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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

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As filed with the Securities and Exchange Commission on January 13, 2011

Registration No. 333-

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

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) 295-1422
(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 Ltd.
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

Title of each Class of Security being registered	Proposed Maximum Aggregate Offering Price(1)	Amount of Registration Fee




Common Shares, $0.01 par value per share(2)	$500,000,000	$58,050

(1): Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.
(2): Includes common shares which may be issued on exercise of a 30-day option granted to the underwriters to cover over-allotments, if any.

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 JANUARY 13, 2011

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 $ and $ per share. We intend to apply to list our common shares on the New York Stock Exchange under the symbol "KOS."

The underwriters have an option to purchase a maximum of 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 19.

	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 , 2010.

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.


Credit Suisse		Citi
Barclays Capital

The date of this prospectus is , 2011.

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		Page

PROSPECTUS SUMMARY		1
RISK FACTORS		19
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		48
DIVIDEND POLICY		50
USE OF PROCEEDS		51
CORPORATE REORGANIZATION		52
CAPITALIZATION		53
DILUTION		55
SELECTED HISTORICAL AND PRO FORMA FINANCIAL INFORMATION		56
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		59
INDUSTRY		75
BUSINESS		84
MANAGEMENT		120
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		135
PRINCIPAL SHAREHOLDERS		136
DESCRIPTION OF SHARE CAPITAL		139
SHARES ELIGIBLE FOR FUTURE SALE		146
CERTAIN TAX CONSIDERATIONS		148
UNDERWRITING		151
LEGAL MATTERS		158
EXPERTS		158
WHERE YOU CAN FIND ADDITIONAL INFORMATION		158
GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS		159
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 159.

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 high-impact 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 five 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 anticipate receiving our first oil revenues in early 2011. We expect gross oil production from the Jubilee Field to reach its design capacity of 120,000 barrels of oil per day ("bopd") in mid 2011.

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 three other discoveries in the appraisal and pre-development stage: Odum, Tweneboa and Enyenra (formerly known as Owo). To date we have identified 49 undrilled prospects within our existing license areas, including 20 prospects across three play types offshore Ghana, 10

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prospects across three play types in Cameroon and 19 prospects across three play types offshore Morocco. The following table summarizes our existing licenses and their current development status.

License			Location	Discovered Fields (Year of Discovery)

*Ghana*
West Cape Three Points ("WCTP")(1)	369,917		Gulf of Guinea's	Jubilee (2007)(3)	13/14	13	30.875	%(4)
			Tano Basin	Odum (2008)
				Mahogany East (2009)
Deepwater Tano ("DT")	205,345		Gulf of Guinea's	Jubilee (2007)(3)	14/15	7	18.000	%(5)
			Tano Basin	Tweneboa (2009)
				Enyenra (2010)
*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	(2)	Coastal strip of	—	—	4	100.000	%(7)
			Rio del Rey Basin
			bordering the Gulf
			of Guinea
*Morocco*
Boujdour Offshore(1)	10,869,654		Northwest Africa's	—	—	19	75.000	%(8)
			Aaiun Basin

(1): Kosmos is the operator under these licenses.
(2): This acreage reflects the relinquishment of 30% of the current license area of the Ndian River Block upon the approval by Cameroon's Ministry of Industry, Mines and Technological Development of the two year renewal of our exploration period for this block.
(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. 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 Cameroon's entitlement. This interest percentage does not give effect to this back-in.

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(7): Cameroon has an option to acquire an interest of up to 15.0% in a commercial discovery on the Ndian River Block. If 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): The Office National des Hydrocarbures et des Mines, the national oil company of Morocco ("ONHYM"), is the only other Boujdour Offshore Block partner and has a 25% participating interest, which will be carried through the exploration phase.

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 development plans for the Odum, Tweneboa and Enyenra 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 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 a high-quality 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

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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 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 four 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"). This sale was terminated in August 2010. 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 discovery offshore Ghana and drilled six successful appraisal wells on our Mahogany East, Odum and Tweneboa 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 five 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 and Enyenra offshore Ghana, which have geologic characteristics similar to the Jubilee Field. In addition, we have identified 20 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.

Well-defined production and growth plan

Our plan for developing the Jubilee Field provides highly visible, near-term cash generation and long-term growth opportunities. We estimate Jubilee Field Phase 1 daily gross production to reach the

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120,000 bopd design capacity of the floating production, storage and offloading ("FPSO") facility used at the field, in mid 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 the full Jubilee Field on a faster timeline and allowed us to achieve first oil production at an earlier date than traditional development techniques. 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 and Enyenra 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. For instance, we are currently drilling the Teak-1 exploration well north of the Jubilee Field. We plan to drill two exploratory wells in Cameroon, one on our Kombe-N'sepe Block 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, we expect oil from the Jubilee Field will ultimately command 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 high-quality 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 a high-impact new venture 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.

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

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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 early 2013. As of September 30, 2010, we had approximately $292 million of total cash on hand, including $89 million of restricted cash, and $300 million of committed undrawn capacity under our commercial debt facilities. In addition, we have demonstrated the ability to raise capital, having secured commitments for approximately $1.1 billion of private equity funding and $1.25 billion of commercial debt commitments in the last seven years. Furthermore, we anticipate receiving our first oil revenues in early 2011 from the Jubilee Field, after which time a portion of these revenues will be used to fund future exploration and development activities.

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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 successful 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 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 and Enyenra. 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 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 anticipate receiving 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

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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.

