdiction in a tax efficient manner and in compliance with local rules and regulations.

        Term.    The LTIP expires after ten years, unless prior to that date the maximum number of shares available for issuance under the plan has been issued or our board of directors terminates the plan.

Awards under the LTIP

        Unvested profit units in Kosmos Energy Holdings held by our employees, including our named executive officers (other than Mr. Musselman, as his unvested units became fully vested on his retirement effective December 31, 2010) will be exchanged in connection with this offering for an aggregate of 9,507,336 restricted shares of our common stock. In addition, on or shortly after the closing of this offering, we intend to grant to our named executive officers (other than Mr. Musselman) and other employees restricted shares in respect of an aggregate of approximately 14,080,000 shares of our common stock. These restricted shares will be governed by the LTIP and individual award agreements.

        The following table sets forth the number of restricted shares that each of our named executive officers (other than Mr. Musselman) is anticipated to hold on or shortly after the closing of this offering. Additional information about these awards follows the table.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Name	 	Restricted
Shares
(Exchange)
(#)	 	Restricted
Shares
(Service)
(#)	 	Restricted
Shares
(Performance)
(#)	 	Total
(#)	 	
Brian F. Maxted	 	 	1,886,125	 	 	2,588,235	 	 	647,059	 	 	5,121,419	 	
W. Greg Dunlevy	 	 	1,257,419	 	 	1,552,941	 	 	388,235	 	 	3,198,595	 	
William S. Hayes	 	 	520,532	 	 	705,882	 	 	176,471	 	 	1,402,885	 	
Dennis C. McLaughlin	 	 	491,910	 	 	470,588	 	 	117,647	 	 	1,080,145	 	
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        The share numbers set forth above are calculated based on an assumed initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price on the cover page of this prospectus.

        Each of Messrs. Maxted, Dunlevy, Hayes and McLaughlin will receive the restricted shares of our common stock in exchange for his unvested profit units and service-vesting restricted shares in connection with this offering. The restricted shares received in exchange for unvested profit units will be scheduled to vest on the same dates as his profit units were scheduled to vest, subject generally to his continued employment through each vesting date. The profit units granted to Messrs. Maxted and Dunlevy were granted 20% vested, with an additional 20% scheduled to vest on each of the first four anniversaries of the grant date. The profit units granted to Messrs. Hayes and McLaughlin are scheduled to vest 50% on each of the second and fourth anniversaries of the grant date. For additional information on these profit units, see "Grants of Plan-Based Awards" and "Outstanding Equity Awards at Fiscal Year-End".

        The executives are expected to receive additional service-vesting restricted shares on the closing of this offering that will be scheduled to vest 25% on each of the first four anniversaries of the grant date. Vesting of both the restricted shares received in exchange for the executives' unvested profit units and the additional service-vesting restricted shares will fully accelerate if the executive's employment is terminated due to his death or "disability," by us without "cause" or by him for "good reason" (as such terms are defined in his employment agreement). In addition, if we undergo a change in control, the shares will vest on the first anniversary of the change in control (or, if earlier, the regularly scheduled vesting date or on termination of the executive's employment by us or the acquiror without cause or by the executive for good reason). If the executive's employment is terminated by us for cause or by him without good reason at any time, he will forfeit any then unvested shares (or, in the committee's sole discretion, if required pursuant to applicable law to effect such forfeiture, the company may repurchase such shares at their par value).

        Each of Messrs. Maxted, Dunlevy, Hayes and McLaughlin also are expected to receive restricted shares on or shortly following the closing of this offering that will be subject to both service and performance conditions. On each of the first four anniversaries of the grant date, 25% of the service condition applicable to these restricted shares will be deemed met, subject generally to the executive's continued employment through each anniversary date. The performance condition will be determined prior to grant of these restricted shares.

        On termination of the executive's employment due to his death or disability, by us without cause or by him for good reason, the service condition will be deemed met, and the restricted shares will remain subject to the performance condition to the extent not yet met. If the executive terminates his employment without good reason, any restricted shares for which the service condition has been met will remain subject to the performance condition to the extent not yet met, and any restricted shares for which the service condition has not been met will be forfeited (or, in the committee's sole discretion, if required pursuant to applicable law to effect such forfeiture, such shares may be repurchased at their par value). If we undergo a change in control, the performance condition will be deemed met, and the service condition, to the extent not met as of the change in control, will be deemed met on the first anniversary of the change in control (or, if earlier, the regularly scheduled vesting date or on termination of the executive's employment by us or the acquiror without cause or by the executive for good reason). If the executive terminates his employment without good reason, any restricted shares for which the service condition is met will remain subject to the performance condition, and any restricted shares for which the service condition is not met will be forfeited (or, in the committee's sole discretion, if required pursuant to applicable law to effect such forfeiture, such shares may be repurchased at their par value). If the executive's employment is terminated by us for cause, he will forfeit any restricted shares for which either the service or performance condition is not

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met (or, in the committee's sole discretion, if required pursuant to applicable law to effect such forfeiture, such shares may be repurchased at their par value).

        On vesting of any of these restricted shares, the restrictions will lapse and, subject to the restrictions on transfer that apply to our officers and directors and certain of our shareholders (see "Underwriting") and any additional restrictions under any applicable lock up agreement, the shares will be fully transferable. Prior to vesting, the executives will have the right to vote the restricted shares and to receive current payment in respect of dividends paid on shares of our common stock.

Annual Incentive Plan

        We have adopted the Kosmos Energy Ltd. Annual Incentive Plan, under which our named executive officers and other employees are eligible for annual cash bonuses. The following is a summary of the material terms of the plan.

        Purpose.    The Annual Incentive Plan is designed to incentivize our executives and other employees to attain annual performance objectives, thereby furthering our best interests and those of our shareholders.

        Eligibility.    Each of our employees is eligible to receive an annual cash bonus under the plan for each fiscal year. Each employee who is employed for less than a full fiscal year will be eligible for a pro rata bonus for the year.

        Executive and Senior Manager Bonuses.    For each fiscal year, our compensation committee will:

•
identify each executive and senior manager who is eligible for an annual cash bonus under the plan;

•
establish objective criteria for determining the bonus payable to each executive and senior manager based on his or her base salary, a specified target bonus percentage, specified key performance indicators, individual performance goals and/or any other objective criteria that the committee deems appropriate, including, without limitation, performance goals based on the performance measures enumerated in our LTIP and summarized above (see "—Long Term Incentive Plan"); and

•
approve the actual amount of the bonus payable to each executive and senior manager based on the attainment of the applicable objective criteria, which amount the committee may increase or decrease based on such subjective criteria as the committee deems appropriate, including without limitation, such executive's or senior manager's individual performance.

        Staff Bonuses.    For each fiscal year, the committee will approve a bonus pool for employees who are not executives or senior managers. The amount of the bonus pool will be based on the employees' base salaries, specified target bonus percentages, specified key performance indicators, individual performance goals and/or any other objective criteria that the committee deems appropriate, including, without limitation, performance goals based on the performance measures enumerated in our LTIP and summarized above (see "—Long Term Incentive Plan"). Our chief executive officer will recommend for the committee's approval the actual amount of each employee's bonus, based on the attainment of the applicable objective criteria and any subjective criteria as the chief executive officer deems appropriate, including, without limitation, such employee's individual performance. The aggregate amount of the employees' bonuses for a fiscal year may not exceed the amount of the bonus pool approved by the committee for the year.

        Maximum Annual Bonus.    The annual cash bonus paid under the plan to any eligible employee for a single fiscal year shall not exceed $10 million.

        Amendment and Termination.    The committee may amend or terminate the plan at any time.

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2010 Director Compensation

        The following table lists the individuals who served as our non-employee directors in 2010 and summarizes their 2010 compensation. Neither our Investor directors nor our executive directors received compensation for their service as directors in 2010. Mr. Kemp, who served as a director in 2010, became Chairman effective January 1, 2011.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Name	 	Fees Earned or
Paid in Cash
($)(1)	 	Stock
Awards
($)	 	Option
Awards
($)(2)	 	Non-Equity
Incentive Plan
Compensation
($)	 	Change in Pension
Value and
Nonqualified
Deferred
Compensation
Earnings
($)	 	All Other
Compensation
($)	 	Total
($)	 	
John R. Kemp III	 	 	147,097	 	 	—	 	 	31,302	 	 	—	 	 	—	 	 	1,501	 	 	179,900	 	
David I. Foley	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
Jeffrey A. Harris	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
David B. Krieger	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
Prakash A. Melwani	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
Adebayo O. Ogunlesi	 	 	40,000	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	40,000	 	
Christopher A. Wright	 	 	40,000	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	40,000	 	

(1)
The amounts in this column reflect the annual cash retainer that was paid quarterly to each of Messrs. Kemp, Ogunlesi and Wright for his service as a director in 2010. Effective January 1, 2011, these retainers were increased to $50,000. For Mr. Kemp, the amount in this column also reflects a monthly fee of $40,000 provided under his consulting agreement for the period from October 11, 2010 through December 31, 2010 in anticipation of his becoming Chairman effective January 1, 2011.

(2)
The amount in this column reflects the aggregate grant date fair value of the profit units in Kosmos Energy Holdings granted to Mr. Kemp on November 17, 2010 under his consulting agreement in anticipation of his becoming Chairman effective January 1, 2011. This amount is calculated in accordance with FASB ASC Topic 718, excluding the effect of estimated forfeitures. For the assumptions made in calculating this amount, see footnote 17 to the unaudited consolidated financial statements of Kosmos Energy Holdings included in this prospectus.

Consulting Agreement with Mr. Kemp

        Effective October 11, 2010, we entered into a consulting agreement with Mr. Kemp pursuant to which he receives compensation for services as our Chairman and such other non-director services as we may reasonably request from time to time. Under the agreement, we provide Mr. Kemp with a monthly fee of $40,000. In addition, beginning April 11, 2011, Mr. Kemp will receive profit units in Kosmos Energy Holdings (issued at three-month intervals) with values determined by our compensation committee. In connection with this offering, these profit units will be exchanged for common shares. The consulting agreement also provides that we will reimburse Mr. Kemp for his reasonable expenses incurred in connection with his providing the services under the agreement, including travel expenses incurred by him and travel expenses incurred by his wife for travelling from Houston to Dallas to accompany him in the performance of his services.

        Either we or Mr. Kemp may terminate the consulting agreement on 30 days' prior written notice. In addition, either we or he may request at any time that the monthly fee and the grants of profit units cease to be provided to him. The agreement contains a customary covenant restricting Mr. Kemp from disclosing our confidential information.

Restricted Stock Award to Mr. Tong

        In February 2011, we appointed Chris Tong to our board of directors. Mr. Tong also serves as the Chairman of our audit committee. As compensation for his service as a director and Chairman of our audit committee, on April 11, 2011, our compensation committee approved the grant to Mr. Tong of an award of 6,000 restricted shares. These restricted shares will be granted under the LTIP on or shortly after the closing of this offering and will be subject to the same four-year vesting schedule and

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accelerated vesting provisions as are described above for the service-vesting restricted stock awards that we intend to grant to Messrs. Maxted, Dunlevy, Hayes and McLaughlin (see "—Long Term Incentive Plan and Awards-Awards under the LTIP"). In addition, on or shortly after the closing of this offering, we intend to grant to Mr. Tong an award of 7,353 restricted shares. These restricted shares will also be granted under the LTIP and will be subject to a one-year vesting schedule.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

        The following is a description of the transactions we have engaged in since January 1, 2010 with our directors and officers and beneficial owners of more than five percent of our voting securities and their affiliates.

        The operating agreement governing our predecessor, Kosmos Energy Holdings, was initially entered into on March 9, 2004 and amended on each of February 20, 2005, June 13, 2007, September 18, 2007, June 18, 2008, December 18, 2008, October 9, 2009 and December 16, 2010 (as amended and restated, the "OA"), among our Investors and certain members of our management and employees. Pursuant to the OA and related contribution agreements, such Investors, members of our management and employees purchased Series A, B and C Convertible Preferred Units and were issued C1 Common Units since our inception. None of these units were purchased in the fiscal year ended December 31, 2010. Additionally, the OA contemplated the issuance of management and profit units as compensation for members of our management and our employees. See "Management." The OA also provided that the holders of the Series A, B and C Convertible Preferred Units receive distributions, if any, equal to the "Accreted Value" of the units, prior to any distributions to the common unit holders. The accumulated preferred return amounts for the Convertible Preferred Units totaled approximately $153.5 million at December 31, 2010. In addition, as a result of the issuance of Series C Convertible Preferred Units and the associated C1 Common Units, a discount existed on the Series C Convertible Preferred Units of approximately $11.8 million. The accumulated preferred return on the Convertible Preferred Units and the discount on the Series C Convertible Preferred Units 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.

        Pursuant to the terms of the corporate reorganization that will occur prior to or concurrently with the closing of the offering described in this prospectus, all of the interests in Kosmos Energy Holdings will be exchanged for common shares of Kosmos Energy Ltd., and the OA will be terminated and a new memorandum of association and articles of association will be put in place for Kosmos Energy Holdings. See "Corporate Reorganization." We have agreed to reimburse our Investors for their fees and expenses incurred in connection with this offering and the related corporate reorganization.

        We have entered into customary indemnification agreements with our directors. In addition, prior to the completion of this offering, we will become a party to the existing registration rights agreement by and among Kosmos Energy Holdings and its unitholders pursuant to which we will grant certain registration rights to the unitholders with respect to the common shares they will receive in the corporate reorganization. See "Shares Eligible for Future Sale—Registration Rights." Also prior to the completion of this offering, we will enter into a shareholders agreement with affiliates of the Investors. See "Management—Shareholders Agreement."

        Prior to the closing of this offering we will adopt a set of related party transaction policies designed to minimize potential conflicts of interest arising from any dealings we may have with our affiliates and to provide appropriate procedures for the disclosure, approval and resolution of any real or potential conflicts of interest which may exist from time to time. Such policies will provide, among other things, that all related party transactions, including any loans between us, our principal shareholders and our affiliates, will be approved by our nominating and corporate governance committee of the board of directors, after considering all relevant facts and circumstances, including without limitation the commercial reasonableness of the terms, the benefit and perceived benefit, or lack thereof, to us, opportunity costs of alternative transactions, the materiality and character of the related party's direct or indirect interest, and the actual or apparent conflict of interest of the related party, and after determining that the transaction is in, or not inconsistent with, our and our shareholders' best interests.

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PRINCIPAL SHAREHOLDERS

        The following table sets forth certain information with respect to the beneficial ownership of our common shares, on a fully-diluted basis, as of December 31, 2010, and after giving effect to our corporate reorganization, for:

•
each of our current executive officers;

•
each of our current directors;

•
all our current executive officers and directors as a group; and

•
each shareholder known by us to be the beneficial owner of more than 5% of our issued and outstanding common shares.

        Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Common shares that may be acquired by an individual or group within 60 days of December 31, 2010, pursuant to the exercise of options or warrants, are deemed to be outstanding for the purpose of computing the percentage ownership of such individual or group, but are not deemed to be outstanding for the purpose of computing the percentage ownership of any other person shown in the table. Percentage of ownership is based on 341,176,471 common shares issued and outstanding on December 31, 2010, after giving effect to our corporate reorganization, plus 30,000,000 common shares that we are selling in this offering. The underwriters have an option to purchase up to 4,500,000 additional common shares from us to cover over-allotments.

        Except as indicated in footnotes to this table, we believe that the shareholders named in this table have sole voting and investment power with respect to all common shares shown to be beneficially owned by them, based on information provided to us by such shareholders. Unless otherwise indicated, the address for each director and executive officer listed is: 8176 Park Lane, Suite 500, Dallas, Texas, 75231.

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	 	Percentage of Shares
Beneficially Owned(1)(2)	 	
Name and Address of Beneficial Owner	 	Number of Shares
Beneficially
Owned(1)	 	Before the Offering	 	After the Offering	 	
Directors and Executive Officers	 	 	 	 	 	 	 	 	 	 	
John R. Kemp III	 	 	732,933	 	 	0.21	%	 	0.20	%	
David I. Foley(4)	 	 	—	 	 	—	 	 	—	 	
Jeffrey A. Harris(3)	 	 	—	 	 	—	 	 	—	 	
David Krieger(3)	 	 	—	 	 	—	 	 	—	 	
Prakash A. Melwani(4)	 	 	—	 	 	—	 	 	—	 	
Adebayo O. Ogunlesi	 	 	1,373,312	 	 	0.40	%	 	0.37	%	
Chris Tong	 	 	—	 	 	—	 	 	—	 	
Christopher A. Wright	 	 	662,545	 	 	0.19	%	 	0.18	%	
Brian F. Maxted(5)	 	 	10,657,197	 	 	3.12	%	 	2.87	%	
W. Greg Dunlevy(6)	 	 	7,237,972	 	 	2.12	%	 	1.95	%	
William S. Hayes(7)	 	 	805,192	 	 	0.24	%	 	0.22	%	
Dennis C. McLaughlin(8)	 	 	691,729	 	 	0.20	%	 	0.19	%	
All directors and executive officers as a group (12 individuals)	 	 	22,160,880	 	 	6.50	%	 	5.97	%	
Five Percent Shareholders	 	 	 	 	 	 	 	 	 	 	
Warburg Pincus Funds(3)	 	 	155,099,918	 	 	45.46	%	 	41.79	%	
Blackstone Funds(4)	 	 	126,899,910	 	 	37.19	%	 	34.19	%	

(1)
Assumes the completion of our corporate reorganization prior to or concurrently with the closing of this offering. See "Corporate Reorganization."

(2)
Assumes no exercise of the underwriters' option to purchase additional shares. The number of shares held by our principal shareholders will depend on the initial public offering price of a common share and the date upon which this offering is completed.

(3)
The Warburg Pincus Funds are comprised of the following entities: Warburg Pincus International Partners, L.P., a Delaware limited partnership, together with two affiliated partnerships ("WPIP") who collectively hold 77,549,959 shares, and Warburg Pincus Private Equity VIII, L.P., a Delaware limited partnership, together with two affiliated partnerships ("WP VIII") who collectively hold 77,549,959 shares. Warburg Pincus Partners, LLC, a New York limited liability company ("WP Partners"), and direct subsidiary of Warburg Pincus & Co., a New York general partnership ("WP"), is the sole general partner of WPIP and WP VIII. WP is the managing member of WP Partners. WPIP and WP VIII are managed by Warburg Pincus LLC, a New York limited liability company ("WP LLC"). Messrs. Harris and Krieger, directors of Kosmos Energy Ltd., are Partners of WP and Managing Directors and Members of WP LLC. All shares indicated as owned by Messrs. Harris and Krieger are included because of their affiliation with the Warburg Pincus entities. Messrs. Harris and Krieger disclaim beneficial ownership of all shares owned by the Warburg Pincus entities. Charles R. Kaye and Joseph P. Landy are Managing General Partners of WP and Managing Members and Co-Presidents of WP LLC and may be deemed to control the Warburg Pincus entities. Messrs. Kaye and Landy disclaim beneficial ownership of all shares held by the Warburg Pincus entities. The address of Messrs. Harris, Krieger, Kaye and Landy, WP VIII, WPIP, WP Partners, WP, WP LLC is 450 Lexington Avenue, New York, New York 10017.

(4)
The Blackstone Funds (as hereinafter defined) are comprised of the following entities: Blackstone Capital Partners (Cayman) IV L.P. ("BCP IV"), Blackstone Capital Partners (Cayman) IV-A L.P. ("BCP IV-A"), Blackstone Family Investment Partnership (Cayman) IV-A L.P ("Family"), Blackstone Participation Partnership (Cayman) IV L.P. ("Participation") and Blackstone Family Investment Partnership (Cayman) IV-A SMD L.P. ("Family SMD", and together with BCP IV,

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BCP IV-A, Family and Participation, the "Blackstone Funds"). The Blackstone Funds beneficially own (i) 118,867,656 shares, which are held by BCP IV, (ii) 1,938,499 shares, which are held by BCP IV-A, (iii) 3,136,210 shares, which are held by Family, (iv) 353,568 shares, which are held by Participation, and (v) 2,603,976 shares, which are held by Family SMD. Blackstone Management Associates (Cayman) IV L.P. ("BMA") is a general partner of each of BCP IV and BCP IV-A. Blackstone LR Associates (Cayman) IV Ltd. ("BLRA") and BCP IV GP L.L.C. are general partners of each of BMA, Family and Participation. Blackstone Holdings III L.P. is the sole member of BCP IV GP L.L.C. and a shareholder of BLRA. Blackstone Holdings III L.P. is indirectly controlled by The Blackstone Group L.P. and is owned, directly or indirectly, by Blackstone professionals and The Blackstone Group L.P. The Blackstone Group L.P. is controlled by its general partner, Blackstone Group Management L.L.C., which is in turn, wholly owned by Blackstone's senior managing directors and controlled by its founder, Stephen A. Schwarzman. In addition, Mr. Schwarzman is a director and controlling person of BLRA. Family SMD is controlled by its general partner, Blackstone Family GP L.L.C., which is in turn wholly owned by Blackstone's senior managing directors and controlled by its founder, Mr. Schwarzman. Each of such Blackstone entities and Mr. Schwarzman may be deemed to beneficially own the shares beneficially owned by the Blackstone Funds directly or indirectly controlled by it or him, but each disclaims beneficial ownership of such shares except to the extent of its or his indirect pecuniary interest therein. Mr. Foley and Mr. Melwani are senior managing directors of Blackstone Group Management L.L.C. and neither is deemed to beneficially own the shares beneficially owned by the Blackstone Funds. The address of each of the Blackstone Funds, BMA and BLRA is c/o Walkers Corporate Services Limited, 87 Mary Street, George Town, Grand Cayman KY1-9005, Cayman Islands and the address for Mr. Schwarzman and each of the other entities listed in this footnote is c/o The Blackstone Group, L.P., 345 Park Avenue, New York, New York 10154.(5)
Includes 1,391,447 restricted shares issued to Mr. Maxted in connection with our corporate reorganization but excludes 3,235,294 restricted shares intended to be issued to Mr. Maxted on or shortly after the closing of this offering pursuant to our LTIP. Also includes 494,678 restricted shares and 2,920,299 common shares issued to Maxted Family Investments, Ltd., an entity which Mr. Maxted is a beneficial owner of, in connection with our corporate reorganization.

(6)
Includes 593,924 restricted shares issued to Mr. Dunlevy in connection with our corporate reorganization but excludes 1,941,176 restricted shares intended to be issued to Mr. Dunlevy on or shortly after the closing of this offering pursuant to our LTIP. Also includes 663,493 restricted shares and 1,092,140 common shares issued to 2008 Carnegie, Ltd., an entity which Mr. Dunlevy is a beneficial owner of, in connection with our corporate reorganization.

(7)
Includes 520,531 restricted shares issued to Mr. Hayes in connection with our corporate reorganization but excludes 882,353 restricted shares intended to be issued to Mr. Hayes on or shortly after the closing of this offering pursuant to our LTIP.

(8)
Includes 491,910 restricted shares issued to Mr. McLaughlin in connection with our corporate reorganization but excludes 588,235 restricted shares intended to be issued to Mr. McLaughlin on or shortly after the closing of this offering pursuant to our LTIP.

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DESCRIPTION OF SHARE CAPITAL

        The following description of certain provisions of our memorandum of association and bye-laws does not purport to be complete and is subject to, and qualified by reference to, all of the provisions of our memorandum of association and bye-laws.

General

        We are an exempted company organized under the Bermuda Companies Act. The rights of our shareholders will be governed by Bermuda law and our memorandum of association and bye-laws. The Bermuda Companies Act differs in some material respects from laws generally applicable to Delaware corporations, which differences have been highlighted in the discussion below.

Share Capital

        Our authorized share capital consists of 2,000,000,000 common shares, par value $0.01 per share, and 200,000,000 preference shares, par value $0.01 per share. Upon completion of this offering, there will be 371,176,471 common shares and no preference shares issued and outstanding. All of our issued and outstanding common shares will be fully paid and non-assessable.