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 extremely 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 us a significant 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 high-quality 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 June 30, 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 59 Mmboe as of June 30, 2010, consisting of approximately 94% 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 and other Jubilee Field phases, do not yet have approved plans of development ("PoDs") and therefore cannot be classified as proved reserves.

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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 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.

Once the drilling and completion activity associated with the Jubilee Field Phase 1 development is complete, the Eirik Raude, Atwood Hunter and Deepwater Millennium drilling rigs 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 and Enyenra discoveries over the next three years.

Discovery Information

Information about our discoveries is summarized in the following table.

Discoveries		License			Block Operator(s)	Stage	Type

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
	Tweneboa	DT(4)	18.0000	%	Tullow	Appraisal	Deepwater	2012	(7)
	Enyenra	DT(4)	18.0000	%	Tullow	Appraisal	Deepwater	2013

(1): For information concerning our estimated proved reserves in the Jubilee Field as of June 30, 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 anticipate receiving 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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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)			Status(2)	Comments

Jubilee
J-09 (Mahogany-1)		Kosmos	05/30/07	12,553	321	Completion Pending	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	Completion Pending	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	Production Ready
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)			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
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.
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		Block Operator	Type	Projected Spud Year(3)

Ghana(1)
	Teak	WCTP	30.875	Kosmos	Deepwater	2010
	Banda Campanian	WCTP	30.875	Kosmos	Deepwater	2011
	Banda Cenomanian	WCTP	30.875	Kosmos	Deepwater	2011
	Makore	WCTP	30.875	Kosmos	Deepwater	2011
	Odum East	WCTP	30.875	Kosmos	Deepwater	2011
	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
	Tweneboa Deep	DT	18.000	Tullow	Deepwater	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
	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(4)
	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): 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. 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): 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."
(4): We have not yet made a decision as to whether or not to continue into the drilling phase of the license. If we do, we anticipate the first well to drill within the Boujdour Offshore Block will be post 2012.

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Recent Events

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.

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. Along with the proceeds from this offering, these funds will support our share of the Jubilee Field Phase 1 development, appraisal of additional discoveries, and ongoing exploration activities.

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).

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Risks Associated with our Business

Please read the section entitled "Risk Factors" for a discussion of some of the factors you should carefully consider before deciding to invest in our common shares.

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 HM11, Bermuda. Our registered offices are located at Clarendon House, 2 Church Street, Hamilton HM11, Bermuda. The telephone number of our registered offices is (441) 295-1422. 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		common shares
Common shares to be issued and outstanding after this offering		common shares
Over-allotment option		We have granted to the underwriters an option, exercisable upon notice to us, to purchase up to 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 early 2013 and associated operating expenses, and for general corporate purposes. See "Use of Proceeds" on page 51 of this prospectus for a more detailed description of our intended use of the proceeds from this offering.
Listing		We intend to apply to have our common shares listed on the New York Stock Exchange (the "NYSE") under the symbol "KOS."

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 $ 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 $ per common share, the aggregate number of common shares issuable as a result of the conversion 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 conversion 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 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, 2005, 2006, 2007, 2008 and 2009 and the consolidated balance sheets as of December 31, 2005, 2006, 2007, 2008 and 2009 were derived from Kosmos Energy Holdings' audited consolidated financial statements. We derived the consolidated statements of operations and cash flows for the nine months ended September 30, 2009 and 2010 and for the period April 23, 2003 (Inception) through September 30, 2010, and the consolidated balance sheets as of September 30, 2009 and 2010 from Kosmos Energy Holdings' unaudited consolidated financial data appearing elsewhere in this prospectus, which, in management's opinion, includes all adjustments necessary for the fair presentation of Kosmos Energy Holdings' financial condition as of such date and Kosmos Energy Holdings' results of operations for such periods. Results of operations for the nine months ended September 30, 2010 are not necessarily indicative of the results of operations that may be achieved for the entire year. The summary unaudited pro forma financial data set forth below is derived from Kosmos Energy Holdings' audited and unaudited consolidated financial statements appearing elsewhere in this prospectus and is based on assumptions and includes adjustments as explained in the notes to the tables.

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Consolidated Statements of Operations Information:

																								Period April 23, 2003 (Inception) through September 30 2010

			Year Ended December 31															Nine Months Ended September 30
			2005			2006			2007			2008			2009			2009			2010
																		(Unaudited)			(Unaudited)			(Unaudited)
			(In thousands)
Revenues and other income:
	Oil and gas revenue		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
	Interest income			252			445			1,568			1,637			985			595			2,548			7,459
	Other income			1,822			3,100			2			5,956			9,210			7,578			3,793			25,383

		Total revenues and other income		2,074			3,545			1,570			7,593			10,195			8,173			6,341			32,842
Costs and expenses:
	Exploration expenses, including dry holes			6,718			9,083			39,950			15,373			22,127			17,191			52,764			146,088
	General and administrative			7,801			9,588			18,556			40,015			55,619			43,425			50,804			188,002
	Depreciation and amortization			340			401			477			719			1,911			1,369			1,655			5,737
	Amortization—debt issue costs			—			—			—			—			2,492			—			20,555			23,047
	Interest expense			—			—			8			1			6,774			—			45,645			52,452
	Derivatives, net			—			—			—			—			—			—			15,310			15,310
	Equity in losses of joint venture			5,157			9,194			2,632			—			—			—			—			16,983
	Other expenses, net			7			7			17			21			46			39			20			875

		Total costs and expenses		20,023			28,273			61,640			56,129			88,969			62,024			186,753			448,494

Loss before income taxes				(17,949	)		(24,728	)		(60,070	)		(48,536	)		(78,774	)		(53,851	)		(180,412	)		(415,652	)
Income tax expense (benefit)				—			—			718			269			973			30			(174	)		1,786

Net loss			$	(17,949	)	$	(24,728	)	$	(60,788	)	$	(48,805	)	$	(79,747	)	$	(53,881	)	$	(180,238	)	$	(417,438	)

Pro forma net loss (unaudited)(1):
Pro forma basic and diluted net loss per common share															$						$

Weighted average common shares outstanding used in pro forma basic and diluted net loss per common share															$						$

(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. The weighted average common shares outstanding have been calculated as if the owenership structure resulting from the corporate reorganization was in place since inception. Pro forma information does not give effect to this offering.

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Consolidated Balance Sheets Information:

	As of December 31															As of September 30						Pro Forma as Adjusted as of September 30 2010(1)

	2005			2006			2007			2008			2009			2009			2010			Pro Forma as Adjusted as of September 30 2010(1)
																(Unaudited)			(Unaudited)			(Unaudited)
	(In thousands)
Cash and cash equivalents	$	14,349		$	9,837		$	39,263		$	147,794		$	139,505		$	60,818		$	202,846		$
Total current assets		16,346			10,334			65,960			205,708			256,728			176,536			491,638
Total property and equipment		3,788			1,567			18,022			208,146			604,007			492,202			884,628
Total other assets		727			3,704			3,393			1,611			161,322			22,650			175,622
Total assets		20,861			15,605			87,375			415,465			1,022,057			691,388			1,551,888
Total current liabilities		430			1,436			28,574			68,698			139,647			143,829			168,310
Total long-term liabilities		1,312			—			—			444			287,022			1,902			967,211
Total convertible preferred units		41,937			61,952			167,000			499,656			813,244			750,065			813,244
Total unit holdings		(22,818	)		(47,783	)		(108,199	)		(153,333	)		(217,856	)		(204,408	)		(396,877	)
Total liabilities, convertible preferred units and unit holdings		20,861			15,605			87,375			415,465			1,022,057			691,388			1,551,888

(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 September 30 2010

	Year Ended December 31															Nine Months Ended September 30
	2005			2006			2007			2008			2009			2009			2010
																(Unaudited)			(Unaudited)			(Unaudited)
	(In thousands)
Net cash provided by (used in):
Operating activities	$	(13,978	)	$	(9,617	)	$	(17,386	)	$	(65,671	)	$	(27,591	)	$	(6,506	)	$	(133,180	)	$	(272,389	)
Investing activities		(3,980	)		(14,663	)		(58,161	)		(156,882	)		(500,393	)		(309,801	)		(451,164	)		(1,190,215	)
Financing activities		30,895			19,768			104,973			331,084			519,695			229,331			647,685			1,665,450

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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 plans of development 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, so you should not place undue reliance on any of our measures.

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. While we expect that our current drilling schedule will enable us to retain the rights to develop the prospects we have identified in this prospectus under the agreements currently in place (or, with respect to the Boujdour Offshore Block, expected to be entered shortly), should they 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

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exploration well on the Kombe-N'sepe Block expected to be spud by the end of the first quarter of 2011. Under the 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. We expect that such application will be approved, but upon approval we will be required to relinquish 30% of the 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 current exploration phase expires on February 26, 2011, and 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 current license.

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.

Furthermore, MODEC, Inc. ("MODEC"), the contractor for the FPSO we are using to produce hydrocarbons from the Jubilee Field, has made a disclosure regarding 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. In addition, in order to continue the 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, 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

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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 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. Due to the formulation of our combined holdings in the WCTP and DT Blocks, we do not currently believe that our interests in the Jubilee Unit will decrease. However, 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, 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 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. 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, as the case may be. Dependence on the operator could prevent us from realizing our target returns for those discoveries or prospects. Further, it may be difficult for us to pursue one of our key business strategies of minimizing the cycle time between discovery and initial production with respect to discoveries on license areas for which we do not operate. 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;
•: 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.

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

We have been a development stage entity and will continue to be so until we generate revenue, which we expect to occur from oil production 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 of June 30, 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 extent, quality and reliability of this data can vary. 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. Although the reserve information contained herein is prepared in consultation with independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise.

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.

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

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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 our PV-10 as of June 30, 2010 would decrease by approximately $23.0 million.

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 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;

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•: 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.

While we believe our operations, upon the consummation of this offering, will be adequately funded through early 2013, we do not currently have any commitments for future external funding beyond the capacity of our commercial debt facilities. 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 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");
•: 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;

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•: 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 facilities.

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 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 prices currently paid for natural gas. We will not receive any payment for this quantity of natural gas. Accordingly, there may be limited or no value derived from any natural gas produced from our West African license areas.

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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, 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,

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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, 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 and the Petroleum Law of 1984 (PNDCL 84) (the "Ghanaian Petroleum 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 and the failure to approve the proposed sale of our Ghanaian assets. 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 and 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.

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;

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•: 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 Africa have experienced political instability in the past. Disruptions may occur in the future, and losses caused by these 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

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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. 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. 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 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. While we believe the prospects we have identified in the DT Block to date do not fall within the area implicated by the demarcation, some 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.