        Pursuant to our bye-laws, subject to the requirements of the New York Stock Exchange, our board of directors is authorized to issue any of our authorized but unissued shares.

Common Shares

        Holders of common shares are entitled to one vote per share on all matters submitted to a vote of holders of common shares. Subject to preferences that may be applicable to any issued and outstanding preference shares, holders of common shares are entitled to receive such dividends, if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. Holders of common shares have no redemption, sinking fund, conversion, exchange, pre-emption or other subscription rights. In the event of our liquidation, dissolution or winding up, the holders of common shares are entitled to share equally and ratably in our assets, if any, remaining after the payment of all of our debts and liabilities, subject to any liquidation preference on any outstanding preference shares.

Preference Shares

        Pursuant to Bermuda law and our bye-laws, our board of directors is authorized to provide for the issuance of one or more series of preference shares having such number of shares, designations, dividend rates, voting rights, conversion or exchange rights, redemption rights, liquidation rights and other powers, preferences and rights as may be determined by the board without any further shareholder approval. Preference shares, if issued, would have priority over common shares with respect to dividends and other distributions, including the distribution of our assets upon liquidation. Although we have no present plans to issue any preference shares, the issuance of preference shares could decrease the amount of earnings and assets available for distribution to the holders of common shares, could adversely affect the rights and powers, including voting rights, of common shares and could have the effect of delaying, deterring or preventing a change in control of us or an unsolicited acquisition proposal.

Board Composition

        Our bye-laws provides that our board of directors will determine the size of the board, provided that it shall be at least five and no more than 15. Our board of directors will initially consist of nine directors.

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        Pursuant to a shareholders agreement entered into by us and affiliates of the Investors, each Investor shall have the right to designate two nominees (or if the size of the board of directors is increased, 25% of the board, rounded to the nearest whole number) if it beneficially owns (A) 20% or more of the issued and outstanding common shares eligible to vote at an annual general meeting of shareholders and (B) 50% or more of the common shares owned by such Investor immediately prior to this offering and one nominee (or if the size of the board of directors is increased, 12.5% of the board, rounded to the nearest whole number) if it beneficially owns 7.5% or more of the issued and outstanding common shares. See "Management—Board of Directors—Board Composition."

Election and Removal of Directors

        Our bye-laws provide that, prior to the first date on which the Investors no longer constitute a group which beneficially owns more than 50% of the issued and outstanding shares entitled to vote, all directors will be up for election each year at our annual general meeting of shareholders. On or after such date, our board of directors will be a classified board divided into 3 classes, with one class coming up for election each year. The election of our directors will be determined by a plurality of the votes cast at the general meeting of shareholders at which the relevant directors are to be elected. Our shareholders do not have cumulative voting rights and accordingly the holders of a plurality of the shares voted can elect all of the directors then standing for election. Our bye-laws require advance notice for shareholders to nominate a director or present proposals for shareholder action at an annual general meeting of shareholders. See "—Meetings of Shareholders."

        Under our bye-laws, prior to the first date on which the Investors no longer constitute a group which beneficially owns more than 50% of the issued and outstanding shares entitled to vote, directors may be removed with or without cause by the affirmative vote of a majority of the issued and outstanding shares entitled to vote. On and after such date, a director may be removed only for cause by the affirmative vote of a majority of the issued and outstanding shares entitled to vote. Any vacancy created by the removal of a director at a special general meeting may be filled at that meeting by the election of another director in his or her place or, in the absence of any such election, by the board of directors. Any other vacancy, including newly created directorships, may be filled by our board of directors.

Proceedings of Board of Directors

        Our bye-laws provide that our business shall be managed by or under the direction of our board of directors. Our board of directors may act by the affirmative vote of a majority of the directors present at a meeting at which a quorum is present. A majority of the total number of directors then in office shall constitute a quorum; provided that, in the case of special meetings, for as long as the Investors collectively beneficially own more than 25% of the issued and outstanding common shares, if at least one director designated by each Investor then entitled to designate a director is not present at a special meeting, such meeting will be postponed for at least 24 hours, after which it may be held as long as a quorum consisting of a majority of the total number of directors is present. The board may also act by unanimous written consent.

Duties of Directors

        Under Bermuda common law, members of a board of directors owe a fiduciary duty to the company to act in good faith in their dealings with or on behalf of the company, and to exercise their powers and fulfill the duties of their office honestly. This duty has the following essential elements: (1) a duty to act in good faith in the best interests of the company; (2) a duty not to make a personal profit from opportunities that arise from the office of director; (3) a duty to avoid conflicts of interest; and (4) a duty to exercise powers for the purpose for which such powers were intended. The Bermuda Companies Act also imposes a duty on directors of a Bermuda company, to act honestly and in good

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faith, with a view to the best interests of the company, and to exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. In addition, the Bermuda Companies Act imposes various duties on directors with respect to certain matters of management and administration of the company.

        The Bermuda Companies Act provides that in any proceedings for negligence, default, breach of duty or breach of trust against any director, if it appears to a court that such officer is or may be liable in respect of the negligence, default, breach of duty or breach of trust, but that he has acted honestly and reasonably, and that, having regard to all the circumstances of the case, including those connected with his appointment, he ought fairly to be excused for the negligence, default, breach of duty or breach of trust, that court may relieve him, either wholly or partly, from any liability on such terms as the court may think fit. This provision has been interpreted to apply only to actions brought by or on behalf of the company against the directors.

        Under Delaware law, the business and affairs of a corporation are managed by or under the direction of its board of directors. In exercising their powers, directors are charged with a duty of care and a duty of loyalty. The duty of care requires that directors act in an informed and deliberate manner and to inform themselves, prior to making a business decision, of all relevant material information reasonably available to them. The duty of care also requires that directors exercise care in overseeing the conduct of corporate employees. The duty of loyalty is the duty to act in good faith, not out of self-interest, and in a manner which the director reasonably believes to be in the best interests of the shareholders. A party challenging the propriety of a decision of a board of directors bears the burden of rebutting the presumptions afforded to directors by the "business judgment rule." If the presumption is not rebutted, the business judgment rule attaches to protect the directors and their decisions. Where, however, the presumption is rebutted, the directors bear the burden of demonstrating the fairness of the relevant transaction. Notwithstanding the foregoing, Delaware courts subject directors' conduct to enhanced scrutiny in respect of defensive actions taken in response to a threat to corporate control and approval of a transaction resulting in a sale of control of the corporation.

Interested Directors

        Under Bermuda law and our bye-laws, as long as a director discloses a direct or indirect interest in any contract or arrangement with us as required by law, such director is entitled to vote in respect of any such contract or arrangement in which he or she is interested, unless disqualified from doing so by the chairman of the meeting, and such a contract or arrangement will not be voidable solely as a result of the interested director's participation in its approval. In addition, the director will not be liable to us for any profit realized from the transaction. In contrast, under Delaware law, such a contract or arrangement is voidable unless it is approved by a majority of disinterested directors or by a vote of shareholders, in each case if the material facts as to the interested director's relationship or interests are disclosed or are known to the disinterested directors or shareholders, or such contract or arrangement is fair to the corporation as of the time it is approved or ratified. Additionally, such interested director could be held liable for a transaction in which such director derived an improper personal benefit.

Indemnification of Directors and Officers

        Bermuda law provides generally that a Bermuda company may indemnify its directors and officers against any loss arising from or liability which by virtue of any rule of law would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust except in cases where such liability arises from fraud or dishonesty of which such director or officer may be guilty in relation to the company.

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        Our bye-laws provide that we shall indemnify our officers and directors in respect of their actions and omissions, except in respect of their fraud or dishonesty, and that we shall advance funds to our officers and directors for expenses incurred in their defense upon receipt of an undertaking to repay the funds if any allegation of fraud or dishonesty is proved. Our bye-laws provide that the company and the shareholders waive all claims or rights of action that they might have, individually or in right of the company, against any of the company's directors or officers for any act or failure to act in the performance of such director's or officer's duties, except in respect of any fraud or dishonesty.

Meetings of Shareholders

        Under Bermuda law, a company is required to convene at least one general meeting of shareholders each calendar year. Under Bermuda law and our bye-laws, a special general meeting of shareholders may be called by the board of directors or the chairman and must be called upon the request of shareholders holding not less than 10% of the paid-up capital of the company carrying the right to vote at general meetings of shareholders.

        Unless otherwise provided in our bye-laws, at any general meeting of shareholders the presence in person or by proxy of shareholders representing a majority of the issued and outstanding shares entitled to vote shall constitute a quorum for the transaction of business. Unless otherwise required by law or our bye-laws, shareholder action requires the affirmative vote of a majority of the issued and outstanding shares voting at a meeting at which a quorum is present.

Shareholder Proposals

        Under Bermuda law, shareholders holding at least 5% of the total voting rights of all the shareholders having at the date of the requisition a right to vote at the meeting to which the requisition relates or any group comprised of at least 100 or more shareholders may require a proposal to be submitted to an annual general meeting of shareholders. Under our bye-laws, any shareholders wishing to nominate a person for election as a director or propose business to be transacted at a meeting of shareholders must provide advance notice.

Shareholder Action by Written Consent

        Our bye-laws will provide that, until the first date on which the Investors no longer beneficially own more than 50% of the issued and outstanding shares entitled to vote, shareholders can act by written consent. Thereafter, shareholders can only act at a meeting of shareholders.

Amendment of Memorandum of Association and Bye-laws

        Our memorandum of association and bye-laws provide that our memorandum of association and bye-laws may not be rescinded, altered or amended except with the approval of our board of directors and shareholders owning a majority of the issued and outstanding shares entitled to vote.

Business Combinations

        A Bermuda company may engage in a business combination pursuant to a tender offer, amalgamation or sale of assets.

        The amalgamation of a Bermuda company with another company requires the amalgamation agreement to be approved by the company's board of directors and by its shareholders. Unless the company's bye-laws provide otherwise, the approval of 75% of the shareholders voting at a meeting is required to approve the amalgamation agreement, and the quorum for such meeting must be two persons holding or representing more than one-third of the issued shares of the company. Our bye-laws provide that an amalgamation must be approved by our board of directors and by shareholders owning

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a majority of the issued and outstanding shares entitled to vote. Shareholders who did not vote in favor of the amalgamation may apply to court for an appraisal within one month of notice of the shareholders meeting.

        Under the Bermuda Companies Act, we are not required to seek the approval of our shareholders for the sale of all or substantially all of our assets. However, our bye-laws provide that for so long as any of the Investors or their respective affiliates continue to retain the right to designate at least one director of our board of directors any sale, lease or exchange by us of all or substantially all of our assets will require the approval of either (1) our board of directors, acting by a majority (including at least one director designated by each Investor then entitled to designate a director) or (2) our board of directors and shareholders owning a majority of the outstanding shares entitled to vote.

        Under Bermuda law, where an offer is made for shares of a company and, within four months of the offer, the holders of not less than 90% of the shares not owned by the offeror, its subsidiaries or their nominees accept such offer, the offeror may by notice require the non-tendering shareholders to transfer their shares on the terms of the offer. Dissenting shareholders do not have express appraisal rights but are entitled to seek relief (within one month of the compulsory acquisition notice) from the court, which has power to make such orders as it thinks fit. Additionally, where one or more parties hold not less than 95% of the shares of a company, such parties may, pursuant to a notice given to the remaining shareholders, acquire the shares of such remaining shareholders. Dissenting shareholders have a right to apply to the court for appraisal of the value of their shares within one month of the compulsory acquisition notice. If a dissenting shareholder is successful in obtaining a higher valuation, that valuation must be paid to all shareholders being squeezed out.

Dividends and Repurchase of Shares

        Pursuant to our bye-laws, our board of directors has the authority to declare dividends and authorize the repurchase of shares subject to applicable law.

        Under Bermuda law, a company may not declare or pay a dividend if there are reasonable grounds for believing that the company is, or would after the payment be, unable to pay its liabilities as they become due or the realizable value of its assets would thereby be less than the aggregate of its liabilities and its issued share capital and its share premium accounts. Issued share capital is the aggregate par value of the company's issued and outstanding shares, and the share premium account is the aggregate amount paid for issued and outstanding shares over and above their par value. Share premium accounts may be reduced in certain limited circumstances. Under Bermuda law, a company cannot purchase its own shares if there are reasonable grounds for believing that the company is, or after the repurchase would be, unable to pay its liabilities as they become due.

Transactions with Significant Shareholders

        The Bermuda Companies Act does not have, and our bye-laws do not provide for, the equivalent of the "business combination" provisions of Section 203 of the Delaware General Corporate Law.

Corporate Opportunities

        Our bye-laws provide that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in, or in being offered an opportunity to participate in, any business opportunity that may be from time to time be presented to the Investors or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (other than us and our subsidiaries) or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such person shall be liable to us for breach of any fiduciary or other duty, as a director or controlling shareholder or otherwise, by reason of the fact that such

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person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity to us unless, in the case of any such person who is one of our directors, such person fails to present any business opportunity that is expressly offered to such person solely in his or her capacity as our director.

Shareholder Suits

        Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company's memorandum of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of the company's shareholders than that which actually approved it.

        When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply to the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company's affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company.

        Our bye-laws contain a provision by virtue of which we and our shareholders waive any claim or right of action that they have, both individually and on our behalf, against any director or officer in relation to any action or failure to take action by such director or officer, except in respect of any fraud or dishonesty of such director or officer. We have been advised by the SEC that in the opinion of the SEC, the operation of this provision as a waiver of the right to sue for violations of federal securities laws would likely be unenforceable in U.S. courts.

Access to Books and Records and Dissemination of Information

        Members of the general public have a right to inspect the public documents of a company available at the office of the Registrar of Companies in Bermuda. These documents include the company's memorandum of association and any amendments thereto. The shareholders have the additional right to inspect the bye-laws of the company, minutes of general meetings of shareholders and the company's audited financial statements. The company's audited financial statements must be presented at the annual general meeting of shareholders. The company's share register is open to inspection by shareholders and by members of the general public without charge. A company is required to maintain its share register in Bermuda but may, subject to the provisions of the Bermuda Companies Act, establish a branch register outside of Bermuda. Bermuda law does not, however, provide a general right for shareholders to inspect or obtain copies of any other corporate records.

Registrar or Transfer Agent

        A register of holders of the common shares will be maintained by Codan Services Limited in Bermuda, and a branch register will be maintained in the United States by Computershare Trust Company, N.A., who will serve as branch registrar and transfer agent.

Listing

        Our common shares have been approved for listing on the NYSE under the symbol "KOS." Settlement will take place through The Depository Trust Company in U.S. dollars. Shortly after the closing of this offering we intend to apply to list our common shares on the GSE, although there can be no assurance that this listing will be completed in a timely manner, or at all.

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SHARES ELIGIBLE FOR FUTURE SALE

        Prior to this offering, there has been no market for our common shares, and a liquid trading market for our common shares may not develop or be sustained after this offering. Future sales of substantial amounts of our common shares in the public market could adversely affect market prices prevailing from time to time. Furthermore, because only a limited number of common shares will be available for sale shortly after this offering due to existing contractual and legal restrictions on resale as described below, there may be sales of substantial amounts of our common shares in the public market after the restrictions lapse. This may adversely affect the prevailing market price and our ability to raise equity capital in the future. Our common shares have been approved for listing on the NYSE under the symbol "KOS." Shortly after the closing of this offering we intend to apply to list our common shares on the GSE, although there can be no assurance that this listing will be completed in a timely manner, or at all.

        Based on the number of common shares issued and outstanding as of December 31, 2010 after giving effect to our reorganization, upon completion of this offering, 371,176,471 common shares will be issued and outstanding, assuming no exercise of the underwriters' over-allotment option. Of the common shares to be issued and outstanding immediately after the closing of this offering, the            common shares to be sold in this offering will be freely tradable without restriction under the Securities Act unless purchased by our "affiliates," as that term is defined in Rule 144 under the Securities Act. The remaining common shares are "restricted securities" under Rule 144. Substantially all of these restricted securities will be subject to the provisions of the lock-up agreements referred to below.

        After the expiration of any lock-up period, these restricted securities may be sold in the public market only if registered or if they qualify for an exemption from registration under Rule 144 or 701 under the Securities Act, which exemptions are summarized below.

Rule 144

        In general, under Rule 144 under the Securities Act, as in effect on the date of this prospectus, a person who is not one of our affiliates at any time during the three months preceding a sale, and who has beneficially owned our common shares to be sold for at least six months, would be entitled to sell an unlimited number of our common shares, provided current public information about us is available. In addition, under Rule 144, a person who is not one of our affiliates at any time during the three months preceding a sale, and who has beneficially owned our common shares to be sold for at least one year, would be entitled to sell an unlimited number of common shares beginning one year after this offering without regard to whether current public information about us is available. Our affiliates who have beneficially owned our common shares for at least six months are entitled to sell within any three month period a number of common shares that does not exceed the greater of:

•
1% of the number of our common shares then issued and outstanding, which will equal approximately 3,711,765 common shares immediately after this offering, and

•
the average weekly trading volume in our common shares on the NYSE during the four calendar weeks preceding the date of filing of a Notice of Proposed Sale of Securities Pursuant to Rule 144 with respect to the sale.

        Sales by affiliates under Rule 144 are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us. Rule 144 also provides that affiliates relying on Rule 144 to sell our common shares that are not restricted common shares must nonetheless comply with the same restrictions applicable to restricted common shares, other than the holding period requirement.

        Upon expiration of any lock-up period and the six-month holding period, approximately 304,160,708 of our common shares will be eligible for sale under Rule 144 by our affiliates, subject to

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the above restrictions. Upon the expiration of any lock-up period and the six-month holding period, approximately 37,015,763 of our common shares will be eligible for sale by non-affiliates under Rule 144. We cannot estimate the number of common shares that our existing shareholders will elect to sell under Rule 144.

Lock-up Agreements

        In connection with this offering, we, our officers and directors, and certain shareholders have each entered into a lock-up agreement with the underwriters of this offering that restricts the sale of our common shares for a period of 180 days after the date of this prospectus, subject to extension in certain circumstances. The Representatives (as defined in "Underwriting"), on behalf of the underwriters, may, in their sole discretion, choose to release any or all of our common shares subject to these lock-up agreements at any time prior to the expiration of the lock-up period without notice. For more information, see "Underwriting."

Registration Rights

        Prior to the completion of this offering, we will become a party to the existing registration rights agreement by and among Kosmos Energy Holdings and its unitholders pursuant to which we will grant certain registration rights to the unitholders with respect to the common shares they will receive in the corporate reorganization. Pursuant to the lock-up agreements described above, certain of our shareholders have agreed not to exercise those rights during the lock-up period without the prior written consent of the Representatives of the underwriters of this offering.

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CERTAIN TAX CONSIDERATIONS

Bermuda Tax Considerations

        At the present time, there is no Bermuda income or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance tax payable by us or by our shareholders in respect of our shares. We have obtained an assurance from the Bermuda Minister of Finance under the Exempted Undertakings Tax Protection Act 1966 that, in the event that any legislation is enacted in Bermuda imposing any tax computed on profits or income, or computed on any capital asset, gain or appreciation or any tax in the nature of estate duty or inheritance tax, such tax shall not, until March 31, 2035, be applicable to us or to any of our operations or to our shares, debentures or other obligations except insofar as such tax applies to persons ordinarily resident in Bermuda or is payable by us in respect of real property owned or leased by us in Bermuda.

U.S. Federal Income Tax Considerations

        The following is a description of the material U.S. federal income tax consequences to the U.S. Holders described below of owning and disposing of our common shares, but it does not purport to be a comprehensive description of all tax considerations that may be relevant to a particular person's decision to acquire our common shares. This discussion does not discuss any state, local or foreign tax considerations. This discussion applies only to a U.S. Holder that acquires our common shares pursuant to this offering and holds them as capital assets for tax purposes. In addition, it does not describe all of the tax consequences that may be relevant in light of the U.S. Holder's particular circumstances, including alternative minimum tax consequences and tax consequences applicable to U.S. Holders subject to special rules, such as:

•
certain financial institutions;

•
dealers or traders in securities who use a mark-to-market method of tax accounting;

•
persons holding our common shares as part of a hedging transaction, straddle, wash sale, conversion transaction or integrated transaction or persons entering into a constructive sale with respect to our common shares;

•
persons whose functional currency for U.S. federal income tax purposes is not the U.S. dollar;

•
entities classified as partnerships for U.S. federal income tax purposes;

•
tax-exempt entities, including "individual retirement accounts"; or

•
persons that own or are deemed to own ten percent or more of our voting shares.

        If an entity that is classified as a partnership for U.S. federal income tax purposes holds our common shares, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the activities of the partnership. Partnerships holding our common shares and partners in such partnerships should consult their tax advisers as to the particular U.S. federal income tax consequences of holding and disposing of our common shares.

        This discussion is based on the Internal Revenue Code of 1986, as amended (the "Code"), administrative pronouncements, judicial decisions, and final, temporary and proposed Treasury regulations, all as of the date of this prospectus, any of which is subject to change, possibly with retroactive effect. U.S. Holders should consult their tax advisers concerning the U.S. federal, state, local and foreign tax consequences of owning and disposing of our common shares in their particular circumstances.

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        A "U.S. Holder" is a holder who, for U.S. federal income tax purposes, is a beneficial owner of our common shares and is:

•
a citizen or individual resident of the United States;

•
a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States, any state therein or the District of Columbia; or

•
an estate or trust the income of which is subject to U.S. federal income taxation regardless of its source.

        This discussion assumes that we are not, and will not become, a passive foreign investment company, as described below.

Taxation of Distributions

        As discussed above under "Dividend Policy," we do not currently intend to pay dividends. In the event that we do pay dividends, subject to the passive foreign investment company rules described below, distributions paid on our common shares, other than certain pro rata  distributions of common shares, will be treated as dividends to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). The amount of the dividend will be treated as foreign-source dividend income to U.S. Holders and will not be eligible for the dividends-received deduction generally available to U.S. corporations under the Code.

Sale or Other Disposition of Common Shares

        Subject to the passive foreign investment company rules described below, for U.S. federal income tax purposes, gain or loss realized on the sale or other disposition of our common shares will be capital gain or loss, and generally will be long-term capital gain or loss if the U.S. Holder held our common shares for more than one year. The amount of the gain or loss will equal the difference between the U.S. Holder's tax basis in the common shares disposed of and the amount realized on the disposition, in each case as determined in U.S. dollars. This gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes.

Passive Foreign Investment Company Rules

        Based on management estimates and projections of future operations and revenue, we do not believe we will be a passive foreign investment company (a "PFIC") for U.S. federal income tax purposes for our current taxable year and we do not expect to become one in the foreseeable future. In general, a non-U.S. corporation is a PFIC for any taxable year in which (i) 75% or more of its gross income consists of passive income (such as dividends, interest, rents and royalties) or (ii) 50% or more of the average quarterly value of its assets consists of assets that produce, or are held for the production of, passive income. Because our PFIC status is a factual determination that is made annually and depends on the composition of our income (which in turn depends on our oil revenues from production) and the composition and market value of our assets from time to time, there can be no assurance that we will not be a PFIC for any taxable year. In particular, if we do not generate a significant amount of oil revenues from production, we may be a PFIC for the current taxable year and for one or more future taxable years.