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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 Law. We currently believe that such law will only have prospective application, and as such would not modify the terms of our interests under the agreements governing our license interests in Ghana, including the WCTP and DT Petroleum Agreements and the UUOA. However, as this law is still being considered by parliament, there can be no assurance that the final law will not seek to retroactively modify our interests or otherwise affect our current and future operations in Ghana. Any such changes may have a material adverse affect on our business. See "Business—Other Regulation of the Oil and Gas Industry—Ghana."

Furthermore, the explosion and sinking in April 2010 of the Deepwater Horizon oil rig during operations on the Macondo exploration well in the Gulf of Mexico, and the resulting oil spill, may have

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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, 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 maintain insurance at levels that we believe are consistent with industry practices, but we are not fully insured against all risks. 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.

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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 and Regulation."

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. Although the company has implemented strict policies and training programs for its employees on such matters, 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 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 for certain potential FCPA violations by the Jubilee Unit partners and the syndicate of international banks who had committed to refinance the construction costs of the FPSO (a portion of

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such costs were originally loaned by the Jubilee Unit partners, including Kosmos). 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 events under investigation, should the DOJ become involved, 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.

Increased costs of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital or increases in interest rates or a reduction in our credit standing. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling development and operations and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

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Our commercial debt facilities contain 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 facilities include 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 facilities.

Our commercial debt facilities require 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 facilities 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 facilities, 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 facilities, 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 facilities 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 $1.25 billion commercial debt facilities. 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;
•: 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;

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•: 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 the Deepwater 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.

An affiliate of an oil and gas company which holds a participating interest in the Macondo well also owns working interests in the WCTP and DT Blocks, including the Jubilee Unit. As a 25% non-operating interest owner in the Macondo well, such partner 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 such partner and could in turn affect such partner's affiliate'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.

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 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 officer or controlling shareholder 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 or officer, any such business opportunity is expressly offered to such person solely in his or her capacity as our director or officer.

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 our interest and expectancy in any business opportunity that may be from time to time presented to our directors and Investors and 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."

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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 28, 2016, 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 28, 2016, 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 28, 2016.

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 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

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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.

Our business could be affected by recent health care reform and potential federal tax increases.

In March 2010, the Patient Protection and Affordable Care Act ("PPACA") and the Health Care and Education Reconciliation Act of 2010 ("HCERA"), which makes various amendments to certain aspects of the PPACA (the HCERA and, together with PPACA, the "Acts"), were signed into law. Among numerous other items, the Acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy and impose excise taxes on high-cost health plans. We are not a recipient of the Medicare Part D tax benefit and therefore, we will not be impacted by this part of the new legislation. We will continue to monitor the potential impact of these new regulations as details emerge over the next several months and years. At this point in time, we are not aware of any material impacts to us.

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."

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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 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 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

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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 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 % 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" in this prospectus.

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;

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•: 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.

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 facilities 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

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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 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) that has been approved by the board must only be approved by shareholders owning a majority of the 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.

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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. 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 and officers.

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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 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 facilities 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 common shares in this offering will be approximately $ million after deducting estimated offering expenses payable by us of $ million and underwriting discounts and commissions and assuming an initial public offering price of $ per common share (being 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 $ million.

We intend to use the net proceeds from this offering, available cash and borrowings under our commercial debt facilities to fund our capital expenditures, and in particular our exploration and appraisal drilling program and development activities through early 2013, our related operating expenses, and for general corporate purposes. As a result, 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 $400.0 million of capital expenditures for the year ending December 31, 2011. This capital expenditure budget consists of:

•: $135.0 million for development in Ghana;
•: $175.0 million for exploration and appraisal in Ghana;
•: $25.0 million for exploration and appraisal in Cameroon;
•: $25.0 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 $ per common share would increase (decrease) our expected net proceeds by approximately $ 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 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 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 $ (being 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 shares outstanding following the completion of this offering. See "Description of Capital Shares" 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 amended and restated to remove the various classes of units and terminate the rights and obligations of Kosmos Energy Holdings' current unitholders, including the rights of our Investors and management to appoint directors to the board of Kosmos Energy Holdings and the rights of Kosmos Energy Holdings to make any additional capital calls.

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 amendment 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 September 30, 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 September 30, 2010

		Actual			Pro Forma to Give Effect to our Corporate Reorganization(1)		Pro Forma as Adjusted for the Effect of this Offering(1)(2)
		(Unaudited)
		(In thousands, except per share data)
Cash and cash equivalents		$	202,846		$		$
Restricted cash			89,000

	Total Cash	$	291,846		$		$

Short-term debt, including current portion of long-term debt		$	—		$		$
Long-term debt			950,000

	Total Debt		950,000
Series A Convertible Preferred Units; 30,000,000 units outstanding, actual			300,000			—		—
Series B Convertible Preferred Units; 20,000,000 units outstanding, actual			500,000			—		—
Series C Convertible Preferred Units; 884,956 units outstanding, actual			13,244			—		—

	Total Convertible Preferred Units		813,244			—		—
Common Units; 18,689,162 units outstanding, actual			516			—		—
Common shares, $0.01 par value per share; shares issued and outstanding, pro forma to give effect to our corporate reorganization(3); shares issued and outstanding, pro forma as adjusted for the effect of this offering(4)			—
Additional paid-in capital			20,780
Deficit accumulated during development stage/Retained deficit			(417,718	)
Accumulated other comprehensive income (loss)			(455	)

	Total Unit Holdings capital/Shareholders' equity		(396,877	)

	Total Capitalization	$	1,366,367		$		$

(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 common shares contemplated by this offering at an assumed initial public offering price of $ per common share (the midpoint of the estimated

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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 assumed initial public offering price would result in approximately a $ 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, (ii) all unvested units and (iii) any units reserved for future issuance, will be converted 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 converted into ; ; and common shares, respectively, or common shares in the aggregate. common shares issued and outstanding, pro forma to give effect to our corporate reorganization, excludes (i) unvested shares granted to management and employees in connection with our corporate reorganization and (ii) common shares which were reserved for issuance pursuant to our long-term incentive plan. Any increase or decrease in the initial public offering price from the assumed offering price of $ 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): common shares issued and outstanding, pro forma as adjusted for the effect of this offering, includes common shares issued pursuant to this offering and excludes (i) unvested common shares granted to management and employees in connection with our corporate reorganization and (ii) common shares which were reserved for issuance pursuant to our long-term incentive plan.

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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 September 30, 2010 after giving effect to our corporate reorganization was $ or $ per common share, based on common shares issued and outstanding prior to the closing of this offering. After giving effect to our corporate reorganization and the sale of common shares by us in this offering at an assumed initial public offering price of $ 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 September 30, 2010, would be $ , or $ per share. This represents an immediate increase in the pro forma net tangible book value of $ per share to existing shareholders and an immediate dilution of $ per share to new investors purchasing common shares in this offering. The following table illustrates this per share dilution:


Assumed initial public offering price		$
Pro forma net tangible book value per share as of September 30, 2010 after giving effect to our corporate reorganization	$
Increase per share attributable to this offering	$

Pro forma net tangible book value per share after giving effect to our corporate reorganization and this offering		$

Dilution per share to new investors in this offering		$

The following table shows, at September 30, 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 share by existing shareholders and by new investors purchasing common shares in this offering:

	Common Shares Purchased

					Total Consideration
					Total Consideration					Average Price Per Common Share
	Number	Percentage			Amount		Percentage			Average Price Per Common Share
Existing shareholders				%	$	(1)			%	$
New investors				%	$				%	$
Total			100.00	%	$			100.00	%	$

(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 % and will increase the number of common shares held by new investors to , or %. This information is based on common shares issued and outstanding as of September 30, 2010, after giving effect to our corporate reorganization. No material change has occurred to our equity capitalization since September 30, 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 $ 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 $ 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, 2005, 2006, 2007, 2008 and 2009 and the consolidated balance sheets as of December 31, 2005, 2006, 2007, 2008 and 2009 were derived from Kosmos Energy Holdings' audited consolidated financial statements. We derived the consolidated statements of operations and cash flows for the nine months ended September 30, 2009 and 2010, for the period April 23, 2003 (Inception) through September 30, 2010, and the consolidated balance sheets as of September 30, 2009 and 2010, from Kosmos Energy Holdings' unaudited consolidated financial information appearing elsewhere in this prospectus, which, in management's opinion, includes all adjustments necessary for the fair presentation of Kosmos Energy Holdings' financial condition as of such date and Kosmos Energy Holdings' results of operations for such periods. Results of operations for the nine months ended September 30, 2010, are not necessarily indicative of the results of operations that may be achieved for the entire year. The unaudited pro forma information is derived from Kosmos Energy Holdings' audited and unaudited consolidated financial statements appearing elsewhere in this document 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 September 30 2010

			Year Ended December 31															Nine Months Ended September 30
			2005			2006			2007			2008			2009			2009			2010
																		(Unaudited)			(Unaudited)			(Unaudited)
			(In thousands)
Revenues and other income:
	Oil and gas revenue		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
	Interest income			252			445			1,568			1,637			985			595			2,548			7,459
	Other income			1,822			3,100			2			5,956			9,210			7,578			3,793			25,383

		Total revenues and other income		2,074			3,545			1,570			7,593			10,195			8,173			6,341			32,842
Costs and expenses:
	Exploration expenses, including dry holes			6,718			9,083			39,950			15,373			22,127			17,191			52,764			146,088
	General and administrative			7,801			9,588			18,556			40,015			55,619			43,425			50,804			188,002
	Depreciation and amortization			340			401			477			719			1,911			1,369			1,655			5,737
	Amortization—debt issue costs			—			—			—			—			2,492			—			20,555			23,047
	Interest expense			—			—			8			1			6,774			—			45,645			52,452
	Derivatives, net			—			—			—			—			—			—			15,310			15,310
	Equity in losses of joint venture			5,157			9,194			2,632			—			—			—			—			16,983
	Other expenses, net			7			7			17			21			46			39			20			875

		Total costs and expenses		20,023			28,273			61,640			56,129			88,969			62,024			186,753			448,494

Loss before income taxes				(17,949	)		(24,728	)		(60,070	)		(48,536	)		(78,774	)		(53,851	)		(180,412	)		(415,652	)
Income tax expense (benefit)				—			—			718			269			973			30			(174	)		1,786

Net loss			$	(17,949	)	$	(24,728	)	$	(60,788	)	$	(48,805	)	$	(79,747	)	$	(53,881	)	$	(180,238	)	$	(417,438	)

Pro forma net loss (unaudited)(1):
Pro forma basic and diluted net loss per common share															$						$

Weighted average common shares outstanding used in pro forma basic and diluted net loss per common share															$						$

(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. The weighted average common shares outstanding have been calculated as if the ownership structure resulting from the corporate reorganization was in place since inception. Pro forma information does not give effect to this offering.