        If we were a PFIC for any taxable year during which a U.S. Holder held our common shares, gain recognized by a U.S. Holder on a sale or other disposition (including certain pledges) of our common shares would be allocated ratably over the U.S. Holder's holding period for the common shares. The amounts allocated to the taxable year of the sale or other disposition and to any year before we became a PFIC would be taxed as ordinary income. The amount allocated to each other taxable year would be subject to tax at the highest rate in effect for individuals or corporations, as appropriate, for

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that taxable year, and an interest charge would be imposed on the amount allocated to that taxable year. Similar rules would apply to the extent that any distribution received by a U.S. Holder on its common shares exceeds 125% of the average of the annual distributions on the common shares received during the preceding three years or the U.S. Holder's holding period, whichever is shorter. Certain elections may be available that would result in alternative treatments (such as mark-to-market treatment) of the common shares. U.S. Holders should consult their tax advisers to determine whether any of these elections would be available and, if so, what the consequences of the alternative treatments would be in their particular circumstances. If we were a PFIC for any year during which a U.S. Holder holds our common shares, we generally would continue to be treated on a PFIC with respect to the holder for all succeeding years during which the U.S. Holder holds our common shares, even if we subsequently ceased to meet the requirements for PFIC Status. U.S. Holders should consult their tax advisers regarding the potential availability of a "deemed sale" election that would allow them to eliminate the continuation of PFIC status under these circumstances.

        If a U.S. Holder owns our common shares during any year in which we are a PFIC, the holder may be required to file Internal Revenue Service ("IRS") Form 8621 reporting certain distributions it receives from us, as well as any disposition of all or any portion of its common shares. In addition, pursuant to a recent amendment to the Code, a U.S. Holder who owns our common shares during any year in which we are a PFIC may be required to file an annual report with the IRS with respect to us containing such information as the U.S. Treasury Department may require.

Information Reporting and Backup Withholding

        Payments of dividends and sales proceeds that are made within the United States or through certain U.S. related financial intermediaries generally are subject to information reporting, and may be subject to backup withholding, unless (i) the U.S. Holder is a corporation or other exempt recipient or (ii) in the case of backup withholding, the U.S. Holder provides a correct taxpayer identification number and certifies that it is not subject to backup withholding. The amount of any backup withholding from a payment to a U.S. Holder will be allowed as a credit against the holder's U.S. federal income tax liability and may entitle it to a refund, provided that the required information is timely furnished to the IRS.

Certain Reporting Obligations

        If a U.S. Holder acquires shares in this offering for a price in excess of $100,000, the Holder must file IRS Form 926 for the holder's taxable year in which the registration occurs. Failure by a U.S. Holder to timely comply with such reporting requirements may result in substantial penalties.

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UNDERWRITING

        Under the terms and subject to the conditions contained in an underwriting agreement dated            , 2011, we have agreed to sell to the underwriters named below, for whom Citigroup Global Markets Inc., Barclays Capital Inc. and Credit Suisse Securities (USA) LLC are acting as representatives (the "Representatives"), the following respective numbers of common shares:
 	 	 	 	 	 	
Underwriter	 	Number of
Common Shares	 	
Citigroup Global Markets Inc. 	 	 	            	 	
Barclays Capital Inc. 	 	 	            	 	
Credit Suisse Securities (USA) LLC	 	 	            	 	
BNP Paribas Securities Corp. 	 	 	            	 	
SG Americas Securities, LLC	 	 	            	 	
Credit Agricole Securities (USA) Inc. 	 	 	            	 	
Howard Weil Incorporated	 	 	            	 	
HSBC Securities (USA) Inc. 	 	 	            	 	
Jefferies & Company, Inc. 	 	 	            	 	
Natixis Bleichroeder LLC	 	 	            	 	
RBC Capital Markets, LLC	 	 	            	 	
 	Total	 	 	            	 	
 	 	 	 	
        The underwriting agreement provides that the underwriters are obligated to purchase all the common shares in the offering if any are purchased, other than those shares covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated.

        We have granted to the underwriters a 30-day option to purchase on a pro rata basis up to            additional common shares from us at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common shares.

        The underwriters propose to offer the common shares initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $    per common share. The underwriters and selling group members may allow a discount of $        per common share on sales to other broker/dealers. After the initial public offering the Representatives may change the public offering price and concession and discount to broker/dealers. The offering of the common shares by the underwriters is subject to receipt and acceptance and subject to the underwriters' right to reject any order in whole or in part.

        The following table summarizes the compensation and estimated expenses we will pay:

	 	Per Common Share	 	Total	 	
 
	 	Without
Over-allotment	 	With
Over-allotment	 	Without
Over-allotment	 	With
Over-allotment	 	
Underwriting discounts and commissions paid by us	 	$	            	 	$	            	 	$	            	 	$	            	 	
Expenses payable by us	 	$	            	 	$	            	 	$	            	 	$	            	 	
        The Representatives have informed us that the underwriters do not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the common shares being offered.

        We have agreed, subject to certain exceptions, that we will not offer, sell, issue, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the SEC a registration statement

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under the Securities Act relating to, any of our common shares or securities convertible into or exchangeable or exercisable for any of our common shares, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of the Representatives for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the "lock-up" period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the "lock-up" period, we announce that we will release earnings results during the 16-day period beginning on the last day of the "lock-up" period, then in either case the expiration of the "lock-up" will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless the Representatives waive, in writing, such an extension.

        Our officers, directors and certain shareholders have agreed, subject to certain exceptions, that they will not offer, sell, contract to sell or otherwise dispose of, directly or indirectly, any of our common shares or securities convertible into or exchangeable or exercisable for any of our common shares, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common shares, whether any of these transactions are to be settled by delivery of our common shares or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of the Representatives for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the "lock-up" period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the "lock-up" period, we announce that we will release earnings results during the 16-day period beginning on the last day of the "lock-up" period, then in either case the expiration of the "lock-up" will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless the Representatives waive, in writing, such an extension.

        We have agreed to indemnify the underwriters against liabilities under the Securities Act or contribute to payments that the underwriters may be required to make in that respect.

        The underwriters have reserved for sale at the initial public offering price up to            common shares for employees, directors and other persons associated with us who have expressed an interest in purchasing common shares in the offering. The number of common shares available for sale to the general public in the offering will be reduced to the extent these persons purchase the reserved common shares. Any reserved common shares not so purchased will be offered by the underwriters to the general public on the same terms as the other common shares.

        Our common shares have been approved for listing on the NYSE under the symbol "KOS." Shortly after the closing of this offering we intend to apply to list our common shares on the GSE, although there can be no assurance that this listing will be completed in a timely manner, or at all.

        In connection with the listing of the common shares on the NYSE, the underwriters will undertake to sell round lots of 100 shares or more to a minimum of 400 beneficial owners.

        Prior to this offering, there has been no public market for our common shares. The initial public offering price has been determined by a negotiation among us and the Representatives and will not necessarily reflect the market price of our common shares following the offering. The principal factors that were considered in determining the public offering price included:

•
the information presented in this prospectus;

•
the history of and prospects for the industry in which we will compete;

•
the ability of our management;

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•
the prospects for our future earnings;

•
the present state of our development and current financial condition;

•
the recent market prices of, and the demand for, publicly traded shares of generally comparable companies; and

•
the general condition of the securities markets at the time of this offering.

        We offer no assurances that the initial public offering price will correspond to the price at which the common shares will trade in the public market subsequent to the offering or that an active trading market for our common shares will develop and continue after the offering.

        In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act.

•
Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

•
Over-allotment involves sales by the underwriters of common shares in excess of the number of common shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of common shares over-allotted by the underwriters is not greater than the number of common shares that they may purchase in the over-allotment option. In a naked short position, the number of common shares involved is greater than the number of common shares in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing common shares in the open market.

•
Syndicate covering transactions involve purchases of the common shares in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of common shares to close out the short position, the underwriters will consider, among other things, the price of common shares available for purchase in the open market as compared to the price at which they may purchase common shares through the over-allotment option. If the underwriters sell more common shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying common shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common shares in the open market after pricing that could adversely affect investors who purchase in the offering.

•
Penalty bids permit the Representatives to reclaim a selling concession from a syndicate member when the common shares originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

        These stabilizing transactions, syndicate covering transactions and penalty bids, as well as purchases by the underwriters for their own accounts, may have the effect of raising or maintaining the market price of our common shares or preventing or retarding a decline in the market price of the common shares. As a result the price of our common shares may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

        Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory, lending and investment banking services for us and our affiliates, for which they received or will receive customary fees and expenses. Affiliates of

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Citigroup Global Markets Inc., Barclays Capital Inc. and Credit Suisse Securities (USA) LLC have extended commitments to an affiliate of Kosmos in conjunction with Kosmos' previous and new commercial debt facilities. An affiliate of Credit Suisse Securities (USA) LLC also acted as a project finance advisor for a portion of such facilities.

        The common shares are offered for sale in those jurisdictions in the United States, Europe, Asia and elsewhere where it is lawful to make such offers.

        Each of the underwriters has represented and agreed that it has not offered, sold or delivered and will not offer, sell or deliver any of the common shares directly or indirectly, or distribute this prospectus or any other offering material relating to the common shares, in or from any jurisdiction except under circumstances that will result in compliance with the applicable laws and regulations thereof and that will not impose any obligations on us except as set forth in the underwriting agreement.

        In relation to each member state of the European Economic Area which has implemented the Prospectus Directive (each, a "Relevant Member State"), including each Relevant Member State that has implemented amendments to Article 3(2) of the Prospectus Directive with regard to persons to whom an offer of securities is addressed and the denomination per unit of the offer of securities (each, an "Early Implementing Member State"), with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the "Relevant Implementation Date"), no offer of common shares will be made to the public in that Relevant Member State (other than offers (the "Permitted Public Offers") where a prospectus will be published in relation to the common shares that has been approved by the competent authority in a Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive), except that with effect from and including that Relevant Implementation Date, offers of common shares may be made to the public in that Relevant Member State at any time:

(a)
to "qualified investors" as defined in the Prospectus Directive, including:

(A)
(in the case of Relevant Member States other than Early Implementing Member States), legal entities which are authorised or regulated to operate in the financial markets or, if not so authorised or regulated, whose corporate purpose is solely to invest in securities, or any legal entity which has two or more of (i) an average of at least 250 employees during the last financial year; (ii) a total balance sheet of more than €43.0 million and (iii) an annual turnover of more than €50.0 million as shown in its last annual or consolidated accounts; or

(B)
(in the case of Early Implementing Member States), persons or entities that are described in points (1) to (4) of Section I of Annex II to Directive 2004/39/EC, and those who are treated on request as professional clients in accordance with Annex II to Directive 2004/39/EC, or recognised as eligible counterparties in accordance with Article 24 of Directive 2004/39/EC unless they have requested that they be treated as non-professional clients; or

(b)
to fewer than 100 (or, in the case of Early Implementing Member States, 150) natural or legal persons (other than "qualified investors" as defined in the Prospectus Directive) subject to obtaining the prior consent of the Subscribers; or

(c)
in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of common shares shall result in a requirement for the publication of a prospectus pursuant to Article 3 of the Prospectus Directive or of a supplement to a prospectus pursuant to Article 16 of the Prospectus Directive.

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        Each person in a Relevant Member State (other than a Relevant Member State where there is a Permitted Public Offer) who initially acquires any common shares or to whom any offer is made will be deemed to have represented, acknowledged and agreed that (A) it is a "qualified investor", and (B) in the case of any common shares acquired by it as a financial intermediary, as that term is used in Article 3(2) of the Prospectus Directive, (x) the common shares acquired by it have not been acquired on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than "qualified investors" as defined in the Prospectus Directive, or in circumstances in which the prior consent of the Representatives has been given to the offer or resale, or (y) where common shares have been acquired by it on behalf of persons in any Relevant Member State other than "qualified investors" as defined in the Prospectus Directive, the offer of those common shares to it or not treated under the Prospectus Directive as having been made to such persons.

        For the purpose of the above provisions, the expression "an offer to the public" in relation to any common shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer of any common shares to be offered so as to enable an investor to decide to purchase any common shares, as the same may be varied in the Relevant Member State by any measure implementing the Prospectus Directive in the Relevant Member State and the expression "Prospectus Directive" means Directive 2003/71 EC (including that Directive as amended, in the case of Early Implementing Member States) and includes any relevant implementing measure in each Relevant Member State.

        Each of the underwriters has severally represented, warranted and agreed as follows:

(a)
it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of section 21 of FSMA) to persons who have professional experience in matters relating to investments falling with Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 or in circumstances in which section 21 of FSMA does not apply to the company; and

(b)
it has complied with, and will comply with all applicable provisions of FSMA with respect to anything done by it in relation to the common shares in, from or otherwise involving the United Kingdom.

        Neither this prospectus nor any other offering material relating to the common shares described in this prospectus has been submitted to the clearance procedures of the Autorité des Marchés Financiers  or of the competent authority of another member state of the European Economic Area and notified to the Autorité des Marchés Financiers . The common shares have not been offered or sold and will not be offered or sold, directly or indirectly, to the public in France. Neither this prospectus nor any other offering material relating to the common shares has been or will be:

•
released, issued, distributed or caused to be released, issued or distributed to the public in France; or

•
used in connection with any offer for subscription or sale of the shares to the public in France.

        Such offers, sales and distributions will be made in France only:

•
to qualified investors (investisseurs qualifiés) and/or to a restricted circle of investors (cercle restreint d'investisseurs), in each case investing for their own account, all as defined in, and in accordance with articles L.411-2, D.411-1, D.411-2, D.734-1, D.744-1, D.754-1 and D.764-1 of the French Code monétaire et financier ;

•
to investment services providers authorized to engage in portfolio management on behalf of third parties; or

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•
in a transaction that, in accordance with article L.411-2-II-1°-or-2°-or 3° of the FrenchCode monétaire et financier  and article 211-2 of the General Regulations ( Règlement Général ) of the Autorité des Marchés Financiers , does not constitute a public offer (appel public à l'épargne ).

        The common shares may be resold directly or indirectly, only in compliance with articles L.411-1, L.411-2, L.412-1 and L.621-8 through L.621-8-3 of the French Code monétaire et financier .

        The common shares may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to "professional investors" within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a "prospectus" within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), and no advertisement, invitation or document relating to the common shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to "professional investors" within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

        This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the "SFA"), (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA. Where the common shares are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries' rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the common shares under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.

        The common shares have not been and will not be registered under the Financial Instruments and Exchange Law of Japan (the Financial Instruments and Exchange Law) and each underwriter has agreed that it will not offer or sell any common shares, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

        This prospectus as well as any other material relating to the common shares does not constitute an issue prospectus pursuant Articles 652a or 1156 of the Swiss Code of Obligations. The common shares

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will not be listed on the SWX Swiss Exchange and, therefore, the documents relating to the common shares, including, but not limited to, this prospectus, do not claim to comply with the disclosure standards of the listing rules of SWX Swiss Exchange and corresponding prospectus schemes annexed to the listing rules of the SWX Swiss Exchange. None of this offering and the common shares has been or will be approved by any Swiss regulatory authority. The common shares are being offered by way of a private placement to a limited and selected circle of investors in Switzerland without any public offering and only to investors who do not subscribe for the common shares with the intention to distribute them to the public. The investors will be individually approached by the Issuer from time to time. This prospectus as well as any other material relating to the common shares is personal and confidential to each offeree and do not constitute an offer to any other person. This prospectus may only be used by those investors to whom it has been handed out in connection with the offer described herein and may neither directly nor indirectly be distributed or made available to other persons without express consent of the Issuer. It may not be used in connection with any other offer and shall in particular not be copied and/or distributed to the public in Switzerland or from Switzerland.

        The common shares described in this prospectus may not be, are not and will not be offered, distributed, sold, transferred or delivered, directly or indirectly, to any person in the Dubai International Financial Centre other than in accordance with the Offered Securities Rules of the Dubai Financial Services Authority.

        This offering is restricted in the Kingdom of Bahrain to banks, financial institutions and professional investors and any person receiving this prospectus in the Kingdom of Bahrain and not falling within those categories is ineligible to purchase our common shares.

        This prospectus does not constitute a public offer of securities in the Kingdom of Saudi Arabia and is not intended to be a public offer. No action has been or will be taken in the Kingdom of Saudi Arabia that would permit a public offering or private placement of our common shares in the Kingdom of Saudi Arabia, or possession or distribution of any offering materials in relation thereto. Our common shares may only be offered or sold in the Kingdom of Saudi Arabia in accordance with Part 5 (Exempt Offers) of the Offers of Securities Regulations dated 20/8/1425 AH (corresponding to 4/10/2004) (the "Regulations") and, in accordance with Part 5 (Exempt Offers) Article 1716(a)(3) of the Regulations, common shares will be offered to no more than 60 offerees in the Kingdom of Saudi Arabia with each such offeree paying an amount not less than Saudi Riyals one million or its equivalent. Investors are informed that Article 19 of the Regulations places restrictions on secondary market activity with respect to our common shares. Any resale or other transfer, or attempted resale or other transfer, made other than in compliance with the above-stated restrictions shall not be recognized by us. Prospective purchasers of the common shares offered hereby should conduct their own due diligence on the accuracy of the information relating to the securities. If you do not understand the contents of this document you should consult an authorized financial adviser.

        This prospectus does not constitute an invitation or public offer of securities in the State of Qatar and should not be construed as such. This prospectus is intended only for the original recipient and must not be provided to any other person. It is not for general circulation in the State of Qatar and may not be reproduced or used for any other purpose.

        No marketing or sale of the common shares may take place in Kuwait unless the same has been duly authorized by the Kuwait Ministry of Commerce and Industry pursuant to the provisions of Law No. 31/1990 and the various ministerial regulations issued thereunder. Persons into whose possession this offering memorandum comes are required to inform themselves about and to observe such restrictions. Investors in Kuwait who approach us or obtain copies of this offering memorandum are required to keep such prospectus confidential and not to make copies thereof or distribute the same to any other person and are also required to observe the restrictions provided for in all jurisdictions with respect to offering, marketing and the sale of common shares.

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        This prospectus is not intended to constitute an offer, sale or delivery of common shares or other securities under the laws of the United Arab Emirates. The common shares have not been and will not be registered under Federal Law No. 4 of 2000 concerning the Emirates Securities and Commodities Authority and the Emirates Security and Commodity Exchange, or with the UAE Central Bank, the Dubai Financial Market, the Abu Dhabi Securities Market or with any other United Arab Emirates exchange. The offering of the common shares and interests therein have not been approved or licensed by the UAE Central Bank or any other licensing authorities in the United Arab Emirates. The common shares may not be, have not been and are not being offered, sold or publicly promoted or advertised in the United Arab Emirates, other than in compliance with laws applicable in the United Arab Emirates governing the issue, offering and sale of securities. Furthermore, the information contained in this prospectus does not constitute a public offer of securities in the United Arab Emirates in accordance with the Commercial Companies Law (Federal Law No. 8 of 1984 (as amended)) or otherwise, and is not intended to be a public offer. The information contained in this prospectus is not intended to lead to the conclusion of any contract of whatsoever nature within the territory of the United Arab Emirates. In relation to its use in the United Arab Emirates, this prospectus is strictly private and confidential, is being distributed to a limited number of investors and must not be provided to any person other than the original recipient, and may not be reproduced or used for any other purpose. The common shares may not be offered or sold directly or indirectly to the public in the United Arab Emirates.

        A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representatives may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

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LEGAL MATTERS

        The validity of the common shares offered in this prospectus is being passed upon for us by Conyers Dill & Pearman Limited, our special Bermuda counsel. Some legal matters as to U.S. law in connection with this offering are being passed upon for us by Davis Polk & Wardwell LLP, New York, New York. Shearman & Sterling LLP, New York, New York is acting as counsel for the underwriters in this offering.
EXPERTS

        The consolidated financial statements of Kosmos Energy Holdings at December 31, 2009 and 2010, and for each of the three years in the period ended December 31, 2010 and for the period April 23, 2003 (Inception) through December 31, 2010 and the schedules of Kosmos Energy Holdings as of December 31, 2009 and 2010 and for each of the three years in the period ended December 31, 2010, appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

        The information included in this prospectus regarding estimated quantities of proved reserves, the future net revenues from those reserves and their present value is based, in part, on estimates of the proved reserves and present values of proved reserves as of December 31, 2010. The reserve estimates at December 31, 2010 and December 31, 2009 are based on reports prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers. These estimates are included in this prospectus in reliance upon the authority of such firm as experts in these matters.
WHERE YOU CAN FIND ADDITIONAL INFORMATION

        We have filed with the SEC a registration statement on Form S-1, which includes exhibits, schedules and amendments, under the Securities Act with respect to this offering of our securities. Although this prospectus, which forms a part of the registration statement, contains all material information included in the registration statement, parts of the registration statement have been omitted as permitted by rules and regulations of the SEC. We refer you to the registration statement and its exhibits for further information about us, our securities and this offering. The registration statement and its exhibits, as well as any other documents that we have filed with the SEC, can be inspected and copied at the SEC's public reference room at 100 F Street, N.E., Washington, D.C. 20549-1004. The public may obtain information about the operation of the public reference room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website at http://www.sec.gov  that contains the registration statement and other reports, proxy and information statements and information that we file electronically with the SEC.

        After we have completed this offering, we will file annual, quarterly and current reports, proxy statements and other information with the SEC. We intend to make these filings available on our website once the offering is completed. You may read and copy any reports, statements or other information on file at the public reference rooms. You can also request copies of these documents, for a copying fee, by writing to the SEC, or you can review these documents on the SEC's website, as described above. In addition, we will provide electronic or paper copies of our filings free of charge upon request.

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GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS

        Unless listed below, all defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings.
 	 	 	
"2D seismic data"	 	Two-dimensional seismic data, serving as interpretive data that allows a view of a vertical cross-section beneath a prospective area.	

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

"Aerial extent"	
 	
The area of the reservoir surface boundaries represented on a map.	

"Albian"	
 	
A geological time period ranging between 112 million and 99.6 million years ago.	

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

"Anticline"	
 	
When layers of rock are folded to create a dome, the resulting geometry is called an anticline. An anticline is thus created by way of four-way closure. Because oil is lighter than water, the oil tends to float to the top of the anticline. If an impermeable seal, such as a shale bed, caps the dome, then a pool of oil may form at the crest.	

"Appraisal well"	
 	
A well drilled after an exploratory well to gain more information on the drilled reservoirs.	

"AVO"	
 	
AVO, or amplitude versus offset, is a measure of the variation in seismic waves that occurs as the distance between the shotpoint and receiver changes during seismic testing. Variations in AVO indicate differences in lithology and fluid content in rocks above and below the reflector. The most important application of AVO is the detection of hydrocarbon reservoirs. AVO analysis refers to a technique by which geophysicists attempt to determine thickness, porosity, density, velocity, lithology and fluid content of rocks.	

"Barrel" or "bbl"	
 	
A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.	

"Barrels of oil-equivalent per acre-foot"	
 	
A unit of measurement for petroleum describing the number of recoverable equivalent barrels of oil and gas in one foot by one acre.	

"Basin"	
 	
A depression in the crust of the Earth, caused by plate tectonic activity and subsidence, in which sediments accumulate. If hydrocarbon rich source rocks occur in combination with appropriate depth and duration of burial, then a petroleum system can develop within the basin.	
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"Bbbl"	 	Billion barrels of oil.	

"Bboe"	
 	
Billion barrels of oil equivalent.	

"Bcf"	
 	
Billion cubic feet.	

"Blowout"	
 	
The uncontrolled release of formation fluids from a well. This may occur when a combination of well control safety systems fails during drilling or production operations.	

"boe"	
 	
Barrels of oil equivalent, with volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.	

"boepd"	
 	
Barrels of oil equivalent per day.	

"bopd"	
 	
Barrels of oil per day.	

"bwpd"	
 	
Barrels of water per day.	

"Campanian"	
 	
A geological time period ranging between 83.5 and 70.6 million years ago.	

"Channel"	
 	
A channel is a linear, commonly concave-based depression through which water and sediment flow and into which sediment can be deposited. The force of gravity and the movement of water in a channel creates a system of sedimentary transport known as a channel system.	

"Closure"	
 	
The vertical distance from the apex of a structure to the lowest structural contour that contains the structure. Measurements of both the areal closure and the distance from the apex to the lowest closing contour are typically incorporated in calculations of the estimated hydrocarbon content of a trap.	

"Completion"	
 	
The procedure used in finishing and equipping an oil or natural gas well for production.	