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Consolidated Balance Sheets Information:

	As of December 31															As of September 30						Pro Forma as Adjusted as of September 30 2010(1)

	2005			2006			2007			2008			2009			2009			2010			Pro Forma as Adjusted as of September 30 2010(1)
																(Unaudited)			(Unaudited)			(Unaudited)
	(In thousands)
Cash and cash equivalents	$	14,349		$	9,837		$	39,263		$	147,794		$	139,505		$	60,818		$	202,846		$
Total current assets		16,346			10,334			65,960			205,708			256,728			176,536			491,638
Total property and equipment		3,788			1,567			18,022			208,146			604,007			492,202			884,628
Total other assets		727			3,704			3,393			1,611			161,322			22,650			175,622
Total assets		20,861			15,605			87,375			415,465			1,022,057			691,388			1,551,888
Total current liabilities		430			1,436			28,574			68,698			139,647			143,829			168,310
Total long-term liabilities		1,312			—			—			444			287,022			1,902			967,211
Total convertible preferred units		41,937			61,952			167,000			499,656			813,244			750,065			813,244
Total unit holdings		(22,818	)		(47,783	)		(108,199	)		(153,333	)		(217,856	)		(204,408	)		(396,877	)
Total liabilities, convertible preferred units and unit holdings		20,861			15,605			87,375			415,465			1,022,057			691,388			1,551,888

(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 September 30 2010

	Year Ended December 31															Nine Months Ended September 30
	2005			2006			2007			2008			2009			2009			2010
																(Unaudited)			(Unaudited)			(Unaudited)
	(In thousands)
Net cash provided by (used in):
Operating activities	$	(13,978	)	$	(9,617	)	$	(17,386	)	$	(65,671	)	$	(27,591	)	$	(6,506	)	$	(133,180	)	$	(272,389	)
Investing activities		(3,980	)		(14,663	)		(58,161	)		(156,882	)		(500,393	)		(309,801	)		(451,164	)		(1,190,215	)
Financing activities		30,895			19,768			104,973			331,084			519,695			229,331			647,685			1,665,450

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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 high-impact 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. 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 have recently commenced oil and natural gas production and we expect to generate revenue 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. In addition, we expect to incur certain non-recurring expenses related to the offering in the quarter in which the offering occurs, including a $15.0 million payment that is payable upon successful completion of an initial public offering. These differences in general and administrative expenses are not reflected in our historical financial statements.

Depletion, Depreciation and Amortization. We have recently commenced oil and natural gas production and we will amortize 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. No depletion of oil and natural gas properties is reflected in our historical financial statements.

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 $6.6 million, recorded at the Moroccan statutory rate of 30%, with an offsetting valuation allowance of $6.6 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 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.

Nine Months Ended September 30, 2010 vs. 2009

			Nine Months Ended September 30

			Nine Months Ended September 30						Increase (Decrease)
			2009			2010			Increase (Decrease)
			(Unaudited)
			(In thousands)
Revenues and other income:
	Oil and gas revenue		$	—		$	—		$	—
	Interest income			595			2,548			1,953
	Other income			7,578			3,793			(3,785	)

		Total revenues and other income		8,173			6,341			(1,832	)
Costs and expenses:
	Exploration expenses, including dry holes			17,191			52,764			35,573
	General and administrative			43,425			50,804			7,379
	Depreciation and amortization			1,369			1,655			286
	Amortization—debt issue costs			—			20,555			20,555
	Interest expense			—			45,645			45,645
	Derivatives, net			—			15,310			15,310
	Other expenses, net			39			20			(19	)

		Total costs and expenses		62,024			186,753			124,729

Loss before income taxes				(53,851	)		(180,412	)		(126,561	)
Income tax expense (benefit)				30			(174	)		(204	)

Net loss			$	(53,881	)	$	(180,238	)	$	(126,357	)

Oil and gas revenue. We have recently commenced oil and natural gas production. We did not realize any oil and gas revenue during the nine months ended September 30, 2009 and 2010.

Interest income. Interest income increased by $2.0 million during the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009, due to interest accrued on receivables—joint interest billings.

Other income. Other income decreased by $3.8 million during the nine months ended September 30, 2010, as compared to the nine months ended September 30, 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 $35.6 million during the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009, primarily due to unsuccessful well costs of $28.2 million and $13.2 million for the Ghana Dahoma-1 well and Cameroon Mombe-1 well, respectively, and an increase in purchases of seismic data for Ghana and Cameroon of $4.4 million offset by a decrease in purchases of seismic data for Morocco of $12.7 million.

General and administrative. General and administrative costs increased by $7.4 million during the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009,

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due to increases in professional fees and expenses offset by increases in capitalized technical service fees.

Amortization—debt issue costs. Amortization—debt issue costs increased by $20.6 million during the nine months ended September 30, 2010, as compared to the nine months ended September 30, 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 $45.6 million during the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009, $39.2 million due to draws on the commercial debt facilities beginning in November 2009 and $13.5 million for realized and unrealized losses on interest rate swaps offset by $7.1 million of capitalized interest.

Derivatives, net. During the nine months ended September 30, 2010, we recorded $15.3 million of losses on commodity derivatives, which represented unrealized losses subject to continuing market risk.

Year Ended December 31, 2009 vs. 2008

			Years Ended December 31

			Years Ended December 31						Increase (Decrease)
			2008			2009			Increase (Decrease)
			(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.

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.

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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.

Year Ended December 31, 2008 vs. 2007

			Years Ended December 31

			Years Ended December 31						Increase (Decrease)
			2007			2008			Increase (Decrease)
			(In thousands)
Revenues and other income:
	Oil and gas revenue		$	—		$	—		$	—
	Interest income			1,568			1,637			69
	Other income			2			5,956			5,954

		Total revenues and other income		1,570			7,593			6,023
Costs and expenses:
	Exploration expenses, including dry holes			39,950			15,373			(24,577	)
	General and administrative			18,556			40,015			21,459
	Depreciation and amortization			477			719			242
	Interest expense			8			1			(7	)
	Equity in losses of joint venture			2,632			—			(2,632	)
	Other expenses, net			17			21			4

		Total costs and expenses		61,640			56,129			(5,511	)

Loss before income taxes				(60,070	)		(48,536	)		11,534
Income tax expense				718			269			(449	)

Net loss			$	(60,788	)	$	(48,805	)	$	11,983

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, 2007 and 2008.

Other income. Other income increased by $6.0 million during the year ended December 31, 2008, as compared to the year ended December 31, 2007, due to an increase in technical services fees and overhead charges billed to the Unit Operator for the Jubilee Field Phase 1 development.

Exploration expenses. Exploration expenses decreased by $24.6 million during the year ended December 31, 2008, as compared to the year ended December 31, 2007, primarily due to a decrease of $43.2 million in unsuccessful well costs for Nigeria and Benin, both drilled in 2007, and a decrease of

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$1.0 million in purchases of seismic data for Benin offset by increases of $3.9 million in purchases of seismic data for Morocco and Ghana. Additionally, exploration costs increased $15.0 million due to a reimbursement for historical costs received in 2007.

General and administrative. General and administrative costs increased by $21.5 million during the year ended December 31, 2008, as compared to the year ended December 31, 2007, primarily due to the Ghana oil discovery in June 2007. The change is due to an increase in costs related to staff additions, professional fees and expenses, office-related costs, travel expenditures and operator charges partially offset by an increase in capitalized technical service fees and billings to block partners.

Equity in losses of joint venture. Equity in losses of joint venture decreased by $2.6 million during the year ended December 31, 2008, as compared to the year ended December 31, 2007, due to reduced losses in our equity investment in the Nigerian joint venture.

Liquidity and Capital Resources

As we have 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 anticipate receiving 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 facilities, will be sufficient to meet our operating needs, service our existing debt, finance internal growth and fund capital expenditures through early 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 $1.1 billion.

During 2009, we secured commercial debt facilities from a number of financial institutions, including the IFC, for up to $900 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.

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 IFC. 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.

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total commitments. Commitment fees for the senior and junior lenders are equal to 50% per annum of the then-applicable respective margin.

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;

(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. 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. As of September 30, 2010, borrowings against the commercial debt facilities totaled $950.0 million, of which $900.0 million is senior debt and $50.0 million is junior debt. As of September 30, 2010, the availability under our commercial debt facilities was $200.0 million, with $300.0 million of committed undrawn capacity provided for in such facilities (the difference being the result of borrowing base constraints).

If an event of default exists under the facilities, the lenders will be able to accelerate the maturity and exercise other rights and remedies.

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 anticipate receiving our first oil revenues in early 2011. We expect gross oil production from the Jubilee Field to reach its design capacity of 120,000 bopd in mid 2011.

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

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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 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 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. 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. Although we have a letter agreement with certain of our partners in which they agree to purchase the vessel and lease it back to the Jubilee Unit partners, should we elect to participate in the purchase or should they fail to perform their obligations under the letter agreement, our share of the remaining balance of cost to make such purchase is 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 $400.0 million of capital expenditures for the year ending December 31, 2011. This capital expenditure budget consists of:

•: $135.0 million for development in Ghana;
•: $175.0 million for exploration and appraisal in Ghana;
•: $25.0 million for exploration and appraisal in Cameroon;
•: $25.0 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.

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Cash Flows

																	Period April 23, 2003 (Inception) through September 30 2010

		Year Ended December 31									Nine Months Ended September 30
		2007			2008			2009			2009			2010
											(Unaudited)			(Unaudited)			(Unaudited)
		(In thousands)
Net cash provided by (used in):
	Operating activities	$	(17,386	)	$	(65,671	)	$	(27,591	)	$	(6,506	)	$	(133,180	)	$	(272,389	)
	Investing activities		(58,161	)		(156,882	)		(500,393	)		(309,801	)		(451,164	)		(1,190,215	)
	Financing activities		104,973			331,084			519,695			229,331			647,685			1,665,450

Operating activities. Net cash used in operating activities in 2009 was $27.6 million compared with net cash used in operating activities of $65.7 million and $17.4 million in 2008 and 2007, respectively. 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 $6.8 million and $6.8 million of interest expense. The increase in cash used in 2008 when compared to 2007 is primarily due to changes in working capital related to expenditures recorded and accrued in 2007 but paid in 2008, increased general and administrative expenses of $21.5 million and a reimbursement of $15.0 million for historical costs received in 2007.

Net cash used in operating activities for the nine months ended September 30, 2010 was $133.2 million compared with net cash used in operating activities for the nine months ended September 30, 2009 of $6.5 million. The increase in cash used in the nine months ended September 30, 2010 is primarily due to interest expense and changes in working capital related to expenditures recorded and accrued in the prior year but paid in the nine months ended September 30, 2010.