"Condensate"	
 	
Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure; however, when produced, is in the liquid phase at surface pressure and temperature.	

"Cretaceous"	
 	
A geologic period ranging from approximately 145 to 65 million years ago.	

"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.	

"Depocenter"	
 	
The area of thickest deposition in a basin.	
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"Deposition"	 	Deposition is a geological process through which rock is formed by either mechanical or chemical processes. Mechanical depositional processes include the buildup of organic material, or the physical transport and depositing of sediment on top of an exposed underlying rock layer. Deposition can also occur as a result of chemical processes involving the buildup of organic material (such as the development of plant matter into coal) or the chemical alteration of a substance to form rock (such as the development of salts through the evaporation of water).	

"Depositional system"	
 	
A depositional system is the process through which a depositional environment is created. A depositional environment is a location where accumulations of sediment have been deposited and through which stratigraphic sequences develop.	

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

"Development"	
 	
The phase in which an oil field is brought into production by drilling development wells and installing appropriate production systems.	

"Development costs"	
 	
The costs incurred in the preparation of discovered reserves for production such as those incurred in connection with the fabrication and installation of processing equipment, as well as costs related to drilling and completion activities of production and injection wells.	

"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.	

"Dip"	
 	
The angle between the strata, sequence or fault relative to a horizontal plane.	

"Distal"	
 	
Distal refers to the location of a depositional environment sited at the furthest position from the sediment source, and is generally characterized by fine-grained sediments or shales.	

"Downdip"	
 	
This term refers to a relative location down the slope of a dipping surface or formation.	

"Downthrown"	
 	
With reference to the relative movement of geologic features present on either side of the fault plane, "downthrown" describes a layer of rock that is lower than the fault plane.	
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"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 costs"	
 	
Costs incurred in identifying and examining areas that are considered to have prospects containing oil and/or natural gas. This includes, but is not limited to, the acquisition of license areas, seismic data, and exploratory wells.	

"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.	

"Facies"	
 	
A body of rock sharing similar characteristics.	

"Fairway"	
 	
The trend along which a particular geological feature is likely, such as a depositional fairway.	

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

"Farm-out"	
 	
An agreement whereby the owner of the working interest agrees to assign a portion of its interest subject to the drilling of one or more specific wells or other work by the assignee as a condition of the assignment.	

"Fault"	
 	
In geology, a fault is a planar fracture or discontinuity in a volume of rock, across which there has been displacement. Large faults within the Earth's crust result from the action of tectonic forces.	

"Fault closure"	
 	
A fault sealing surface combined with a specific reservoir shape, which together provide a trap where hydrocarbons can accumulate.	

"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.	
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"Four-way closure"	 	A structural trap where closure is present from all angles and hydrocarbons cannot effectively escape and drain to the surface. In contrast to a three-way fault closure, none of the components of closure in a four-way closure is formed by the presence of a fault. See "—Closure"	

"FPSO"	
 	
Floating Production, Storage and Offloading vessel.	

"Frac-packs"	
 	
Refers to the process where fluids and sand are injected into hydrocarbon bearing rock at high-pressure in order to fracture the rock and prop open the newly created fissures. This process, combined with specialized downhole equipment, increases well productivity and provides a measure of protection against formation sand production.	

"Gas-oil ratio"	
 	
The ratio of the volume of natural gas that comes out of solution from a volume of oil at standard atmospheric conditions (expressed in standard cubic feet per barrel of oil).	

"Gathering system"	
 	
Pipelines and other facilities that transport oil and gas from wells to a central delivery point for sale or delivery into a transmission line or mainline.	

"Gross acre"	
 	
An acre in which a working interest is owned. The number of gross acres is the total number of acres in which an interest is owned.	

"Horizon"	
 	
A term used to denote a surface in or of rock, or a distinctive layer of rock that might be represented by a reflection in seismic data.	

"Hydrocarbon"	
 	
A hydrocarbon is an organic compound made of two elements, carbon and hydrogen. Various carbon and hydrogen atomic structures can form oil and natural gas.	

"Interference test"	
 	
A test of pressure interrelationships (interference) between wells within the same formation. This test is used to determine, for example, oil in place, inter-well communication and various reservoir properties.	

"License"	
 	
A legal instrument executed by the host government or agency thereof granting the right to explore, drill, develop and produce oil and natural gas. An oil and natural gas license embodies the legal rights, privileges and duties pertaining to the licensor and licensee.	

"Milidarcy"	
 	
One thousandth of a "darcy," which is a unit of permeability.	

"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.	
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"Mud"	 	Mud is a term that is generally synonymous with drilling fluid and that encompasses most fluids used in hydrocarbon drilling operations, especially fluids that contain significant amounts of suspended solids, emulsified water or oil.	

"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.	

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

"OPEC"	
 	
Organization of the Petroleum Exporting Countries.	

"Permeability"	
 	
A combination of rock and fluid properties representing the fluid's ability to flow through a network of interconnected pores within a reservoir. Expressed in either Darcys (D) or  1 / 1000  of a Darcy termed millidarcies (mD). A higher permeability value represents the reservoir's natural potential to produce fluids and vice versa.	

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

"Plan of development"	
 	
A written document outlining the steps to be undertaken to develop a field.	

"Play"	
 	
A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects.	

"Porosity"	
 	
The ratio of pore volume or void space to the gross rock volume. Represents the amount of storage space within a reservoir able to accommodate fluids and generally expressed as a percentage or as a fraction of unity. A higher porosity value equates to more hydrocarbons that can be stored within a given volume of rock and vice versa. Values can range from 0% to a theoretical maximum of 47.6%.	

"Pressure communication"	
 	
Formation pressure measurements can be obtained within a well and compared to offset or surrounding wells that have had similar measurements previously captured. When these pressures are plotted versus depth, analysis can be performed which may suggest the wells have penetrated the same reservoir. When this occurs, the wells are said to be in "pressure communication". This information is critical in ensuring injection wells are appropriately placed to support and efficiently sweep hydrocarbons to the producing wells.	
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Table of Contents
 	 	 	
"Production costs"	 	The production or operational costs incurred while extracting and producing, storing, and transporting oil and/or natural gas. Typical of these costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes, and insurance.	

"Producing well"	
 	
A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.	

"Prospect(s)"	
 	
A potential trap which 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 which geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).	

"Proved developed reserves"	
 	
Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.	

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

"Reserves"	
 	
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, a revenue interest in the production, installed means of delivering oil, gas, or related substances to market, and all permits and financing required to implement the project.	

"Reservoir"	
 	
A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.	
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Table of Contents
 	 	 	
"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.	

"Seal"	
 	
A relatively impermeable rock, commonly shale, anhydrite or salt, that forms a barrier or cap above and around reservoir rock such that fluids cannot migrate beyond the reservoir. A seal is a critical component of a complete petroleum system.	

"Seismic data"	
 	
Seismic data is used by scientists to interpret the composition, fluid content, extent and geometry of rocks in the subsurface. Seismic data is acquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflected beneath the earth's surface and a receiver is used to collect and record these reflections.	

"Sequence"	
 	
A sequence refers to a series of geological events, processes, or rocks, arranged in chronological order.	

"Shale"	
 	
A fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.	

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

"Shut in"	
 	
To close the valves on a well so that it stops producing.	

"Sidetrack"	
 	
To drill a secondary wellbore within the original wellbore away from an original wellbore.	

"Source rock"	
 	
This term refers to rocks with sufficient organic material from which hydrocarbons have been generated or are capable of being generated. They typically have a deeper, warmer, and higher pressure than reservoir rocks which allows the expelled hydrocarbons to accumulate.	

"Spud"	
 	
The very beginning of drilling operations of a new well, occurring when the drilling bit penetrates the surface utilizing a drilling rig capable of drilling the well to the authorized total depth.	

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

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

"Stratigraphy"	
 	
The study of the composition, relative ages and distribution of layers of sedimentary rock.	
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Table of Contents
 	 	 	
"Stratigraphic trap"	 	A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.	

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

"Tertiary"	
 	
A geological time period ranging between 65 million and 2.6 million years ago.	

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

"Thrust Fault"	
 	
A thrust fault occurs where rocks of lower (older) stratigraphic position are pushed up and over higher (younger) strata. Thrust faults are the result of compression forces.	

"Thrust Sheet"	
 	
Thrust sheet is the body of rock within a thrust fault.	

"Total depth"	
 	
The maximum depth reached by a well.	

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

"Transform fault"	
 	
A transform fault or transform boundary is a type of fault at the margin of a tectonic plate. Transform faults occur where tectonic plates slide past or move apart from each other. Most transform faults are found on the ocean floor, however, the best-known transform faults are found on land.	

"Turbidite"	
 	
A turbidite is a sediment transported and deposited by a turbidity current. A turbidity current is an underwater current of rapidly moving sand-laden water moving down a slope, comparable to an underwater avalanche.	

"Turbidite fan"	
 	
A turbidite fan is a fan shaped deposit of sand deposted on the seabed by a turbidity current. The architecture of these fans is constructed through many repeated depositional events or cycles. See "—Turbidite."	

"Turbidite fan lobe"	
 	
A turbidite fan lobe is one depositional cycle within the overall larger turbidite fan. These turbidite fan lobes often consist of excellent reservoir rock.	

"Turonian"	
 	
A geological time period ranging between 93.5 million and 89.3 million years ago.	

"Updip"	
 	
This term refers to a relative location up the slope of a dipping surface or formation.	
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Table of Contents
 	 	 	
"Undeveloped acreage"	 	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.	

"Unitized production"	
 	
Pooled production from wells or a reservoir. The proceeds of this pooled production are distributed to the participants according to the agreed-upon formula.	

"West African Transform Margin"	
 	
A portion of the West African continental margin extending approximately 2,400 miles (1,500 kilometers) along the coast from eastern Ghana, across the Ivory Coast and Liberia, and to the west of Sierra Leone. The area is associated with a series of transform faults.	

"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 revenues with other working interest owners, based on the percentage of working interest owned.	

"Workover"	
 	
Operations in a producing well to restore or increase production.	
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INDEX TO FINANCIAL STATEMENTS

 
	 	Page	 	
Kosmos Energy Holdings	 	 	 	 	
Audited Consolidated Financial Statements (a Development Stage Entity)	 	 	 	 	
 	Report of Independent Registered Public Accounting Firm	 	 	
F-2	 	
 	Consolidated Balance Sheets as of December 31, 2009 and 2010	 	 	
F-3	 	
 	Consolidated Statements of Operations for the years ended December 31, 2008, 2009 and 2010 and for the Period April 23, 2003 (Inception) through December 31, 2010	 	 	
F-4	 	
 	Consolidated Statements of Unit Holdings Equity for the Period April 23, 2003 (Inception) through December 31, 2003 and for each of the seven years in the period ended December 31, 2010	 	 	
F-5	 	
 	Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2009 and 2010 and for the Period April 23, 2003 (Inception) through December 31, 2010	 	 	
F-6	 	
 	Consolidated Statements of Comprehensive Loss for the years ended December 31, 2008, 2009 and 2010 and for the Period April 23, 2003 (Inception) through December 31, 2010	 	 	
F-7	 	
 	Notes to Consolidated Financial Statements	 	 	
F-8	 	
 	Supplementary Oil and Gas Data (Unaudited)	 	 	
F-39	 	
F-1

Table of Contents
Report of Independent Registered Public Accounting Firm

The Unit Holders
Kosmos Energy Holdings

        We have audited the accompanying consolidated balance sheets of Kosmos Energy Holdings (a development stage entity) (the "Company") as of December 31, 2009 and 2010, and the related consolidated statements of operations, unit holdings equity, cash flows and comprehensive loss for each of the three years in the period ended December 31, 2010, and for the period April 23, 2003 (Inception) through December 31, 2010. Our audits also included the financial statement schedules included at Item 16(b). These consolidated financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and schedules based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Kosmos Energy Holdings at December 31, 2009 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, and for the period April 23, 2003 (Inception) through December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the consolidated financial statements taken as a whole, presents fairly, in all material respects, the financial information set forth therein.
 	 	 	
 	 	/s/ Ernst & Young LLP	
Dallas, Texas
March 2, 2011

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Balance Sheets

	 	December 31	 	Pro Forma as
Adjusted as of
December 31
2010	 	 	
 
	 	2009	 	2010	 	 	 	 	

	 	 
	 	(Unaudited)

	 	(In thousands, except share
and per share data)
	 	 	
Assets	 	 	 	 	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	139,505	 	$	100,415	 	$	100,415	 	 	
 	Restricted cash	 	 	—	 	 	80,000	 	 	80,000	 	 	
 	Receivables:	 	 	 	 	 	 	 	 	 	 	 	
 	 	Joint interest billings	 	 	42,616	 	 	124,449	 	 	124,449	 	 	
 	 	Notes	 	 	52,318	 	 	113,889	 	 	113,889	 	 	
 	 	Other	 	 	1,693	 	 	615	 	 	615	 	 	
 	Inventories	 	 	19,621	 	 	37,674	 	 	37,674	 	 	
 	Prepaid expenses and other	 	 	848	 	 	13,278	 	 	13,278	 	 	
 	Current deferred tax assets	 	 	127	 	 	89,600	 	 	89,600	 	 	
 	 	 	 	 	 	 	 	 	
Total current assets	 	 	256,728	 	 	559,920	 	 	559,920	 	 	
Property and equipment:	 	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas properties, net of accumulated depletion of zero and $6,430, respectively	 	 	595,091	 	 	989,869	 	 	989,869	 	 	
 	Other property, net of accumulated depreciation of $3,193 and $5,343, respectively	 	 	8,916	 	 	8,131	 	 	8,131	 	 	
 	 	 	 	 	 	 	 	 	
Property and equipment—net	 	 	604,007	 	 	998,000	 	 	998,000	 	 	
Other assets:	 	 	 	 	 	 	 	 	 	 	 	
 	Restricted cash	 	 	30,000	 	 	32,000	 	 	32,000	 	 	
 	Long-term receivables—joint interest billings, net of allowance	 	 	41,593	 	 	21,897	 	 	21,897	 	 	
 	Debt issue costs and other assets, net of accumulated amortization of $3,266 and $32,093, respectively	 	 	89,729	 	 	78,217	 	 	78,217	 	 	
 	Derivatives	 	 	—	 	 	1,501	 	 	1,501	 	 	
 	 	 	 	 	 	 	 	 	
Total assets	 	$	1,022,057	 	$	1,691,535	 	$	1,691,535	 	 	
 	 	 	 	 	 	 	 	 	
Liabilities and unit holdings/shareholders' equity	 	 	 	 	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	 	 	 	 	
 	Current maturities of long-term debt	 	$	—	 	$	245,000	 	$	245,000	 	 	
 	Accounts payable	 	 	97,837	 	 	163,495	 	 	163,495	 	 	
 	Accrued liabilities	 	 	41,810	 	 	53,208	 	 	53,208	 	 	
 	Derivatives	 	 	—	 	 	20,354	 	 	20,354	 	 	
 	 	 	 	 	 	 	 	 	
Total current liabilities	 	 	139,647	 	 	482,057	 	 	482,057	 	 	
Long-term debt	 	 	285,000	 	 	800,000	 	 	800,000	 	 	
Long-term derivatives	 	 	—	 	 	15,104	 	 	15,104	 	 	
Long-term asset retirement obligations	 	 	—	 	 	16,752	 	 	16,752	 	 	
Leasehold improvement allowance—long-term	 	 	1,369	 	 	1,014	 	 	1,014	 	 	
Long-term deferred tax liability	 	 	653	 	 	12,513	 	 	12,513	 	 	
Convertible preferred units, 100,000,000 units authorized:	 	 	 	 	 	 	 	 	 	 	 	
 	Series A—30,000,000 units issued at December 31, 2009 and 2010	 	 	300,000	 	 	383,246	 	 	—	 	 	
 	Series B—20,000,000 units issued at December 31, 2009 and 2010	 	 	500,000	 	 	568,163	 	 	—	 	 	
 	Series C—884,956 units issued at December 31, 2009 and 2010	 	 	13,244	 	 	27,097	 	 	—	 	 	
Unit holdings/shareholders' equity:	 	 	 	 	 	 	 	 	 	 	 	
 	Common units, 100,000,000 units authorized; 18,666,667 and 19,069,662 issued at December 31, 2009 and 2010, respectively	 	 	516	 	 	516	 	 	—	 	 	
 	Common shares, $0.01 par value; 371,176,471 common shares issued and outstanding, pro forma as adjusted for the effect of our corporate reorganization and this offering	 	 	—	 	 	—	 	 	3,412	 	 	
 	Additional paid-in capital	 	 	19,108	 	 	—	 	 	975,610	 	 	
 	Deficit accumulated during development stage	 	 	(237,480	)	 	(615,515	)	 	(615,515	)	 	
 	Accumulated other comprehensive income	 	 	—	 	 	588	 	 	588	 	 	
 	 	 	 	 	 	 	 	 	
Total unit holdings/shareholders' equity	 	 	(217,856	)	 	(614,411	)	 	364,095	 	 	
 	 	 	 	 	 	 	 	 	
Total liabilities, convertible preferred units and unit holdings/shareholders' equity	 	$	1,022,057	 	$	1,691,535	 	$	1,691,535	 	 	
 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-3

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Operations

	 	 

	 	Period
April 23, 2003
(Inception)
Through
December 31
2010	 	 	
 
	 	Years Ended December 31	 	 	 	 	 	
 
	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands, except share and per share data)
	 	 	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas revenue	 	$	—	 	$	—	 	$	—	 	$	—	 	 	 	
 	Interest income	 	 	1,637	 	 	985	 	 	4,231	 	 	9,142	 	 	 	
 	Other income	 	 	5,956	 	 	9,210	 	 	5,109	 	 	26,699	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total revenues and other income	 	 	7,593	 	 	10,195	 	 	9,340	 	 	35,841	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Exploration expenses, including dry holes	 	 	15,373	 	 	22,127	 	 	73,126	 	 	166,450	 	 	 	
 	General and administrative	 	 	40,015	 	 	55,619	 	 	98,967	 	 	236,165	 	 	 	
 	Depletion, depreciation and amortization	 	 	719	 	 	1,911	 	 	2,423	 	 	6,505	 	 	 	
 	Amortization—debt issue costs	 	 	—	 	 	2,492	 	 	28,827	 	 	31,319	 	 	 	
 	Interest expense	 	 	1	 	 	6,774	 	 	59,582	 	 	66,389	 	 	 	
 	Derivatives, net	 	 	—	 	 	—	 	 	28,319	 	 	28,319	 	 	 	
 	Equity in losses of joint venture	 	 	—	 	 	—	 	 	—	 	 	16,983	 	 	 	
 	Doubtful accounts expense	 	 	—	 	 	—	 	 	39,782	 	 	39,782	 	 	 	
 	Other expenses, net	 	 	21	 	 	46	 	 	1,094	 	 	1,949	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total costs and expenses	 	 	56,129	 	 	88,969	 	 	332,120	 	 	593,861	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Loss before income taxes	 	 	(48,536	)	 	(78,774	)	 	(322,780	)	 	(558,020	)	 	 	
 	Income tax expense (benefit)	 	 	269	 	 	973	 	 	(77,108	)	 	(75,148	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(245,672	)	$	(482,872	)	 	 	
Accretion to redemption value of convertible preferred units	 	 	
(21,449	
)	 	
(51,528	
)	 	
(77,313	
)	 	
(165,262	
)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net loss attributable to common unit holders	 	$	(70,254	)	$	(131,275	)	$	(322,985	)	$	(648,134	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	(Unaudited)	 	 	 	 	 	 	
Pro forma basic and diluted net loss per common share	 	 	 	 	 	 	 	$	(0.75	)	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pro forma weighted average number of shares used to compute pro forma net loss per share, basic and diluted	 	 	 	 	 	 	 	 	325,799	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-4

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Unit Holdings Equity

	 	 

	 	Deficit
Accumulated
During
Development
Stage	 	 

 
	 	Common Units	 	 
	 	 	 	Accumulated
Other
Comprehensive
Income	 	 

	 	 	 	Additional
Paid-in
Capital	 	 	 	 	 	 

	 	Units	 	Amount	 	 	 	 	 	 	 	Total	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 
	 	(In thousands)

Inception (April 23, 2003)	 	 	—	 	$	—	 	$	—	 	$	—	 	$	—	 	$	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of Kosmos Energy, LLC units	 	 	350	 	 	350	 	 	—	 	 	—	 	 	—	 	 	350	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(1,232	)	 	—	 	 	(1,232	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2003	 	 	350	 	 	350	 	 	—	 	 	(1,232	)	 	—	 	 	(882	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Exchanged Kosmos Energy, LLC units	 	 	(350	)	 	(350	)	 	—	 	 	—	 	 	—	 	 	(350	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	for Kosmos Energy Holdings units	 	 	3,500	 	 	350	 	 	—	 	 	—	 	 	—	 	 	350	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	2,850	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(3,951	)	 	—	 	 	(3,951	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2004	 	 	6,350	 	 	350	 	 	—	 	 	(5,183	)	 	—	 	 	(4,833	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	392	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(765	)	 	(42	)	 	—	 	 	—	 	 	—	 	 	(42	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	6	 	 	—	 	 	—	 	 	6	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(17,949	)	 	—	 	 	(17,949	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2005	 	 	5,977	 	 	308	 	 	6	 	 	(23,132	)	 	—	 	 	(22,818	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	409	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(784	)	 	(42	)	 	—	 	 	(205	)	 	—	 	 	(247	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	10	 	 	—	 	 	—	 	 	10	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(24,728	)	 	—	 	 	(24,728	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2006	 	 	5,602	 	 	266	 	 	16	 	 	(48,065	)	 	—	 	 	(47,783	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	1,067	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(25	)	 	—	 	 	—	 	 	(75	)	 	—	 	 	(75	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	447	 	 	—	 	 	—	 	 	447	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(60,788	)	 	—	 	 	(60,788	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2007	 	 	6,644	 	 	266	 	 	463	 	 	(108,928	)	 	—	 	 	(108,199	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	9,595	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(67	)	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	3,671	 	 	—	 	 	—	 	 	3,671	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(48,805	)	 	—	 	 	(48,805	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2008	 	 	16,172	 	 	266	 	 	4,134	 	 	(157,733	)	 	—	 	 	(153,333	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	10	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(15	)	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of C1 units	 	 	2,500	 	 	250	 	 	11,506	 	 	—	 	 	—	 	 	11,756	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	3,468	 	 	—	 	 	—	 	 	3,468	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(79,747	)	 	—	 	 	(79,747	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2009	 	 	18,667	 	 	516	 	 	19,108	 	 	(237,480	)	 	—	 	 	(217,856	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	411	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(8	)	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	13,791	 	 	—	 	 	—	 	 	13,791	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Derivatives, net	 	 	—	 	 	—	 	 	—	 	 	—	 	 	588	 	 	588	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Accrete convertible preferred units to redemption amount	 	 	—	 	 	—	 	 	(21,143	)	 	(132,363	)	 	—	 	 	(153,506	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Accrete value of Series C Convertible Preferred Units	 	 	—	 	 	—	 	 	(11,756	)	 	—	 	 	—	 	 	(11,756	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(245,672	)	 	—	 	 	(245,672	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2010	 	 	19,070	 	$	516	 	$	—	 	$	(615,515	)	$	588	 	$	(614,411	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-5

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Cash Flows

	 	 

	 	Period
April 23, 2003
(Inception)
Through
December 31
2010	 	 	
 
	 	Years Ended December 31	 	 	 	 	 	
 
	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	
Operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(245,672	)	$	(482,872	)	 	 	
Adjustments to reconcile net loss to net cash used in operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Equity in losses of joint venture	 	 	—	 	 	—	 	 	—	 	 	16,983	 	 	 	
 	 	Depletion, depreciation and amortization	 	 	719	 	 	4,403	 	 	31,250	 	 	37,824	 	 	 	
 	 	Deferred income taxes	 	 	428	 	 	99	 	 	(77,614	)	 	(77,086	)	 	 	
 	 	Deferred rent income	 	 	—	 	 	(266	)	 	(355	)	 	(621	)	 	 	
 	 	Leasehold improvement incentive	 	 	—	 	 	1,989	 	 	—	 	 	1,989	 	 	 	
 	 	Loss on disposal of inventory and other property	 	 	—	 	 	564	 	 	1,076	 	 	1,658	 	 	 	
 	 	Unsuccessful well costs	 	 	90	 	 	74	 	 	59,401	 	 	102,792	 	 	 	
 	 	Doubtful accounts expense	 	 	—	 	 	—	 	 	39,782	 	 	39,782	 	 	 	
 	 	Derivative related activity	 	 	—	 	 	—	 	 	34,545	 	 	34,545	 	 	 	
 	 	Unit-based compensation	 	 	3,671	 	 	3,468	 	 	13,791	 	 	21,393	 	 	 	
 	 	Leasehold impairment	 	 	—	 	 	—	 	 	—	 	 	3,000	 	 	 	
 	 	Changes in assets and liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Increase in receivables	 	 	(28,701	)	 	(34,531	)	 	(100,605	)	 	(186,747	)	 	 	
 	 	 	Increase in inventories	 	 	(2,412	)	 	(14,465	)	 	(12,699	)	 	(32,541	)	 	 	
 	 	 	(Increase) decrease in prepaid expenses and other	 	 	(88	)	 	61	 	 	(12,429	)	 	(12,671	)	 	 	
 	 	 	Increase in accounts payable	 	 	7,051	 	 	80,883	 	 	65,800	 	 	163,494	 	 	 	
 	 	 	Increase in accrued liabilities	 	 	2,376	 	 	9,877	 	 	11,929	 	 	38,069	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net cash used in operating activities	 	 	(65,671	)	 	(27,591	)	 	(191,800	)	 	(331,009	)	 	 	
Investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas assets	 	 	(156,283	)	 	(411,939	)	 	(444,712	)	 	(1,068,405	)	 	 	
Other property	 	 	(3,799	)	 	(6,376	)	 	(1,452	)	 	(14,038	)	 	 	
Leasehold acquisition	 	 	—	 	 	—	 	 	—	 	 	(3,831	)	 	 	
Contribution to investment under equity method	 	 	—	 	 	—	 	 	—	 	 	(16,983	)	 	 	
Increase in cash due to acquisition	 	 	—	 	 	—	 	 	—	 	 	893	 	 	 	
Deferred organizational costs	 	 	—	 	 	—	 	 	—	 	 	(773	)	 	 	
Notes receivable	 	 	—	 	 	(52,078	)	 	(61,811	)	 	(113,889	)	 	 	
Restricted cash	 	 	3,200	 	 	(30,000	)	 	(82,000	)	 	(112,000	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net cash used in investing activities	 	 	(156,882	)	 	(500,393	)	 	(589,975	)	 	(1,329,026	)	 	 	
Financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Borrowings under long-term debt	 	 	—	 	 	285,000	 	 	760,000	 	 	1,045,000	 	 	 	
Net proceeds from issuance of units	 	 	332,656	 	 	325,344	 	 	—	 	 	824,986	 	 	 	
Debt issue costs	 	 	(1,572	)	 	(90,649	)	 	(17,315	)	 	(109,536	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by financing activities	 	 	331,084	 	 	519,695	 	 	742,685	 	 	1,760,450	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net increase (decrease) in cash and cash equivalents	 	 	108,531	 	 	(8,289	)	 	(39,090	)	 	100,415	 	 	 	
Cash and cash equivalents at beginning of period	 	 	39,263	 	 	147,794	 	 	139,505	 	 	—	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	 	$	147,794	 	$	139,505	 	$	100,415	 	$	100,415	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Supplemental cash flow information	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash paid for:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Interest	 	$	12	 	$	6,765	 	$	52,472	 	$	59,273	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Income taxes (net of refunds received)	 	$	856	 	$	(65	)	$	762	 	$	1,553	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Non cash activity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Deemed repayment and termination of notes receivable	 	$	—	 	$	—	 	$	90,197	 	$	90,197	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-6

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Comprehensive Loss

	 	 

	 	Period
April 23, 2003
(Inception)
Through
December 31
2010	 	 	
 
	 	Years Ended December 31	 	 	 	 	 	
 
	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	
Net loss	 	$	(48,085	)	$	(79,747	)	$	(245,672	)	$	(482,872	)	 	 	
Other comprehensive income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Change in fair value of cash flow hedges	 	 	—	 	 	—	 	 	(4,838	)	 	(4,838	)	 	 	
 	Loss on cash flow hedge included in operations	 	 	—	 	 	—	 	 	5,426	 	 	5,426	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Other comprehensive income	 	 	—	 	 	—	 	 	588	 	 	588	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Comprehensive loss	 	$	(48,085	)	$	(79,747	)	$	(245,084	)	$	(482,284	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-7

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements

1. Organization

        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.

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

        On August 29, 2003, contributions were made by the seven founding partners in the amount of $350 thousand, for which they received 350,000 units in Kosmos Energy, LLC. On March 9, 2004, the seven 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 13—Convertible Preferred Units.

        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.

        As of December 31, 2010, Kosmos Energy Holdings has nine members on the Board of Managers (directors). Warburg Pincus and The Blackstone Group appointed two directors each, one director is a company executive, and there are four independent directors.

        Kosmos Energy Holdings was a development stage entity as of December 31, 2010. In January 2011, we recognized our first revenue from oil production and, as a result we were no longer categorized as a development stage entity beginning in 2011.

2. Accounting Policies

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.

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.

F-8

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

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 December 31, 2009 and 2010, Kosmos had a total of $30.0 million and $112.0 million of restricted cash on hand included in current and long-term assets. In accordance with our project financing commercial debt facilities agreement, we have the following types of restricted cash on hand: (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 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 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. We have the option to invest the restricted cash in an account which is satisfactory to the facility agents. As of December 31, 2010, $80.0 million was classified as current to offset maturing debt. This restricted cash will be released after Project Completion in mid-2011. The remaining $9.0 million is included in long-term assets.

        Effective December 30, 2010, Kosmos Energy Finance provided a $23.0 million cash collateralized irrevocable standby Letter of Credit ("LOC") in respect of Kosmos Ghana's Jubilee paying interest share of Tullow Ghana Limited's LOC related to their drilling contract for the Eirik Raude. The LOC expires on September 14, 2011. As of December 31, 2010, the LOC is included in long-term assets as it relates to oil and gas properties.

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.

Inventories

        Inventories were comprised of $19.6 million and $25.2 million of materials and supplies and zero and $12.5 million of hydrocarbons as of December 31, 2009 and 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. Write downs of zero and $1.1 million as of December 31, 2009 and 2010, respectively, for materials and supplies were recorded as reductions to the carrying values for materials and supplies inventories in the Company's consolidated balance sheets and as other expenses, net in the accompanying consolidated statement of operations.

        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.

F-9

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

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 years ended December 31, 2008, 2009 and 2010, Kosmos recognized exploration expense of $15.4 million, $22.1 million and $73.1 million, respectively.

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.

        As of December 31, 2010, depletion costs of $6.4 million are recorded in inventory on the consolidated balance sheets. Oil production commenced on November 28, 2010 and we received revenues from oil production in early 2011 at which time depletion costs were transferred to the consolidated statements of operations.

        Depreciation and amortization of other property is computed using the straight-line method over estimated useful lives ranging from 3 to 7 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. Amortization of other assets is computed using the straight-line method over an estimated useful life of five years.

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.

F-10

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

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 as if that obligation were incurred on that 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 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.

Investments in Nonconsolidated Companies

        The Company uses the equity method of accounting for long-term investments for which it owns between 20% and 50% of the investee's outstanding voting shares or has the ability to exercise significant influence over operating and financial policies of the investee. The equity method requires periodic adjustments to the investment account to recognize our proportionate share in the investee's results, reduced by receipt of the investee's dividends.

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. VIE's 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. Kosmos Energy Finance, a wholly-owned subsidiary whose ultimate parent is Kosmos Energy Holdings, meets the definition of a VIE and the Company is the primary beneficiary. As a result, Kosmos Energy Finance is consolidated in these financial statements. Kosmos Energy Finance's assets and liabilities are shown separately on the face of the consolidated balance sheets 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. Included in cash and cash equivalents is $58.0 million related to Kosmos Energy Finance.

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

F-11

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

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.

        During 2006, Kosmos recognized an impairment of $3.0 million for the Morocco Boujdour Reconnaissance license which expired in April 2006.

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 and effective June 1, 2010 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 11—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 which geological and engineering data demonstrate with reasonable certainty to be 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 SEC and the FASB. The accuracy of these reserve estimates is a function of:

•
the engineering and geological interpretation of available data;

•
estimates regarding 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

F-12

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

received revenues from oil production in early 2011. As of December 31, 2010, no revenues have been recognized in our financial statements.

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.

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 using 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. See Note 18—Profit Units.

Employees

        The majority of our full-time employees were leased through TriNet Acquisition Corp. 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

        In June 2009, the FASB issued Statement of Financial Accounting Standards ("SFAS") No. 166, "Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140." This Statement was codified into FASB ASC 860—Transfers and Servicing. This Statement removes the concept of qualifying special purpose entity ("SPE") and the exception for qualifying SPEs from the consolidation guidance. Additionally, the Statement clarifies the requirements for financial asset transfers eligible for sale accounting. The Company adopted this Statement on its effective date, January 1, 2010, and it did not have a material impact on the Company's financial position or results of operations.

F-13

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

        Also in June 2009, the FASB issued SFAS No. 167, "Amendments to FASB Interpretation No. 46(R)," to address the effects of the elimination of the qualifying SPE concept in SFAS No. 166, and other concerns about the application of key provisions of consolidation guidance for VIEs. This Statement was codified into FASB ASC 810—Consolidation. More specifically, SFAS No. 167 requires a qualitative rather than a quantitative approach to determine the primary beneficiary of a VIE, it amends certain guidance pertaining to the determination of the primary beneficiary when related parities are involved, and it amends certain guidance for determining whether an entity is a VIE. Additionally, this Statement requires continuous assessments of whether an enterprise is the primary beneficiary of a VIE. The Company adopted this Statement on its effective date, January 1, 2010, and it did not have a material impact on the Company's financial position or results of operations.

        In January 2010, the FASB issued Accounting Standards Update ("ASU") No. 2010-03—Oil and Gas Reserve Estimation and Disclosures. This ASU amends the FASB's ASC Topic 932—Extractive Activities—Oil and Gas to align the accounting requirements of this topic with the Securities and Exchange Commission's final rule, "Modernization of the Oil and Gas Reporting Requirements" issued on December 31, 2008. In summary, the revisions in ASU No. 2010-03 modernize the disclosure rules to better align with current industry practices and expand the disclosure requirements for equity method investments so that more useful information is provided. More specifically, the main provisions include the following:

•
An expanded definition of oil and gas producing activities to include nontraditional resources such as bitumen extracted from oil sands.

•
The use of an average of the first-day-of-the-month price for the 12-month period, rather than a year-end price for determining whether reserves can be produced economically.

•
Amended definitions of key terms such as "reliable technology" and "reasonable certainty" which are used in estimating proved oil and gas reserve quantities.

•
A requirement for disclosing separate information about reserve quantities and financial statement amounts for geographical areas representing 15 percent or more of proved reserves.

•
Clarification that an entity's equity investments must be considered in determining whether it has significant oil and gas activities and a requirement to disclose equity method investments in the same level of detail as is required for consolidated investments.

        ASU No. 2010-03 is effective for annual reporting periods ended on or after December 31, 2009, and it requires (1) the effect of the adoption to be included within each of the dollar amounts and quantities disclosed, (2) qualitative and quantitative disclosure of the estimated effect of adoption on each of the dollar amounts and quantities disclosed, if significant and practical to estimate and (3) the effect of adoption on the financial statements, if significant and practical to estimate. Adoption of these requirements did not significantly impact our reported reserves or our consolidated financial statements.

        In January 2010, the FASB issued ASU No. 2010-06—Improving Disclosures and Fair Value Measurements to improve disclosure requirements and thereby increase transparency in financial reporting. We adopted the update as of December 31, 2009, and it did not have a material impact on our financial position or results of operations.

F-14

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

3. Investment and Acquisition—Pioneer Natural Resources (Nigeria) 320 Limited

        In 2005, the Company acquired, through its wholly-owned subsidiary PNR Nigeria (320) Limited (subsequently renamed Kosmos Energy Nigeria (320) Limited), a 41.17647% interest in Pioneer Natural Resources (Nigeria) 320 Limited (subsequently renamed Kosmos Energy Deepwater Nigeria Limited—"KEDNL"). Between 2005 and 2007, Kosmos made capital contributions on its investment of $17.0 million. On July 16, 2007, Pioneer Natural Resources announced its decision to divest its interest in the OPL 320 block offshore Nigeria and took a charge on its investment. Kosmos recognized an impairment in 2006 of $4.0 million of its investment in Pioneer Natural Resources (Nigeria) 320 Limited, bringing its balance to zero.

        In September 2007, the Company, per an agreement with PNR Nigeria, acquired PNR Nigeria's interest in KEDNL. Kosmos Energy NHC I, a subsidiary of Kosmos Energy Holdings, now indirectly holds 100% of the stock of KEDNL. The transaction was accounted for as a business combination. No goodwill was recorded as a result of this transaction and no consideration was paid. The fair value of the assets obtained, consisting of cash, prepaid expenses and property and equipment was $2.1 million. The fair value of the accrued liabilities assumed was $2.1 million.

        On June 29, 2009, Kosmos provided notice of its withdrawal from OPL 320 to the Nigerian government and its block partners. The effective date of the withdrawal was July 31, 2009. All of the Company's Nigerian subsidiaries were dissolved as of November 16, 2010.

4. Notes Receivable

        During the fourth quarter of 2009, Kosmos Energy Ghana HC ("Kosmos Ghana") 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 floating production, storage and offloading ("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, Tullow Ghana Limited ("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, a total of $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 made by TGL for the variation order request 025 dated January 15, 2010, to enable MODEC to pay fees in connection with its long-term financing. MODEC is required to repay TGL the earlier of September 15, 2011 or the date of the first drawdown under MODEC's long-term financing. TGL is required, based on the terms of the joint operating agreement for the Jubilee Unit, to reimburse us the amounts MODEC reimburses to TGL within ten business days of repayment by MODEC. As of December 31, 2010,

F-15

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

4. Notes Receivable (Continued)

Kosmos Ghana's share of the payments made under the Advance Payments Agreement is $113.9 million (includes accrued interest of $0.3 million) and is recorded as notes receivable.

5. 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 results of the Mahogany-2 well. The Mahogany-2 well was announced as an oil 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, Tullow Ghana Limited, 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, for the purpose of unitizing the Jubilee Field and governing 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 as of 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 their additional paying interest under both the WCTP and DT Blocks, Kosmos Ghana, Tullow Ghana Limited, 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. Tullow Ghana Limited, a subsidiary of Tullow Oil plc, is the Unit Operator, while 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 WCTP Block and 50% for the DT Block. Although the Jubilee Field is unitized, Kosmos Ghana's working interests 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.

        Pursuant to the requirements of the WCTP and DT Petroleum Agreements, Kosmos Ghana (for the WCTP Block) and Tullow Ghana Limited (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 between 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

F-16

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

5. Jubilee Field Unitization (Continued)

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.

6. 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 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, with repayment expected to be funded through EO Group's future production revenues. The related receivable of $61.7 million became due upon commencement of production. In August 2009, GNPC notified us and our applicable unit partners 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 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 of $41.6 million and $21.9 million are shown net of allowances of zero and $39.8 million as of December 31, 2009 and 2010, respectively.

7. Property and Equipment

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

	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Oil and gas properties, net:	 	 	 	 	 	 	 	
 	Proved properties	 	$	251,814	 	$	426,831	 	
 	Unproved properties	 	 	128,557	 	 	198,149	 	
 	Support equipment and facilities	 	 	214,720	 	 	371,319	 	
 	Less: accumulated depletion	 	 	—	 	 	(6,430	)	
 	 	 	 	 	 	
 	 	$	595,091	 	$	989,869	 	
 	 	 	 	 	 	
Other property, net:	 	 	 	 	 	 	 	
 	Leasehold improvements	 	$	5,041	 	$	4,978	 	
 	Computer equipment and software	 	 	3,539	 	 	4,947	 	
 	Office equipment and furniture	 	 	3,529	 	 	3,549	 	
 	Less: accumulated depreciation	 	 	(3,193	)	 	(5,343	)	
 	 	 	 	 	 	
 	 	$	8,916	 	$	8,131	 	
 	 	 	 	 	 	
        The Company recorded $0.6 million, $1.9 million and $2.2 million of depreciation expense for the years ended December 31, 2008, 2009 and 2010, respectively.

F-17

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

8. 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.

        The following table reflects the Company's capitalized exploratory well activities during the years ended December 31, 2008, 2009 and 2010, respectively. The table excludes costs related to exploratory dry holes of $56.0 million which were incurred and subsequently expensed in 2010.

	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Beginning balance	 	$	11,938	 	$	71,883	 	$	114,307	 	
Additions to capitalized exploratory well costs pending the determination of proved reserves	 	 	59,945	 	 	508,197	 	 	55,706	 	
Reclassification due to determination of proved reserves	 	 	—	 	 	(465,773	)	 	—	 	
Capitalized exploratory well costs charged to expense	 	 	—	 	 	—	 	 	(2,502	)	
 	 	 	 	 	 	 	 	
Ending balance	 	$	71,883	 	$	114,307	 	$	167,511	 	
 	 	 	 	 	 	 	 	
        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 a period greater than one year since the completion of drilling:

	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands, except well counts)
	 	
Exploratory well costs capitalized for a period of one year or less	 	$	59,945	 	$	91,909	 	$	49,022	 	
Exploratory well costs capitalized for a period greater than one year	 	 	11,938	 	 	22,398	 	 	118,489	 	
 	 	 	 	 	 	 	 	
Ending balance	 	$	71,883	 	$	114,307	 	$	167,511	 	
 	 	 	 	 	 	 	 	
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	 	 	2	 	 	1	 	 	6	 	
 	 	 	 	 	 	 	 	
        As of December 31, 2010, the exploratory well costs capitalized in excess of one year since the completion of drilling relate to the Odum-1, Odum-2, Mahogany-3, Mahogany-4 and Mahogany Deep-2 exploration wells in the WCTP Block and Tweneboa-1 well in the DT Block. All costs incurred are approximately one to two years old.

        Odum Discovery—Results of the Odum-2 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 as 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.

F-18

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

8. Suspended Well Costs (Continued)

        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 is currently being prepared for submission to Ghana's Ministry of Energy in early 2011.

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

9. Accounts Payable and Accrued Liabilities

        At December 31, 2009 and 2010, $97.8 million and $163.5 million were recorded for invoices received but not paid in 2009 and 2010, respectively. Accrued liabilities were $41.8 million and $53.2 million at December 31, 2009 and 2010, respectively. Accrued liabilities consist of the following:

	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Accrued liabilities:	 	 	 	 	 	 	 	
 	Accrued exploration and development	 	$	34,723	 	$	26,843	 	
 	Accrued general and administrative expenses	 	 	2,236	 	 	23,393	 	
 	Accrued debt issue costs	 	 	3,232	 	 	—	 	
 	Taxes other than income	 	 	979	 	 	1,936	 	
 	Accrued interest	 	 	—	 	 	655	 	
 	Income taxes	 	 	640	 	 	381	 	
 	 	 	 	 	 	
 	 	$	41,810	 	$	53,208	 	
 	 	 	 	 	 	
10. Commercial Debt Facilities

        On July 13, 2009, Kosmos signed definitive documentation for $750 million project finance commercial debt facilities. The security package for the facilities included, among other things and subject to necessary consents, a pledge collateralization over the shares of the Company's subsidiaries, Kosmos Energy Development and Kosmos Ghana, and an assignment by way of security of their interest in the WCTP and DT Petroleum Agreements. The facilities were amended effective October 29, 2009, by revising the conditions precedent to initial utilization by putting in place an alternative security package that included a charge over the shares of additional subsidiaries of the Company. The Company completed an internal reorganization that included the interposition of a new subsidiary, Kosmos Energy Operating ("KEO"), between Kosmos Energy Holdings and the following subsidiaries: Kosmos Energy International, Kosmos Energy Development, Kosmos Ghana, Kosmos Energy Finance, Kosmos Energy Offshore Morocco HC, Kosmos Energy Cameroon HC, Longhorn Offshore Drilling Ltd. and Kosmos Energy Cote d'Ivoire. Kosmos Energy Holdings granted a charge over the shares of KEO to the lenders in order to secure the facilities. The facilities were further amended on December 24, 2009, increasing the total commercial debt facilities for up to $900.0 million,

F-19

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

10. Commercial Debt Facilities (Continued)

($825.0 million was committed as of December 31, 2009) and adding a new lender as a party to the facilities agreement. On March 31, 2010, Kosmos delivered a request notice to the senior facility agent to increase the commitment under the commercial debt facilities for the remaining $75.0 million by adding a new lender. The conditions set forth in the commercial debt facilities were met and both the increase and new lender were approved as of April 27, 2010. Effective August 23, 2010, the Company signed definitive documentation to increase the facilities by $350.0 million, raising the total amount of its debt commitments to $1.25 billion.

        The revised $1.25 billion of commercial debt facilities are divided among a senior facility of $950.0 million, a junior facility of $200.0 million and additional facilities of $100.0 million ($50.0 million senior facility and $50.0 million junior facility) from the International Finance Corporation ("IFC"), a member of the World Bank Group. The senior and junior facilities of $950.0 million and $200.0 million include a syndicate of institutions led by Standard Chartered Bank, the Global Coordinator for the facilities. Standard Chartered Bank is also the Co-Technical and Modeling Bank and Senior Facility Agent, BNP Paribas SA is the Security Trustee, Junior Facility Agent, and has the role of Hedging Coordinator Bank, and Société Générale is the Lead Technical and Modeling Bank. The senior facilities have a final maturity date of December 15, 2015, while the junior facilities have a final maturity date of June 15, 2016.

        The amount of funds available to be borrowed under the senior facilities, the Borrowing Base Amount, is determined twice a year on June 15 and December 15 of each year as part of the Forecast that is prepared and agreed by the Company 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 December 31, 2010, borrowings against the commercial debt facilities totaled $1.05 billion, of which $970.0 million is senior debt and $75.0 million is junior debt. As of December 31, 2010, the availability under our commercial debt facilities was $203.0 million, with $205.0 million of committed undrawn capacity provided for in such facilities (with the difference being the result of borrowing base constraints). See Note 21—Subsequent Events.

        The interest is the aggregate of the applicable margin (5% to 6% on the senior facilities and 9% to 9.5% on the junior facilities); LIBOR; and mandatory cost (if any, as defined in the relevant documentation). 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). The Company pays commitment fees on the undrawn and uncancelled portion of the total commitments. Commitment fees for the senior and junior lenders are equal to 50% per annum of the then applicable respective margin. Interest expense was $2.0 million and $39.0 million (net of capitalized interest of $0.6 million and $9.8 million) and commitment fees were $4.8 million and $8.2 million for the years ended December 31, 2009 and 2010, respectively.

        Certain facilities contain certain financial covenants, which include:

•
Before project completion, maintenance of the funding sufficiency ratio, not less than 1:1x; and;

•
After project completion, maintenance of:

          (i)  the debt service coverage ratio, not less than 1.2x;

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

10. Commercial Debt Facilities (Continued)

         (ii)  the field life cover ratio, not less than 1.35x; and

        (iii)  the loan life cover ratio, not less than 1.15x

in each case, as calculated on the basis of all available information. The "funding sufficiency ratio" is broadly defined, for each applicable calculation period, as the ratio of (x) available funding through the assumed completion date, being the sum of the total available commitments under our commercial debt facilities, the balance of certain accounts securing our commercial debt facilities and the amount of any additional indebtedness permitted under our commercial debt facilities, to (y) total costs through the assumed completion date, being the forecasted project costs, interests and principal payments on, and costs in connection with, our commercial debt facilities, hedging payments in connection with required hedges under our commercial debt facilities, taxes payable and any other costs, fees and expenses incurred in connection with carrying out the Jubilee Field Phase 1 development. The "debt service coverage ratio" is broadly defined, for each applicable forecast period, as the ratio of (x) net cash flow for that period, to (y) aggregate costs of financing the project under our commercial debt facilities, including interest, principal, fees and expenses payable for such period. 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 Phase I development and funded under our commercial debt facilities, to (y) the aggregate loan amounts outstanding under the senior 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 maturity date of the commercial debt facilities plus the net present value of capital expenditures incurred in relation to the Jubilee Phase I development and funded under our commercial debt facilities, to (y) the aggregate loan amounts outstanding under the senior facility.

        Kosmos has the right to cancel all the undrawn commitments under the facilities if such cancellation is simultaneous with the full repayment of all outstanding loans made under the facilities. The amount of funds available to be borrowed under the senior facilities, also known as the borrowing base amount, is determined on June 15 and December 15 of each year as part of a forecast that is prepared and agreed 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.

        If an event of default exists under the facilities, the lenders will be able to accelerate the maturity and exercise other rights and remedies.

        Our payment obligations under the commercial debt facilities are secured by a charge over the shares of subsidiaries' of the Company as described above. The commercial debt facilities contain limitations on our activities, which among other things include incurring additional indebtedness; making distributions or payment of dividends or certain other restricted payments or investments; making certain payments on indebtedness; selling or otherwise disposing of assets; and merger, consolidation or sales of substantially all of our assets. At December 31, 2010, the Company's subsidiaries' had $119.8 million in cash and cash equivalents and restricted cash that could not be used for cash dividend payments, loans or advances to Kosmos Energy Holdings.

F-21

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

10. Commercial Debt Facilities (Continued)

        At December 31, 2010, the scheduled maturities of debt during the next five years and thereafter are as follows:

	 	Payments Due By Year	 	
 
	 	2011	 	2012	 	2013	 	2014	 	2015	 	Thereafter	 	
 
	 	(In thousands)
	 	
Commercial debt facilities(1)	 	$	245,000	 	$	250,000	 	$	200,000	 	$	175,000	 	$	100,000	 	$	75,000	 	

(1)
Pursuant to the terms in the commercial debt facilities, when any junior debt is outstanding, repayments may be required to be made under the agreement, whereby 75% of any funds remaining on any repayment date, after required payments are made, will be applied to prepay the junior facilities and the remaining 25% will be applied to prepay the senior facilities. The table of scheduled maturities assumes the outstanding borrowings under the junior facilities will be repaid on June 15, 2016. If repayments are required as noted above, amortization of the junior facilities will occur through such repayments.

        Debt issue costs associated with the facilities were $92.2 million and $109.5 million at December 31, 2009 and 2010, respectively. The Company amortizes debt issue costs using the straight-line method over the life of the facilities. Amortization expense of zero, $2.5 million and $28.8 million were recorded for the years ended December 31, 2008, 2009 and 2010, respectively.

11. 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. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss ("AOCI(L)") within equity until such time as the hedged item is recognized in earnings. In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically.

        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 will recognize, from that date forward, all changes in the fair values of its interest rate swap derivative contracts as gains or losses in the results of the period in which they occur.

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

11. Derivative Financial Instruments (Continued)

        The effective portions of the discontinued hedges as of May 31, 2010 are included in 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.

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) and have been entered into as required under the terms of our commercial debt facilities.

        The Company manages and controls 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 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. All of our commodity derivative contracts are with parties that are lenders under our commercial debt facilities. 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 December 31, 2010, the net liability of commodity derivative contracts was reduced by $2.7 million for estimated nonperformance risk.

        The following table sets forth as of December 31, 2010 the volumes in barrels ("bbl") 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, the Company 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 under its commercial debt facilities to a weighted average fixed rate. The following table

F-23

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

11. Derivative Financial Instruments (Continued)

summarizes our open interest rate swaps as of December 31, 2010, all of which were entered into as required under the terms of our commercial debt facilities and are with parties that are lenders under our commercial debt facilities:
 	 	 	 	 	 	 	 	 	
Term	 	Notional Amount	 	Fixed Rate	 	Floating Rate	
 
	 	(In thousands)

	
January 2011 - June 2016	 	$	161,250	 	 	2.22	%	6-month LIBOR	
January 2011 - June 2016	 	$	161,250	 	 	2.31	%	6-month LIBOR	
January 2011 - June 2014	 	$	77,500	 	 	0.98	%	6-month LIBOR	
January 2011 - June 2015	 	$	75,000	 	 	1.34	%	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 December 31, 2010, the net liability of interest rate derivative contracts was reduced by $0.5 million for estimated nonperformance risk.

        All of the Company's derivatives were made up of non-hedge derivatives as of December 31, 2010. The following tables provide disclosure of the Company's derivative instruments:
 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair Value of Derivative Instruments as of December 31, 2010	 	
 
	 	Asset Derivatives	 	Liability Derivatives	 	
Type	 	Balance Sheet Location	 	Fair
Value	 	Balance Sheet Location	 	Fair
Value	 	

	 	(In thousands)
	 	 
	 	(In thousands)
	 	
Derivatives not designated as hedging instruments	 	 	 	 	 	 	 	 	 	 	 	
 	Commodity derivatives	 	Derivatives—current	 	$	—	 	Derivatives—current	 	$	13,979	 	
 	Interest rate derivatives	 	Derivatives—current	 	 	—	 	Derivatives—current	 	 	6,375	 	
 	Commodity derivatives	 	Derivatives—noncurrent	 	 	—	 	Long-term derivatives	 	 	14,340	 	
 	Interest rate derivatives	 	Derivatives—noncurrent	 	 	1,501	 	Long-term derivatives	 	 	764	 	
 	 	 	 	 	 	 	 	 	 	
Total derivatives not designated as hedging instruments	 	 	 	 	1,501	 	 	 	 	35,458	 	
 	 	 	 	 	 	 	 	 	 	
Total derivatives	 	 	 	$	1,501	 	 	 	$	35,458	 	
 	 	 	 	 	 	 	 	 	 	
F-24

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

11. Derivative Financial Instruments (Continued)

        The Company did not have any derivative instruments at December 31, 2009.

	 	 
	 	Amount of Income
Recognized in
AOCI(L) on
Effective Portion	 	 	

	 	Years Ended
December 31	 	 	
 
	 	Location of Gain/(Loss)	 	 	 	 	 	
Derivatives in Cash Flow Hedging Relationships	 	 	 	2009	 	2010	 	 	 	 	

	 	(In thousands)
	 	 	 	 	
Interest rate derivatives	 	AOCI(L)	 	$	—	 	$	588	 	 	 	 	

 	 	 	 	 	 	 	 	 	 	 	

	 	Amount of Loss
Reclassified from
AOCI(L) into
Earnings	 	 	

	 	Years Ended
December 31	 	 	
 
	 	Location of Gain/(Loss)
Reclassified from
AOCI(L) into Earnings	 	 	 	 	 	
Derivatives in Cash Flow Hedging Relationships	 	 	 	2009	 	2010	 	 	 	 	

	 	(In thousands)
	 	 	 	 	
Interest rate derivatives	 	Interest expense	 	$	—	 	$	(5,426	)	 	 	 	

 	 	 	 	 	 	 	 	 	 	 	 	

	 	Amount of Gain
(Loss) Recognized in
Earnings on
Derivatives	 	 	

	 	Years Ended
December 31	 	 	
 
	 	Location of Gain (Loss)
Recognized in Earnings
on Derivatives	 	 	 	 	 	
Derivatives Not Designated as Hedging Instruments	 	 	 	2009	 	2010	 	 	 	 	

	 	(In thousands)
	 	 	 	 	
Commodity derivatives	 	Derivatives, net	 	$	—	 	$	(28,319	)	 	 	 	
Interest rate derivatives	 	Interest expense	 	 	—	 	 	(6,967	)	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	
 	Total	 	 	 	$	—	 	$	(35,286	)	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	
        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 the earnings of the period in which they occur. During the twelve months ending December 31, 2011, the Company expects to reclassify $2.9 million of AOCI(L) losses to interest expense. See Note 15—Fair Value Measurements for additional information regarding the Company's derivative instruments.

F-25

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

12. Asset Retirement Obligations

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

	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Asset Retirement Obligations:	 	 	 	 	 	 	 	
 	Beginning asset retirement obligations	 	$	—	 	$	—	 	
 	Liabilities incurred during period	 	 	—	 	 	16,570	 	
 	Revisions in estimated retirement obligations	 	 	—	 	 	—	 	
 	Liabilities settled during period	 	 	—	 	 	—	 	
 	Accretion expense	 	 	—	 	 	182	 	
 	 	 	 	 	 	
 	Ending asset retirement obligations	 	$	—	 	$	16,752	 	
 	 	 	 	 	 	
        The Ghanaian legal and regulatory regime regarding oil field abandonment and other environmental matters is evolving. Currently, no Ghana 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 which 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 Tullow Ghana, Ltd., 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.

13. 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

F-26

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

13. Convertible Preferred Units (Continued)

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.

        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	 	 	44,758	 	 	36,621	 	 	1,867	 	 	83,246	 	
 	 	 	 	 	 	 	 	 	 	
Total Issuances—Series A	 	$	206,056	 	$	168,593	 	$	8,597	 	$	383,246	 	
 	 	 	 	 	 	 	 	 	 	
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	 	 	36,712	 	 	30,037	 	 	1,414	 	 	68,163	 	
 	 	 	 	 	 	 	 	 	 	
Total Issuances—Series B	 	$	306,006	 	$	250,368	 	$	11,789	 	$	568,163	 	
 	 	 	 	 	 	 	 	 	 	
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	 	 	1,128	 	 	923	 	 	46	 	 	2,097	 	
 	 	 	 	 	 	 	 	 	 	
Total Issuances—Series C	 	$	14,579	 	$	11,928	 	$	590	 	$	27,097	 	
 	 	 	 	 	 	 	 	 	 	
        Under the Fourth Amended and Restated Operating Agreement of Kosmos Energy Holdings (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 seven 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 as of December 31, 2010, the date at which a determination was made that it was probable that an exchange

F-27

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

13. Convertible Preferred Units (Continued)

of securities for common shares would occur. The amount was applied to additional paid-in capital first, with the remaining amount applied to the deficit accumulated during development stage.

        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, they 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 and preferred shares, respectively, of the "IPO Corporation," as defined in the Agreement. Each preferred share of the IPO Corporation would be exchanged for a combination of cash or 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 Directors.

14. Other Income

        Other income consists primarily of technical service fees and overhead expenses billed to third parties for the Jubilee Field per the Pre Unit Agreement through July 13, 2009, and subsequently the UUOA. The expenses associated with these third-party billings are recorded within the general and administrative expense line item in the accompanying consolidated financial statements. Other income under this agreement was $6.0 million, $9.6 million and $5.1 million for the years ended December 31, 2008, 2009 and 2010, respectively.

15. 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

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

15. Fair Value Measurements (Continued)

prices that are observable for the asset or liability (e.g., interest rates) 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 table presents the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2010, for each of the fair value hierarchy levels:

	 	Fair Value Measurements at
Reporting Date Using	 	 

	 	Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)	 	Significant
Other
Observable
Inputs
(Level 2)	 	Significant
Unobservable
Inputs
(Level 3)	 	Fair Value at
December 31
2010	 	
 
	 	(In thousands)
	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Money market accounts	 	$	18,056	 	$	—	 	$	—	 	$	18,056	 	
Interest rate derivatives	 	 	—	 	 	1,501	 	 	—	 	 	1,501	 	
 	 	 	 	 	 	 	 	 	 	
 	Total assets	 	$	18,056	 	$	1,501	 	$	—	 	$	19,557	 	
 	 	 	 	 	 	 	 	 	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	$	—	 	$	28,319	 	$	—	 	$	28,319	 	
Interest rate derivatives	 	 	—	 	 	7,139	 	 	—	 	 	7,139	 	
 	 	 	 	 	 	 	 	 	 	
 	Total liabilities	 	$	—	 	$	35,458	 	$	—	 	$	35,458	 	
 	 	 	 	 	 	 	 	 	 	
        All fair values have been adjusted for nonperformance risk resulting in a decrease of the commodity derivative liabilities of approximately $2.7 million and a decrease of the interest rate derivatives of approximately of $0.5 million as of December 31, 2010. 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 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.

F-29

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

15. Fair Value Measurements (Continued)

        The following table presents the carrying amounts and fair values of the Company's financial instruments as of December 31, 2009 and 2010:

	 	December 31, 2009	 	December 31, 2010	 	
 
	 	Carrying
Value	 	Fair Value	 	Carrying
Value	 	Fair Value	 	
 
	 	(In thousands)
	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Money market accounts	 	$	59,757	 	$	59,757	 	$	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	 	
        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 as of December 31, 2010 are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for Dated Brent, (iii) a credit-adjusted yield curve as 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 were 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 11—Derivative Financial Instruments for additional information regarding the Company's derivative instruments.

Interest Rate Derivatives

        The Company's interest rate derivatives as of December 31, 2010 represent swap contracts for $475.0 million notional amount of debt, 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 as of December 31, 2010 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR rate 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.

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

16. Income Taxes

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

	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
United States	 	$	674	 	$	2,497	 	$	1,476	 	
Foreign	 	 	(49,210	)	 	(81,271	)	 	(324,256	)	
 	 	 	 	 	 	 	 	
Ending balance	 	$	(48,536	)	$	(78,774	)	$	(322,780	)	
 	 	 	 	 	 	 	 	
        Kosmos Energy Holdings is a Cayman Island company that is treated as a partnership for U.S. tax purposes. Kosmos Energy Holding's operating subsidiaries in the United States, Ghana, Cameroon and Morocco are subject to taxation in their respective jurisdictions.

        The components of the provision for income taxes were as follows:

	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Current:	 	 	 	 	 	 	 	 	 	 	
 	U.S. federal	 	$	(232	)	$	651	 	$	844	 	
 	State and local	 	 	73	 	 	223	 	 	(338	)	
 	 	 	 	 	 	 	 	
Total current	 	 	(159	)	 	874	 	 	506	 	
Deferred:	 	 	 	 	 	 	 	 	 	 	
 	U.S. federal	 	 	428	 	 	99	 	 	(143	)	
 	Foreign	 	 	—	 	 	—	 	 	(77,471	)	
 	 	 	 	 	 	 	 	
Total deferred	 	 	428	 	 	99	 	 	(77,614	)	
 	 	 	 	 	 	 	 	
Provision (benefit) for income taxes	 	$	269	 	$	973	 	$	(77,108	)	
 	 	 	 	 	 	 	 	
        A reconciliation of the differences between the Company's applicable statutory tax rate and the Company's effective income tax rate follows:

	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
Tax provision at statutory rate (Cayman Islands)	 	 	—	%	 	—	%	 	—	%	
Loss subject to tax benefit in excess of statutory rate	 	 	22.39	 	 	18.24	 	 	23.19	 	
Change in valuation allowance	 	 	(22.73	)	 	(19.25	)	 	1.12	 	
Other	 	 	(0.21	)	 	(0.22	)	 	(0.42	)	
 	 	 	 	 	 	 	 	
Consolidated effective tax rate	 	 	(0.55	)%	 	(1.23	)%	 	23.89	%	
 	 	 	 	 	 	 	 	
        Deferred taxes reflect the tax effects of differences between the amounts recorded as assets and liabilities for financial reporting purposes and the amounts recorded for income tax purposes. The tax

F-31

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

16. Income Taxes (Continued)

effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows:

	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Deferred tax assets:	 	 	 	 	 	 	 	
 	Ghana foreign capitalized operating expenses	 	$	20,591	 	$	8,473	 	
 	Foreign net operating losses	 	 	15,552	 	 	134,090	 	
 	Other	 	 	488	 	 	6,007	 	
 	 	 	 	 	 	
Total deferred tax assets	 	 	36,631	 	 	148,570	 	
Deferred tax liabilities:	 	 	 	 	 	 	 	
 	Depletion, depreciation and amortization	 	 	(653	)	 	(36,900	)	
 	Intangible drilling costs	 	 	(2,563	)	 	(4,243	)	
 	Other	 	 	(192	)	 	(200	)	
 	 	 	 	 	 	
Total deferred tax liabilities	 	 	(3,408	)	 	(41,343	)	
Valuation allowance	 	 	
(33,749	
)	 	
(30,140	
)	
 	 	 	 	 	 	
Net deferred tax asset (liability)	 	$	(526	)	$	77,087	 	
 	 	 	 	 	 	
        The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. During 2008, the Company determined that it was more likely than not that the net deferred tax asset for its U.S. operations would be realized in the amount of $79 thousand.

        The Company had net deferred tax assets in Ghana totaling approximately $20.6 million at December 31, 2009 primarily relating to capitalized operating expenses incurred during the development phase of the Jubilee Field. Prior to the commencement of production from the Jubilee Field on November 28, 2010, the Company maintained a full valuation allowance against its 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 and concluded that many of the considerations that previously led to the need for a valuation allowance related to the Ghana deferred tax assets no longer exist as of December 31, 2010, as the Company had begun production. The net change in the valuation allowance of $3.6 million is due to the release of the Ghana valuation allowance netted against current year activity in Morocco and Cameroon.

        Additionally, in 2010, with the commencement of oil production in Ghana, the Company began to amortize its pre-operating development costs related to the Jubilee Field over a five-year period for tax purposes in accordance with Ghanaian tax law.

        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

F-32

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

16. Income Taxes (Continued)

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 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 in the third quarter of 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. Based on our current production plan and a price per barrel of $79.35, which is also used to calculate our standardized measure, we anticipate realization of the net operating loss carryforward by the end of 2012. If we utilize current production plans and March 2, 2011 crude oil prices, we will realize the net operating loss carryforward prior to that.

•
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.

F-33

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

16. Income Taxes (Continued)

•
There is an unlimited NOL 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 realized and, therefore, released the $20.6 million valuation allowance that was recorded as of December 31, 2009 and recognized $56.9 million of deferred tax assets generated during 2010.

        The Company entered into the Boujdour Offshore Petroleum Agreement in May 2006. This 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 $6.8 million, recorded at the Moroccan statutory rate of 30%, with an offsetting valuation allowance of $6.8 million. Once 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 has foreign net operating loss carryforwards of approximately $58.9 million which begin to expire in 2011 through 2015 and approximately $298.6 million which do not expire.

        Effective January 1, 2009, the Company 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 the implementation of this standard, the Company recognized no material adjustment for unrecognized income tax benefits. In addition, there were no material unrecognized income tax benefits recognized during the current year.

        The Company files a U.S. federal income tax return and a Texas margin tax return. In addition to the United States, the Company files income tax returns in the countries in which the Company operates. The Company is open to U.S. federal income tax examinations for tax years 2007 through 2010 and to Texas margin tax examinations for the tax years 2006 through 2010. In addition the Company is open to income tax examinations for years 2004 through 2010 in its significant foreign jurisdictions (Ghana, Cameroon and Morocco).

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

        During 2007, the Company settled an examination by the Internal Revenue Service. The settlement resulted in an adjustment that eliminated the domestic net operating loss carryforward. The Company was required to pay $137 thousand of additional tax related to the exam of the 2005 and 2006 federal income tax returns.

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

17. 401(k) Plan

        As of July 2007, the Company offers a 401(k) Plan to which employees may contribute tax deferred earnings subject to Internal Revenue Service limitations. Employee contributions of up to 6% of compensation, as defined by the plan, is matched by the Company at 100%. The Company's match is vested immediately. Matching contributions made by the Company to the 401(k) Plan were approximately $315 thousand, $550 thousand and $668 thousand for the years ended December 31, 2008, 2009 and 2010, respectively.

18. Profit Units

        Kosmos issues common units designated as profit units with a threshold value of $0.85 to $90 to employees, management and directors. Profit units, the defined term in the related agreements, are equity awards that are measured on the grant date and expensed over a vesting period of four years. Founding management and directors vest 20% as of the date of issuance and an additional 20% on the anniversary date for each of the next four years. Profit units issued to employees vest 50% on the second and fourth anniversary of the issuance date. Of the 100 million authorized common units, 15.7 million are designated as profit units. The following is a summary of the Company's profit unit activity:

	 	Profit Units	 	Weighted-Average
Grant-Date
Fair Value	 	
 
	 	(In thousands)

Outstanding at December 31, 2007	 	 	3,984	 	$	0.13	 	
 	Granted	 	 	9,595	 	 	1.11	 	
 	Relinquished	 	 	(67	)	 	1.52	 	
 	 	 	 	 	 	 	
Outstanding at December 31, 2008	 	 	13,512	 	 	0.82	 	
 	Granted	 	 	10	 	 	2.94	 	
 	Relinquished	 	 	(15	)	 	3.05	 	
 	 	 	 	 	 	 	
Outstanding at December 31, 2009	 	 	13,507	 	 	0.81	 	
 	Granted	 	 	411	 	 	5.27	 	
 	Relinquished	 	 	(8	)	 	2.45	 	
 	 	 	 	 	 	 	
Outstanding December 31, 2010	 	 	13,910	 	 	1.76	 	
 	 	 	 	 	 	 	
F-35

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

18. Profit Units (Continued)

        A summary of the status of the Company's non-vested profit units is as follows:

	 	Profit Units	 	Weighted-Average
Grant-Date
Fair Value	 	
 
	 	(In thousands)

Non-vested at December 31, 2007	 	 	2,080	 	$	0.22	 	
 	Granted	 	 	9,595	 	 	1.11	 	
 	Vested	 	 	(2,659	)	 	0.66	 	
 	Relinquished	 	 	(67	)	 	1.52	 	
 	 	 	 	 	 	 	
Non-vested at December 31, 2008	 	 	8,949	 	 	1.03	 	
 	Granted	 	 	10	 	 	2.94	 	
 	Vested	 	 	(2,000	)	 	0.90	 	
 	Relinquished	 	 	(15	)	 	3.05	 	
 	Other	 	 	13	 	 	0.02	 	
 	 	 	 	 	 	 	
Non-vested at December 31, 2009	 	 	6,957	 	 	1.06	 	
 	Granted	 	 	411	 	 	5.27	 	
 	Vested	 	 	(2,719	)	 	1.03	 	
 	Relinquished	 	 	(8	)	 	2.45	 	
 	Accelerated vesting	 	 	(1,177	)	 	10.66	 	
 	 	 	 	 	 	 	
Non-vested at December 31, 2010	 	 	3,464	 	 	1.60	 	
 	 	 	 	 	 	 	
        Effective December 31, 2010, James C. Musselman retired as the Company's Chairman and Chief Executive Officer. The Company entered into a retirement agreement with Mr. Musselman on December 17, 2010. Pursuant to the retirement agreement, 1.2 million profit units of Kosmos Energy Holdings that were unvested as of his retirement date became fully vested as of such date resulting in unit-based compensation of $11.5 million in the fourth quarter of 2010.

        At December 31, 2010, the remaining unrecognized compensation cost from profit units was $3.1 million, which will be recognized over a weighted-average period of 2.3 years. Total profit unit compensation expense recognized in income was $3.7 million, $3.5 million and $13.8 million for the years ended December 31, 2008, 2009 and 2010, respectively.

        The significant assumptions used to calculate the fair values of the profit units granted over the past three years, as calculated using a binomial tree, were as follows: no dividend yield, expected volatility ranging from approximately 25% to 66%, risk-free interest rate ranging from 1.3% to 5.1%, expected life ranging from 1.2 to 8.1 years and projected turnover rate of 7.0% for employees and none for management.

F-36

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

19. Commitments and Contingencies

        As of September 12, 2003, the Company leased office space located at 8401 North Central Expressway, Dallas, Texas. The lease, as amended, expired on September 30, 2009.

        As of June 29, 2008, office lease agreements were signed between Harvest/NPE LP and Kosmos Energy, LLC with respect to spaces located at 8170 Park Lane, Dallas, Texas, referred to as the North Premises and the South Premises. The leases commenced in March 2009 and expire in 2015 and 2014, respectively. At December 31, 2009 and 2010, liabilities of $1.7 million and $1.4 million, respectively, were recorded for tenant improvement allowances. The Company received $2.0 million for leasehold incentives from Harvest/NPE LP in 2009.

        The Company leases other facilities under various operating leases that expire through 2015. Rent expense under these agreements along with the office lease agreements, was $0.9 million, $1.4 million and $1.4 million for the years ended December 31, 2008, 2009 and 2010, respectively.

        Future minimum rental commitments under these leases at December 31, 2010, are as follows:

	 	Office Leases	 	
 
	 	(In thousands)
	 	
2011	 	$	1,615	 	
2012	 	 	1,636	 	
2013	 	 	1,660	 	
2014	 	 	1,168	 	
2015	 	 	382	 	
Thereafter	 	 	—	 	
        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 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 is $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 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 Tullow Ghana Limited 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 time. The future minimum commitments under this contract as of December 31, 2010, are (in thousands): 2011—$138,588; and 2012—$133,131.

20. Litigation

        Kosmos Energy Holdings is not party to any litigation or proceedings with respect to the Company's operations which management believes, based on advice of 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.

F-37

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

21. Subsequent Events

Commercial Debt Facilities

        In January 2011, the Company borrowed $28.0 million under the senior facilities. As of the date of the financial statements, borrowings against the commercial debt facilities totaled $1.07 billion and the scheduled principal maturities during the next five years and thereafter are (in thousands): 2011—$273,000; 2012—$250,000; 2013—$200,000; 2014—$175,000; 2015—$100,000 and thereafter—$75,000.

Exploration Expenses

        Drilling of the Mombe-1 exploration well was completed in January 2011. The well encountered hydrocarbons in sub-commercial quantities and accordingly will be plugged and abandoned. Total well related costs incurred from inception through December 31, 2010 of $26.1 million are included in exploration expenses in the accompanying consolidated statement of operations. As of the date of the financial statements, the Company estimates we will incur an additional $1.8 million of related well costs.

Exchange of Convertible Preferred Units

        Contemporaneous with the public offering, the holders of the convertible preferred units are expected to exercise their rights, acquired on formation, to exchange all of the outstanding convertible preferred units of the Company to ordinary shares based on the pre-offering equity value of such interests. As a result, 50,884,956 convertible preferred units outstanding at that date will be exchanged into 279,208,798 ordinary shares. The ordinary shares have one vote per share and a par value of $0.01. The effects of the exchange of the convertible preferred units are shown in the balance sheet column "Pro Forma."

22. Pro forma Information (Unaudited)

Per share information

        Basic and diluted net loss per share have been calculated using the weighted average number of common shares, on a pro forma basis, assuming conversion of the redeemable preferred units into common shares. The weighted average common shares outstanding have been calculated as if the ownership restructure resulting from the corporate reorganization was in place since inception.

        The pro forma as adjusted as of December 31, 2010 gives effect to the exchange of all of the interests in Kosmos Energy Holdings for newly issued common shares of Kosmos Energy Ltd. pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

22. Pro forma Information (Unaudited) (Continued)

closing of this offering. The following is a reconciliation of the denominator of the pro forma basic and diluted net loss per share computations (in thousands, except per share data).

	 	Year Ended
December 31
2010	 	
Weighted average common shares outstanding:	 	 	 	 	
 	As converted from common units	 	 	46,590	 	
 	As converted from convertible preferred units	 	 	279,209	 	
 	 	 	 	
Pro forma weighted average common shares for basic and diluted net loss per common share	 	 	325,799	 	
 	 	 	 	
        The following table sets forth the computation of pro forma basic and diluted net loss per common share (in thousands, except per share data).

	 	Year Ended
December 31
2010	 	
Numerator	 	 	 	 	
Net loss	 	$	(245,672	)	
 	 	 	 	
Denominator	 	 	 	 	
Pro forma weighted average common shares for basic and diluted net loss per common share	 	 	325,799	 	
 	 	 	 	
Pro forma basic and diluted net loss per share	 	
$	
(0.75	
)	

23. Supplementary Oil and Gas Data (Unaudited)

        In January 2010, the FASB issued ASU No. 2010-03—Extractive Activities—Oil and Gas (ASC 932) Oil and Gas Reserve Estimation and Disclosures so as to align the oil and gas reserve estimation and disclosure requirements of Extractive Activities—Oil and Gas (ASC 932) with the requirements in the SEC's final rule, Modernization of the Oil and Gas Reporting Requirements which was issued on December 31, 2008. The Company adopted the update as of December 31, 2009.

        Net proved oil and gas reserve estimates presented were prepared by Netherland, Sewell & Associates, Inc. ("NSAI"), independent petroleum engineers located in Dallas, Texas. The technical persons at NSAI have prepared the reserve estimates presented herein and meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to independent reserve engineers for their reserves review process. The supplementary oil and gas data that follows includes (1) net proved oil and gas reserves, (2) capitalized costs related to oil and gas producing activities, (3) costs incurred for property

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

acquisition, exploration, and development activities, (4) results of operations for oil and gas producing activities, (5) a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, and (6) changes in the standardized measure of discounted future net cash flows. Oil production commenced on November 28, 2010, and we received revenues from oil production in early 2011; therefore, there are no disclosures related to item (4) above for 2010.

Net Proved Developed and Undeveloped Reserves

        The following table is a summary of net proved developed and undeveloped oil and gas reserves to Kosmos' interest in the Jubilee Field Phase 1 development in Ghana.

	 	Oil	 	Gas	 	Total	 	
 
	 	(Mmbbl)
	 	(Bcf)
	 	(Mmboe)
	 	
Net proved undeveloped reserves at December 31, 2008	 	 	—	 	 	—	 	 	—	 	
 	Discoveries and extensions	 	 	52	 	 	—	 	 	52	 	
 	Production	 	 	—	 	 	—	 	 	—	 	
 	Purchases of minerals-in-place	 	 	—	 	 	—	 	 	—	 	
 	 	 	 	 	 	 	 	
Net proved undeveloped reserves at December 31, 2009	 	 	52	 	 	—	 	 	52	 	
 	Discoveries and extensions	 	 	—	 	 	22	 	 	4	 	
 	Production	 	 	—	 	 	—	 	 	—	 	
 	Purchases of minerals-in-place	 	 	—	 	 	—	 	 	—	 	
 	 	 	 	 	 	 	 	
Net proved developed and undeveloped reserves at December 31, 2010	 	 	52	 	 	22	 	 	56	 	
 	 	 	 	 	 	 	 	
Proved developed reserves	 	 	 	 	 	 	 	 	 	 	
 	January 1, 2009	 	 	—	 	 	—	 	 	—	 	
 	December 31, 2009	 	 	—	 	 	—	 	 	—	 	
 	December 31, 2010	 	 	35	 	 	18	 	 	38	 	
Proved undeveloped reserves	 	 	 	 	 	 	 	 	 	 	
 	January 1, 2009	 	 	—	 	 	—	 	 	—	 	
 	December 31, 2009	 	 	52	 	 	—	 	 	52	 	
 	December 31, 2010	 	 	17	 	 	4	 	 	18	 	
        Net proved reserves were calculated utilizing the twelve month unweighted arithmetic average of the first-day-of-the-month oil price for each month for Brent crude in the period January through December 2010. The average Brent crude price of $79.35 per barrel is adjusted for crude handling, transportation fees, quality, and a regional price differential. Based on the crude quality, these adjustments are estimated to be an additional $0.35 per barrel; therefore, the oil flowstreams receive a crude price of $79.70 per barrel. This oil price is held constant throughout the lives of the properties. There is no gas price used because gas reserves are consumed in operations as fuel.

        Proved oil and gas reserves are defined by the SEC Rule 4.10(a) of Regulation S-X as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recovered under current economic conditions, operating

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

methods, and government regulations. Inherent uncertainties exist in estimating proved reserve quantities, projecting future production rates and timing of development expenditures.

Capitalized Costs Related to Oil and Gas Activities

        The following table presents aggregate capitalized costs related to oil and gas activities:

	 	Ghana	 	Other West
Africa	 	Total	 	
 
	 	(In thousands)
	 	
As of December 31, 2009	 	 	 	 	 	 	 	 	 	 	
 	Unproved properties	 	$	121,781	 	$	7,206	 	$	128,987	 	
 	Proved properties	 	 	466,104	 	 	—	 	 	466,104	 	
 	 	 	 	 	 	 	 	
 	 	 	587,885	 	 	7,206	 	 	595,091	 	
Accumulated depletion, depreciation and amortization	 	 	
—	 	 	
—	 	 	
—	 	
 	 	 	 	 	 	 	 	
Net capitalized costs	 	$	587,885	 	$	7,206	 	$	595,091	 	
 	 	 	 	 	 	 	 	
As of December 31, 2010	 	 	 	 	 	 	 	 	 	 	
 	Unproved properties	 	$	190,184	 	$	7,965	 	$	198,149	 	
 	Proved properties	 	 	798,150	 	 	—	 	 	798,150	 	
 	 	 	 	 	 	 	 	
 	 	 	988,334	 	 	7,965	 	 	996,299	 	
Accumulated depletion, depreciation and amortization	 	 	(6,430	)	 	—	 	 	(6,430	)	
 	 	 	 	 	 	 	 	
Net capitalized costs	 	$	981,904	 	$	7,965	 	$	989,869	 	
 	 	 	 	 	 	 	 	
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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

Costs Incurred in Oil and Gas Activities

        The following table reflects total costs incurred, both capitalized and expensed, for oil and gas property acquisition, exploration, and development activities for the year.

	 	Ghana	 	Other West
Africa	 	Total	 	
 
	 	(In thousands)
	 	
Year ended December 31, 2008	 	 	 	 	 	 	 	 	 	 	
Property acquisition:	 	 	 	 	 	 	 	 	 	 	
 	Unproved	 	$	—	 	$	—	 	$	—	 	
 	Proved	 	 	—	 	 	—	 	 	—	 	
Exploration	 	 	45,961	 	 	9,631	 	 	55,592	 	
Development	 	 	146,728	 	 	—	 	 	146,728	 	
 	 	 	 	 	 	 	 	
Total costs incurred	 	$	192,689	 	$	9,631	 	$	202,320	 	
 	 	 	 	 	 	 	 	
Year ended December 31, 2009	 	 	 	 	 	 	 	 	 	 	
Property acquisition:	 	 	 	 	 	 	 	 	 	 	
 	Unproved	 	$	—	 	$	—	 	$	—	 	
 	Proved	 	 	—	 	 	—	 	 	—	 	
Exploration	 	 	88,103	 	 	20,776	 	 	108,879	 	
Development	 	 	304,948	 	 	—	 	 	304,948	 	
 	 	 	 	 	 	 	 	
Total costs incurred	 	$	393,051	 	$	20,776	 	$	413,827	 	
 	 	 	 	 	 	 	 	
Year ended December 31, 2010	 	 	 	 	 	 	 	 	 	 	
Property acquisition:	 	 	 	 	 	 	 	 	 	 	
 	Unproved	 	$	—	 	$	—	 	$	—	 	
 	Proved	 	 	—	 	 	—	 	 	—	 	
Exploration	 	 	109,624	 	 	32,304	 	 	141,928	 	
Development	 	 	325,975	 	 	—	 	 	325,975	 	
 	 	 	 	 	 	 	 	
Total costs incurred	 	$	435,599	 	$	32,304	 	$	467,903	 	
 	 	 	 	 	 	 	 	
Standardized Measure for Discounted Future Net Cash Flows

        The following table provides projected future net cash flows based on the twelve month unweighted arithmetic average of the first-day-of-the-month oil price for Brent crude in the period January through December 2010. The average Brent crude price of $79.35 per barrel is adjusted for crude handling, transportation fees, quality, and a regional price differential. Based on the crude quality, these adjustments are estimated to be an additional $0.35 per barrel; therefore, the oil flowstreams receive a crude price of $79.70 per barrel. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on market conditions that occurred.

        The projection should not be interpreted as representing the current value to Kosmos. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

from those used; and actual costs may vary. Kosmos' investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on a wide range of different price and cost assumptions.

        The standardized measure is intended to provide a better means to compare the value of Kosmos' proved reserves at a given time with those of other oil producing companies than is provided by comparing raw proved reserve quantities.

	 	Ghana	 	
 
	 	(In millions)
	 	
At December 31, 2009	 	 	 	 	
Future cash inflows	 	$	3,098	 	
Future production costs	 	 	(990	)	
Future development costs	 	 	(630	)	
Future Ghanaian tax expenses(1)	 	 	(351	)	
 	 	 	 	
Future net cash flows	 	 	1,127	 	
10% annual discount for estimated timing of cash flows	 	 	(429	)	
 	 	 	 	
Standardized measure of discounted future net cash flows	 	$	698	 	
 	 	 	 	
At December 31, 2010	 	 	 	 	
Future cash inflows	 	$	4,141	 	
Future production costs	 	 	(1,140	)	
Future development costs	 	 	(342	)	
Future Ghanaian tax expenses(1)	 	 	(618	)	
 	 	 	 	
Future net cash flows	 	 	2,041	 	
10% annual discount for estimated timing of cash flows	 	 	(511	)	
 	 	 	 	
Standardized measure of discounted future net cash flows	 	$	1,530	 	
 	 	 	 	
Changes in the Standardized Measure for Discounted Cash Flows

	 	Ghana	 	
 
	 	(In millions)
	 	
Balance at December 31, 2009	 	$	698	 	
Net changes in prices	 	 	1,055	 	
Net changes in production costs	 	 	(150	)	
Net changes in development costs	 	 	288	 	
Extensions and discoveries	 	 	(12	)	
Net change in Ghanaian tax expenses(1)	 	 	(267	)	
Accretion of discount	 	 	(82	)	
 	 	 	 	
Balance at December 31, 2010	 	$	1,530	 	

(1)
Standardized Measure includes the effects of both future income tax expense related to the Company's proved oil and gas reserves levied at a corporate parent and intermediate

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

subsidiary level on future net revenues and future tax expense levied at an asset level (in the Company's case, future Ghanaian tax expense levied under the WCTP and DT Petroleum Agreements). As the Company has been a tax exempted company incorporated pursuant to the laws of the Cayman Islands to date and will be a tax exempted company incorporated pursuant to the laws of Bermuda following the completion of the corporate reorganization to be completed in connection with this offering, and as the Company's intermediate subsidiaries positioned between it and the subsidiary that is a signatory to the WCTP and DT Petroleum Agreements will continue to be tax exempted companies, the Company has not been and does not expect to be subject to future income tax expense related to its proved oil and gas reserves levied at a corporate parent or intermediate subsidiary level. Accordingly, the Company's Standardized Measure for the years ended December 31, 2009 and 2010, respectively, only reflect the effects of future Ghanaian tax expense levied under the WCTP and DT Petroleum Agreements.

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Table of Contents

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13.    Other Expenses of Issuance and Distribution.

        The following table sets forth an itemization of the various costs and expenses, all of which we will pay, in connection with the issuance and distribution of the securities being registered. All of the amounts shown are estimated except the SEC registration fee, the NYSE listing fee and the FINRA filing fee:
 	 	 	 	 	
SEC registration fee	 	$	58,050	 	
NYSE listing fee	 	 	250,000	 	
FINRA filing fee	 	 	75,500	 	
Accounting fees and expense	 	 	1,500,000	 	
Printing and engraving expenses	 	 	450,000	 	
Legal fees and expenses	 	 	2,800,000	 	
Transfer Agents and Registrar fees	 	 	25,000	 	
Miscellaneous	 	 	341,450	 	
 	 	 	 	
Total	 	$	5,500,000	 	
 	 	 	 	
Item 14.    Indemnification of Directors and Officers.

        Section 98 of the Companies Act 1981 of Bermuda (the "Bermuda Companies Act") provides generally that a Bermuda company may indemnify its directors, officers and auditors against any liability which by virtue of any rule of law would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust, except in cases where such liability arises from fraud or dishonesty of which such director, officer or auditor may be guilty in relation to the company. Section 98 further provides that a Bermuda company may indemnify its directors, officers and auditors against any liability incurred by them in defending any proceedings, whether civil or criminal, in which judgment is awarded in their favour or in which they are acquitted or granted relief by the Supreme Court of Bermuda pursuant to section 281 of the Bermuda Companies Act.

        We have adopted provisions in our bye-laws that provide that we shall indemnify our officers and directors in respect of their actions and omissions, except in respect of their fraud or dishonesty. Our bye-laws provide that the company and the shareholders waive all claims or rights of action that they might have, individually or in right of the company, against any of the company's directors or officers for any act or failure to act in the performance of such director's or officer's duties, except in respect of any fraud or dishonesty of such director or officer. Section 98A of the Bermuda Companies Act permits us to purchase and maintain insurance for the benefit of any officer or director in respect of any loss or liability attaching to him in respect of any negligence, default, breach of duty or breach of trust, whether or not we may otherwise indemnify such officer or director.

        Insofar as indemnification by us for liabilities arising under the Securities Act may be permitted to our directors, officers or persons controlling the company pursuant to provisions of our bye-laws, or otherwise, we have been advised that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable. In the event that a claim for indemnification by such director, officer or controlling person of us in the successful defense of any action, suit or proceeding is asserted by such director, officer or controlling person in connection with the securities being offered, we will, unless in the opinion of our counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by us is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

II-1

        At the present time, there is no pending litigation or proceeding involving a director, officer, employee or other agent of ours in which indemnification would be required or permitted. We are not aware of any threatened litigation or proceeding, which may result in a claim for such indemnification.

        We carry insurance policies insuring our directors and officers against certain liabilities that they may incur in their capacity as directors and officers. In addition, we expect to enter into indemnification agreements with each of our directors prior to completion of the offering.

        Additionally, reference is made to the Underwriting Agreement filed as Exhibit 1.1. hereto, which provides for indemnification by the underwriters of Kosmos Energy Ltd., our directors and officers who sign the registration statement and persons who control Kosmos Energy Ltd., under certain circumstances.

Item 15.    Recent Sales of Unregistered Securities.

        During the past three years, Kosmos Energy Ltd.'s predecessor, Kosmos Energy Holdings, issued unregistered securities to funds affiliated with Warburg Pincus LLC ("Warburg Pincus"), The Blackstone Group L.P. ("Blackstone"), certain members of management, accredited employee investors and directors, as described below. None of these transactions involved any underwriters or any public offerings, and we believe that each of these transactions was exempt from the registration requirements pursuant to Section 3(a)(9) or Section 4(2) of the Securities Act of 1933, as amended. The recipients of the securities in these transactions represented their intention to acquire the securities for investment only and not with a view to or for sale in connection with any distribution thereof. The information presented below does not give effect to our corporate reorganization as described in the prospectus.

        During the fiscal year ended December 31, 2008, Kosmos Energy Holdings issued the following unregistered securities for the consideration listed:
 	 	 	 	 	 	 	
Recipient	 	Securities Issued	 	Consideration
Received by
Kosmos Energy
Holdings	 	
Warburg Pincus	 	7,150,893 Series A Convertible Preferred Units	 	$	71,508,930	 	
 	 	4,308,700 Series B Convertible Preferred Units	 	 	107,717,500	 	
Blackstone	 	5,850,738 Series A Convertible Preferred Units	 	
$	
58,507,380	 	
 	 	3,525,300 Series B Convertible Preferred Units	 	 	88,132,500	 	
Members of management, accredited employee investors and directors, in the aggregate	 	298,367 Series A Convertible Preferred Units	 	
$	
2,983,670	 	
 	 	152,250 Series B Convertible Preferred Units	 	 	3,806,250	 	
II-2

        During the fiscal year ended December 31, 2009, Kosmos Energy Holdings issued the following unregistered securities for the consideration listed:
 	 	 	 	 	 	 	
Recipient	 	Securities Issued	 	Consideration
Received by
Kosmos Energy
Holdings	 	
Warburg Pincus	 	6,463,052 Series B Convertible Preferred Units	 	$	161,576,300	 	
 	 	476,134 Series C Convertible Preferred Units(1)	 	 	13,450,786	 	
Blackstone	 	5,287,948 Series B Convertible Preferred Units	 	
$	
132,198,700	 	
 	 	389,563 Series C Convertible Preferred Units(1)	 	 	11,005,155	 	
Members of management, accredited employee investors and directors, in the aggregate	 	262,750 Series B Convertible Preferred Units	 	
$	
6,568,750	 	
 	 	19,259 Series C Convertible Preferred Units(1)	 	 	544,066	 	

(1)
Kosmos Energy Holdings' financial statements reflect that the proceeds from the Series C funding were allocated on a relative fair value basis between the Series C Convertible Preferred Units and the C1 Common Units.

        During the fiscal year ended December 31, 2010, Kosmos Energy Holdings did not issue any unregistered securities. To date, during the current fiscal year, Kosmos Energy Holdings has not issued any unregistered securities. To date, during the current fiscal year, Kosmos Energy Ltd. has issued one common share in connection with its incorporation under the laws of Bermuda.

II-3

Item 16.    Exhibits and Financial Statement Schedules.
(a)
The following exhibits are filed as part of this registration statement:
 	 	 	 	
Exhibit
Number	 	Description of Document	
 	1.1	 	Form of Underwriting Agreement*******	

3.1	
 	
Certificate of Incorporation of Kosmos Energy Ltd. (the "Company")****	

3.2	
 	
Memorandum of Association of the Company****	

3.3	
 	
Form of Bye-laws of the Company*****	

3.4	
 	
Fourth Amended and Restated Operating Agreement of Kosmos Energy Holdings (the "Predecessor"), as amended*****	

3.5	
 	
Memorandum of Association of the Predecessor****	

3.6	
 	
Articles of Association of the Predecessor****	

4.1	
 	
Specimen share certificate*******	

5.1	
 	
Opinion of Conyers Dill & Pearman Limited*******	

9.1	
 	
Form of Shareholders Agreement.*****	

10.1	
 	
Petroleum Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 22, 2004 among the Ghana National Petroleum Corporation ("GNPC"), Kosmos Energy Ghana HC ("Kosmos Ghana") and the E.O. Group Limited ("E.O. Group").***	

10.2	
 	
Operating Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 27, 2004 between Kosmos Ghana and E.O. Group.***	

10.3	
 	
Petroleum Agreement in respect of the Deepwater Tano Contract Area dated March 10, 2006 among GNPC, Tullow Ghana Limited ("Tullow Ghana"), Sabre Oil and Gas Limited ("Sabre") and Kosmos Ghana.***	

10.4	
 	
Joint Operating Agreement in respect of the Deepwater Tano Contract Area, Offshore Ghana dated August 14, 2006, among Tullow Ghana, Sabre Oil and Gas Limited, and Kosmos Ghana.***	

10.5	
 	
Assignment Agreement in respect of the Deepwater Tano Block dated September 1, 2006, among Anadarko WCTP Company ("Anadarko WCTP") and Kosmos Ghana.***	

10.6	
 	
Unitization and Unit Operating Agreement covering the Jubilee Field Unit located offshore the Republic of Ghana dated July 13, 2009, among GNPC, Tullow, Kosmos Ghana, Anadarko WCTP, Sabre and E.O. Group.***	

10.7	
 	
Atwood Hunter Offshore Drilling Contract dated June 23, 2008 among Kosmos Ghana, Alpha Offshore Drilling Services Company and Noble Energy EG Ltd., as amended.****	

10.8	
 	
Ndian River Production Sharing Contract dated November 20, 2006 between the Republic of Cameroon and Kosmos Energy Cameroon HC ("Kosmos Cameroon").***	

10.9	
 	
Decree 2005/249 dated June 30, 2005 granting Perenco Oil and Gas (Cameroon) Ltd. ("Perenco") and Société Nationale des Hydrocarbures ("SNH") the Kombe-N'sepe Permit.***	

10.10	
 	
Contract of Association relating to the Kombe-N'sepe Permit dated December 11, 1997 between the Republic of Cameroon, CMS Nomeco Cameroon Ltd ("CMS Nomeco Cameroon"), Globex Cameroon, LLC ("Globex Cameroon") and SNH.***	
II-4

 	 	 	 	
Exhibit
Number	 	Description of Document	
 	10.11	 	Convention of Establishment relating to the Kombe-N'sepe Permit dated December 11, 1997 between the Republic of Cameroon, CMS Nomeco Cameroon and Globex Cameroon.***	

10.12	
 	
Deed of Assignment of the Kombe-N'sepe Permit, Contract of Association and Convention of Establishment dated November 16, 2005 between Perenco and Kosmos Cameroon.***	

10.13	
 	
Agreement on the Management of Petroleum Operations (JOA) covering the Kombe-N'sepe Permit dated July 3, 2008 among SNH, Perenco and Kosmos Cameroon.***	

10.14	
 	
Petroleum Agreement regarding the exploration for and exploitation of hydrocarbons in the area of interest named Boujdour Offshore dated May 3, 2006 between Office National des Hydrocarbures et des Mines ("ONHYM") and Kosmos Energy Offshore Morocco HC ("Kosmos Morocco").***	

10.15	
 	
Association Contract regarding the exploration for and exploitation of hydrocarbons in the Boujdour Offshore Block dated May 3, 2006 between ONHYM and Kosmos Morocco.***	

10.16	
 	
Memorandum of Understanding regarding a new petroleum agreement covering certain areas of the Boujdour Offshore Block dated September 27, 2010 between ONHYM and Kosmos Morocco.***	

10.17	
 	
Facility Agreement, dated March 28, 2011 among Kosmos Energy Finance International ("Kosmos Finance International"), Kosmos Energy Operating ("Kosmos Operating"), Kosmos Energy International ("Kosmos International"), Kosmos Energy Development ("Kosmos Development") and Kosmos Ghana and the various financial institutions and others party thereto.*******	

10.18	
 	
[Reserved.]	

10.19	
 	
[Reserved.]	

10.20	
 	
Intercreditor Agreement, dated March 28, 2011 among BNP Paribas, Kosmos Finance International, Kosmos Operating, Kosmos International, Kosmos Development, Kosmos Ghana and the various financial institutions and others party thereto.*******	

10.21	
†	
Form of Long Term Incentive Plan*****	

10.22	
†	
Form of Annual Incentive Plan*****	

10.23	
†	
Form of Non-Qualified Stock Option Award Agreement*****	

10.24	
†	
Form of Restricted Stock Award Agreement (Exchange)*****	

10.25	
†	
Form of Restricted Stock Award Agreement (Service Vesting)*****	

10.26	
†	
Form of Restricted Stock Award Agreement (Performance Vesting)*****	

10.27	
 	
Form of Director Indemnification Agreement******	

10.28	
†	
Retirement Agreement dated December 17, 2010 between Kosmos Energy, LLC, Kosmos Energy Holdings, James C. Musselman, Musselman-Kosmos, Ltd. and funds affiliated with Warburg Pincus LLC and The Blackstone Group L.P.***	

10.29	
†	
Consulting Agreement dated November 17, 2010 between Kosmos Energy Holdings and John R. Kemp***	

10.30	
†	
Form of Executive Employment Agreement*****	
II-5

 	 	 	 	
Exhibit
Number	 	Description of Document	
 	10.31	 	Letter agreement, dated May 4, 2010 among Tullow Ghana Limited, Anadarko WCTP Company and Kosmos Ghana****	

10.32	
 	
Settlement Agreement, dated December 18, 2010 among Kosmos Ghana, Ghana National Petroleum Corporation and the Government of the Republic of Ghana******	

10.33	
 	
Participation Agreement dated June 1, 2004 between Kosmos Ghana and E.O. Group Limited.*******	

21.1	
 	
List of Subsidiaries******	

23.1	
 	
Consent of Ernst & Young LLP	

23.2	
 	
Consent of Netherland, Sewell & Associates, Inc.	

23.3	
 	
Consent of Conyers Dill & Pearman Limited (included in Exhibit 5.1)	

24	
 	
Power of Attorney (included on the signature pages of this registration statement)	

99.1	
 	
Estimate of Reserves and Future Revenue to the Kosmos Energy Interest in the Jubilee Field Phase 1 Development Unit Area located in the West Cape Three Points and Deepwater Tano License Areas Offshore Ghana as of December 31, 2009.*******	

99.2	
 	
Estimate of Reserves and Future Revenue to the Kosmos Energy Interest in the Jubilee Field Phase 1 Development Unit Area located in the West Cape Three Points and Deepwater Tano License Areas Offshore Ghana as of December 31, 2010.*******	

99.3	
 	
Consent of David I. Foley, as director nominee**	

99.4	
 	
Consent of Jeffrey A. Harris, as director nominee**	

99.5	
 	
Consent of David Krieger, as director nominee**	

99.6	
 	
Consent of Prakash A. Melwani, as director nominee**	

99.7	
 	
Consent of Bayo O. Ogunlesi, as director nominee**	

99.8	
 	
Consent of Christopher A. Wright, as director nominee**	

**
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on January 14, 2011.

***
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 3, 2011.

****
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 23, 2011.

*****
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 30, 2011.

******
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on April 14, 2011.

*******
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on April 25, 2011.

†
Management contract or compensatory plan or arrangement.

II-6

(b)
Financial Statement Schedule

Schedule I—Condensed Parent Company Financial Statements

        Under the terms of agreements governing the indebtedness of subsidiaries of Kosmos Energy Holdings ("KEH," the "Parent Company"), such subsidiaries are restricted from making dividend payments, loans or advances to KEH. Schedule I of Article 5-04 of Regulation S-X requires the condensed financial information of the Parent Company to be filed when the restricted net assets of consolidated subsidiaries exceed 25 percent of consolidated net assets as of the end of the most recently completed fiscal year.

        The following condensed parent-only financial statements of KEH have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X and included herein. The Parent Company's 100% investment in its subsidiaries has been recorded using the equity basis of accounting in the accompanying condensed parent-only financial statements. The condensed financial statements should be read in conjunction with the consolidated financial statements of Kosmos Energy Holdings and subsidiaries and notes thereto.

II-7

Kosmos Energy Holdings

(A Development Stage Entity)

Condensed Parent Company Balance Sheets

 
	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Assets	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	51,224	 	$	—	 	
 	Receivables from subsidiaries	 	 	3,878	 	 	—	 	
 	Prepaid expenses and other	 	 	15	 	 	—	 	
 	 	 	 	 	 	
Total current assets	 	 	55,117	 	 	—	 	
Other assets, net of accumulated depreciation and amortization of $773 and $773, respectively	 	 	
2	 	 	
—	 	
Investment in subsidiaries at equity	 	 	540,482	 	 	363,507	 	
 	 	 	 	 	 	
Total assets	 	$	595,601	 	$	363,507	 	
 	 	 	 	 	 	
Liabilities and unit holdings	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	
 	Accounts payable to subsidiaries	 	$	—	 	$	—	 	
 	Accrued liabilities	 	 	213	 	 	—	 	
 	 	 	 	 	 	
Total current liabilities	 	 	213	 	 	—	 	
Convertible preferred units, 100,000 units authorized:	 	 	 	 	 	 	 	
 	Series A—30,000 units issued at December 31, 2009 and 2010	 	 	300,000	 	 	383,246	 	
 	Series B—20,000 units issued at December 31, 2009 and 2010	 	 	500,000	 	 	568,163	 	
 	Series C—885 units issued at December 31, 2009 and 2010	 	 	13,244	 	 	27,097	 	
Unit holdings:	 	 	 	 	 	 	 	
 	Common units, 100,000 units authorized; 18,667 and 19,070 issued at December 31, 2009 and 2010, respectively	 	 	516	 	 	516	 	
 	Additional paid-in capital	 	 	19,108	 	 	—	 	
 	Deficit accumulated during development stage	 	 	(237,480	)	 	(615,515	)	
 	 	 	 	 	 	
Total unit holdings	 	 	(217,856	)	 	(614,999	)	
 	 	 	 	 	 	
Total liabilities, convertible preferred units and unit holdings	 	$	595,601	 	$	363,507	 	
 	 	 	 	 	 	
II-8

Kosmos Energy Holdings

(A Development Stage Entity)

Condensed Parent Company Statements of Operations

 
	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas revenue	 	$	—	 	$	—	 	$	—	 	
 	Interest income	 	 	188	 	 	15	 	 	44	 	
 	 	 	 	 	 	 	 	
Total revenues and other income	 	 	188	 	 	15	 	 	44	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	
 	General and administrative	 	 	4,743	 	 	11,580	 	 	21,187	 	
 	General and administrative—related party	 	 	12,453	 	 	10,663	 	 	16,830	 	
 	Depreciation and amortization	 	 	155	 	 	39	 	 	—	 	
 	Equity in losses of subsidiaries	 	 	31,642	 	 	57,494	 	 	207,697	 	
 	Other expenses, net	 	 	—	 	 	(14	)	 	2	 	
 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	48,993	 	 	79,762	 	 	245,716	 	
 	 	 	 	 	 	 	 	
Loss before income taxes	 	 	
(48,805	
)	 	
(79,747	
)	 	
(245,672	
)	
Income tax expense	 	 	—	 	 	—	 	 	—	 	
 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(245,672	)	
 	 	 	 	 	 	 	 	
II-9

Kosmos Energy Holdings

(A Development Stage Entity)

Condensed Parent Company Statements of Cash Flows

 
	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Operating activities	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(245,672	)	
Adjustments to reconcile net loss to net cash used in operating activities:	 	 	 	 	 	 	 	 	 	 	
 	Equity in losses of subsidiaries	 	 	31,642	 	 	57,494	 	 	207,697	 	
 	Depreciation and amortization	 	 	155	 	 	39	 	 	—	 	
 	Unit-based compensation	 	 	3,671	 	 	3,468	 	 	13,791	 	
 	Changes in assets and liabilities:	 	 	 	 	 	 	 	 	 	 	
 	 	(Increase) decrease in prepaid expenses and other	 	 	(47	)	 	32	 	 	15	 	
 	 	(Increase) decrease due to/from related party	 	 	1,008	 	 	(10,171	)	 	3,878	 	
 	 	Decrease in accounts payable	 	 	(75	)	 	—	 	 	—	 	
 	 	Increase (decrease) in accrued liabilities	 	 	—	 	 	213	 	 	(213	)	
 	 	 	 	 	 	 	 	
Net cash used in operating activities	 	 	(12,451	)	 	(28,672	)	 	(20,504	)	
Investing activities	 	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	 	 	(320,205	)	 	(245,496	)	 	(30,722	)	
Other property	 	 	—	 	 	(2	)	 	2	 	
 	 	 	 	 	 	 	 	
Net cash used in investing activities	 	 	(320,205	)	 	(245,498	)	 	(30,720	)	
Financing activities	 	 	 	 	 	 	 	 	 	 	
Net proceeds from issuance of units	 	 	332,656	 	 	325,344	 	 	—	 	
 	 	 	 	 	 	 	 	
Net cash provided by financing activities	 	 	332,656	 	 	325,344	 	 	—	 	
 	 	 	 	 	 	 	 	
Net increase (decrease) in cash and cash equivalents	 	 	
—	 	 	
51,174	 	 	
(51,224	
)	
Cash and cash equivalents at beginning of period	 	 	50	 	 	50	 	 	51,224	 	
 	 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	 	$	50	 	$	51,224	 	$	—	 	
 	 	 	 	 	 	 	 	
II-10

Kosmos Energy Holdings

(A Development Stage Entity)

Valuation and Qualifying Accounts

For the Years Ended December 31, 2008, 2009 and 2010

 
	 	 
	 	Additions	 	 

Description
	 	Balance
January 1	 	Charged to
Costs and
Expenses	 	Charged
to Other
Accounts	 	Deductions
From
Reserves	 	Balance
December 31	 	
 
	 	(In thousands)
	 	
2008	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for doubtful receivables	 	
$	
—	 	
$	
—	 	
$	
—	 	
$	
—	 	
$	
—	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for deferred tax asset	 	
$	
9,404	 	
$	
9,727	 	
$	
—	 	
$	
—	 	
$	
19,131	 	
 	 	 	 	 	 	 	 	 	 	 	 	
2009	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for doubtful receivables	 	
$	
—	 	
$	
—	 	
$	
—	 	
$	
—	 	
$	
—	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for deferred tax asset	 	
$	
19,131	 	
$	
14,618	 	
$	
—	 	
$	
—	 	
$	
33,749	 	
 	 	 	 	 	 	 	 	 	 	 	 	
2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for doubtful receivables	 	
$	
—	 	
$	
39,782	 	
$	
—	 	
$	
—	 	
$	
39,782	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for deferred tax asset	 	
$	
33,749	 	
$	
(3,609	
)	
$	
—	 	
$	
—	 	
$	
30,140	 	
 	 	 	 	 	 	 	 	 	 	 	 	
II-11

Item 17.    Undertakings.

        (a)   The undersigned registrant hereby undertakes:

        (1)   To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

            i.  To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;

           ii.  To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20 percent change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in the effective registration statement.

          iii.  To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

        (2)   That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

        (3)   To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

        (4)   That in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

            i.  Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

           ii.  Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

          iii.  The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

          iv.  Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

        (b)   The undersigned hereby undertakes to provide to the underwriter at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriter to permit prompt delivery to each purchaser.

        (c)   Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and

II-12

Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer, or controlling person of the registrant in the successful defense of any action, suit, or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

        (d)   The undersigned registrant hereby undertakes that:

        (1)   For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

        (2)   For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-13

SIGNATURES

        Pursuant to the requirements of the Securities Act of 1933, the Registrant certifies that it has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Dallas, Texas on April 25, 2011.
 	 	 	 	 	
 	 	Kosmos Energy Ltd.	
 	 	By:	 	/s/ BRIAN F. MAXTED

Brian F. Maxted
Director and Chief Executive Officer	
        Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities held on the dates indicated.
 	 	 	 	 	
SIGNATURE	 	TITLE	 	DATE	

 	

 	
/s/ BRIAN F. MAXTED

Brian F. Maxted	 	Director and Chief Executive Officer (Principal Executive Officer)	 	April 25, 2011	

/s/ W. GREG DUNLEVY

W Greg. Dunlevy	
 	
Chief Financial Officer and Executive Vice President (Principal Financial Officer)	
 	
April 25, 2011	

/s/ SYLVIA MANOR

Sylvia Manor	
 	
Vice President and Controller
(Principal Accounting Officer)	
 	
April 25, 2011	

    *

John R. Kemp	
 	
Chairman of the Board of Directors	
 	
April 25, 2011	

    *

David I. Foley	
 	
Director	
 	
April 25, 2011	

    *

Jeffrey A. Harris	
 	
Director	
 	
April 25, 2011	

    *

David B. Krieger	
 	
Director	
 	
April 25, 2011	

    *

Prakash A. Melwani	
 	
Director	
 	
April 25, 2011	

    *

Adebayo O. Ogunlesi	
 	
Director	
 	
April 25, 2011	

    *

Chris Tong	
 	
Director	
 	
April 25, 2011	

    *

Christopher A. Wright	
 	
Director	
 	
April 25, 2011	

*By:	 	/s/ BRIAN F. MAXTED

Brian F. Maxted
Attorney-in-Fact	 	 	
II-14

INDEX OF EXHIBITS

Exhibit
Number	 	Description of Document	
 	1.1	 	Form of Underwriting Agreement*******	

3.1	
 	
Certificate of Incorporation of the Company****	

3.2	
 	
Memorandum of Association of the Company****	

3.3	
 	
Form of Bye-laws of the Company*****	

3.4	
 	
Fourth Amended and Restated Operating Agreement of the Predecessor, as amended*****	

3.5	
 	
Memorandum of Association of the Predecessor****	

3.6	
 	
Articles of Association of the Predecessor****	

4.1	
 	
Specimen share certificate*******	

5.1	
 	
Opinion of Conyers Dill & Pearman Limited*******	

9.1	
 	
Form of Shareholders Agreement.*****	

10.1	
 	
Petroleum Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 22, 2004 among the GNPC, Kosmos Ghana and the E.O. Group.***	

10.2	
 	
Operating Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 27, 2004 between Kosmos Ghana and E.O. Group.***	

10.3	
 	
Petroleum Agreement in respect of the Deepwater Tano Contract Area dated March 10, 2006 among GNPC, Tullow Ghana, Sabre and Kosmos Ghana.***	

10.4	
 	
Joint Operating Agreement in respect of the Deepwater Tano Contract Area, Offshore Ghana dated August 14, 2006, among Tullow Ghana, Sabre Oil and Gas Limited, and Kosmos Ghana.***	

10.5	
 	
Assignment Agreement in respect of the Deepwater Tano Block dated September 1, 2006, among Anadarko WCTP and Kosmos Ghana.***	

10.6	
 	
Unitization and Unit Operating Agreement covering the Jubilee Field Unit located offshore the Republic of Ghana dated July 13, 2009, among GNPC, Tullow, Kosmos Ghana, Anadarko WCTP, Sabre and E.O. Group.***	

10.7	
 	
Atwood Hunter Offshore Drilling Contract dated June 23, 2008 among Kosmos Ghana, Alpha Offshore Drilling Services Company and Noble Energy EG Ltd., as amended.****	

10.8	
 	
Ndian River Production Sharing Contract dated November 20, 2006 between the Republic of Cameroon and Kosmos Cameroon.***	

10.9	
 	
Decree 2005/249 dated June 30, 2005 granting Perenco and SNH the Kombe-N'sepe Permit.***	

10.10	
 	
Contract of Association relating to the Kombe-N'sepe Permit dated December 11, 1997 between the Republic of Cameroon, CMS Nomeco Cameroon, Globex Cameroon and SNH.***	

10.11	
 	
Convention of Establishment relating to the Kombe-N'sepe Permit dated December 11, 1997 between the Republic of Cameroon, CMS Nomeco Cameroon and Globex Cameroon.***	

10.12	
 	
Deed of Assignment of the Kombe-N'sepe Permit, Contract of Association and Convention of Establishment dated November 16, 2005 between Perenco and Kosmos Cameroon.***	

10.13	
 	
Agreement on the Management of Petroleum Operations (JOA) covering the Kombe-N'sepe Permit dated July 3, 2008 among SNH, Perenco and Kosmos Cameroon.***	

 	 	 	 	
Exhibit
Number	 	Description of Document	
 	10.14	 	Petroleum Agreement regarding the exploration for and exploitation of hydrocarbons in the area of interest named Boujdour Offshore dated May 3, 2006 between ONHYM and Kosmos Morocco.***	

10.15	
 	
Association Contract regarding the exploration for and exploitation of hydrocarbons in the Boujdour Offshore Block dated May 3, 2006 between ONHYM and Kosmos Morocco.***	

10.16	
 	
Memorandum of Understanding regarding a new petroleum agreement covering certain areas of the Boujdour Offshore Block dated September 27, 2010 between ONHYM and Kosmos Morocco.***	

10.17	
 	
Facility Agreement, dated March 28, 2011 among Kosmos Finance International, Kosmos Operating, Kosmos International, Kosmos Development and Kosmos Ghana and the various financial institutions and others party thereto.*******	

10.18	
 	
[Reserved.]	

10.19	
 	
[Reserved.]	

10.20	
 	
Intercreditor Agreement, dated March 28, 2011 among BNP Paribas, Kosmos Finance International, Kosmos Operating, Kosmos International, Kosmos Development, Kosmos Ghana and the various financial institutions and others party thereto.*******	

10.21	
†	
Form of Long Term Incentive Plan*****	

10.22	
†	
Form of Annual Incentive Plan*****	

10.23	
†	
Form of Non-Qualified Stock Option Award Agreement*****	

10.24	
†	
Form of Restricted Stock Award Agreement (Exchange)*****	

10.25	
†	
Form of Restricted Stock Award Agreement (Service Vesting)*****	

10.26	
†	
Form of Restricted Stock Award Agreement (Performance Vesting)*****	

10.27	
 	
Form of Director Indemnification Agreement******	

10.28	
†	
Retirement Agreement dated December 17, 2010 between Kosmos Energy, LLC, Kosmos Energy Holdings, James C. Musselman, Musselman-Kosmos, Ltd. and funds affiliated with Warburg Pincus LLC and The Blackstone Group L.P.***	

10.29	
†	
Consulting Agreement dated November 17, 2010 between Kosmos Energy Holdings and John R. Kemp***	

10.30	
†	
Form of Executive Employment Agreement*****	

10.31	
 	
Letter agreement, dated May 4, 2010 among Tullow Ghana Limited, Anadarko WCTP Company and Kosmos Ghana****	

10.32	
 	
Settlement Agreement, dated December 18, 2010 among Kosmos Ghana, Ghana National Petroleum Corporation and the Government of the Republic of Ghana******	

10.33	
 	
Participation Agreement date June 1, 2004 between Kosmos Ghana and E.O. Group Limited.*******	

21.1	
 	
List of Subsidiaries******	

23.1	
 	
Consent of Ernst & Young LLP	

23.2	
 	
Consent of Netherland, Sewell & Associates, Inc.	

23.3	
 	
Consent of Conyers Dill & Pearman Limited (included in Exhibit 5.1)	

24	
 	
Power of Attorney (included on the signature pages of this registration statement)	

 	 	 	 	
Exhibit
Number	 	Description of Document	
 	99.1	 	Estimate of Reserves and Future Revenue to the Kosmos Energy Interest in the Jubilee Field Phase 1 Development Unit Area located in the West Cape Three Points and Deepwater Tano License Areas Offshore Ghana as of December 31, 2009.*******	

99.2	
 	
Estimate of Reserves and Future Revenue to the Kosmos Energy Interest in the Jubilee Field Phase 1 Development Unit Area located in the West Cape Three Points and Deepwater Tano License Areas Offshore Ghana as of December 31, 2010.*******	

99.3	
 	
Consent of David I. Foley, as director nominee**	

99.4	
 	
Consent of Jeffrey A. Harris, as director nominee**	

99.5	
 	
Consent of David Krieger, as director nominee**	

99.6	
 	
Consent of Prakash A. Melwani, as director nominee**	

99.7	
 	
Consent of Bayo O. Ogunlesi, as director nominee**	

99.8	
 	
Consent of Christopher A. Wright, as director nominee**	

**
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on January 14, 2011.

***
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 3, 2011.

****
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 23, 2011.

*****
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 30, 2011.

******
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on April 14, 2011.

*******
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on April 25, 2011.

†
Management contract or compensatory plan or arrangement.

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

        We consent to the reference to our firm under the caption "Experts" and to the use of our report dated March 2, 2011, related to the consolidated financial statements and schedules of Kosmos Energy Holdings in Amendment No. 6 to the Registration Statement (Form S-1) and related Prospectus of Kosmos Energy Ltd. for the registration of its common stock.
 	 	 	
 	 	/s/ Ernst & Young LLP	
Dallas, Texas
April 25, 2011

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Exhibit 23.1

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Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

        We hereby consent to the reference of our firm and to the use of our reports of Kosmos Energy Ltd. as of December 31, 2009, dated February 4, 2010, and as of December 31, 2010, dated April 19, 2011, in this Form S-1 Registration Statement and the related Prospectus to be filed on or about April 25, 2011. We also consent to the reference to us under the heading "Experts" in such Registration Statement and the Prospectus to which the Registration Statement is related.
 	 	 	 	 	
 	 	NETHERLAND, SEWELL & ASSOCIATES, INC.	

 	
By:	
 	
/s/ C.H. (SCOTT) REES III

C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer	
Dallas, Texas
April 25, 2011

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Exhibit 23.2