Investing activities. Net cash used in investing activities in 2009 was $500.4 million compared with net cash used in investing activities of $156.9 million and $58.2 million in 2008 and 2007, respectively. The increase in cash used in 2009 when compared to 2008 is primarily attributed to increased expenditures in Ghana for successful exploration and appraisal wells and development activities. The increase in 2008 cash flows when compared to 2007 is also primarily attributable to expenditures in Ghana for exploration and appraisal wells and development activities.

Net cash used in investing activities for the nine months ended September 30, 2010 and 2009 was $451.2 million and $309.8 million, respectively. The increase in cash used in 2010 when compared to 2009 is primarily attributed to notes receivable of $60.9 million, restricted cash required under the commercial debt facilities of $59.0 million and increased oil and gas expenditures primarily in Ghana and Cameroon of $26.6 million.

Financing activities. Net cash provided by financing activities in 2009 was $519.7 million compared with net cash provided by financing activities of $331.1 million and $105.0 million in 2008 and 2007, respectively. 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 $87.9 million in cash used for debt issue costs. The increase in 2008 cash flows when compared to 2007 is primarily due to $227.7 million of proceeds from issuances of Series A and Series B Convertible Preferred Units.

Net cash provided by financing activities for the nine months ended September 30, 2010 and 2009 was $647.7 million and $229.3 million, respectively. The increase in cash provided in 2010 when compared to 2009 is primarily due to borrowings of $665.0 million on the commercial debt facilities offset by a decrease of $250.4 million of proceeds from issuances of Series B Convertible Preferred Units.

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Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of September 30, 2010:

	Payments Due By Year

	Total		2010(1)		2011		2012		2013		2014		Thereafter
	(In thousands)
Drilling rig contract(2)	$	280,449	$	23,462	$	123,856	$	133,131	$	—	$	—	$	—
Operating leases		6,863		402		1,615		1,636		1,660		1,168		382
Commercial debt facilities(3)		950,000		—		175,000		250,000		200,000		175,000		150,000

(1): Represents payments for the period October 1, 2010 through December 31, 2010.
(2): Does not include any well commitments we may have under our oil and natural gas licenses.
(3): The amounts included in the table above represent principal maturities only. Subsequent to September 30, 2010, the Company borrowed an additional $95 million under the senior and junior facilities. As of the date the financial statements are available to be issued, borrowings against the commercial debt facilities totaled $1.05 billion and the scheduled principal maturities during the next five years and thereafter are (in thousands): 2010—zero; 2011—$245,000; 2012—$250,000; 2013—$200,000; 2014—$175,000; and thereafter—$175,000.

The following table presents maturities by expected maturity dates under the 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.

			October 1 Through December 31 2010			Year Ending December 31															Liability Fair Value at September 30 2010

			October 1 Through December 31 2010			2011			2012			2013			2014			Thereafter			Liability Fair Value at September 30 2010
			(In thousands, except percentages)
Variable Rate Debt:
	Credit facilities maturities		$	—		$	175,000		$	250,000		$	200,000		$	175,000		$	150,000		$	950,000
	Weighted average interest rate			7.25	%		7.08	%		7.33	%		6.92	%		8.30	%		10.69	%
Interest Rate Swaps
	Notional debt amount(1)		$	161,250		$	161,250		$	138,073		$	91,683		$	47,033		$	13,333		$	5,002
		Fixed rate payable		2.22	%		2.22	%		2.22	%		2.22	%		2.22	%		2.22	%
		Variable rate receivable(2)		0.75	%		0.60	%		1.06	%		1.73	%		2.50	%		3.38	%
	Notional debt amount(1)		$	161,250		$	161,250		$	138,073		$	91,683		$	47,033		$	13,333		$	5,424
		Fixed rate payable		2.31	%		2.31	%		2.31	%		2.31	%		2.31	%		2.31	%
		Variable rate receivable(2)		0.75	%		0.60	%		1.06	%		1.73	%		2.50	%		3.38	%
	Notional debt amount(1)		$	77,500		$	77,500		$	63,625		$	19,057		$	1,868		$	—		$	349
		Fixed rate payable		0.98	%		0.98	%		0.98	%		0.98	%		0.98	%
		Variable rate receivable(2)		0.25	%		0.60	%		1.06	%		1.73	%		2.30	%

(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 September 30, 2010, we did not have any off-balance sheet arrangements.

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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 will use the sales method of accounting for oil and gas revenues. Under this method, we will 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. As of September 30, 2010, no revenues have been recognized in our financial statements.

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 geologic 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.

Inventories. Inventories consist primarily of casing and wellheads that will be used in our anticipated future drilling program. The inventory is stated at the lower of cost, using the weighted average cost method or market.

Income Taxes. We account for income taxes as required by the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("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.

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

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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 June 30, 2010, our net proved undeveloped reserves totaled 59 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 quality and quantity of available data and the engineering and geological interpretation of that data;
•: estimates regarding the amount and timing of future operating cost, production taxes, development cost and workover cost, all of which may in fact vary considerably from actual results;
•: 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 have recently commenced oil and natural gas production and we expect to have significant obligations to remove our equipment and restore land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and natural gas facilities. Estimating the future restoration and removal cost is difficult and requires us to make estimates and 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. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Pursuant to the FASB ASC 410—Assets Retirement Obligations, we will be required to record a separate liability in the fourth quarter of 2010 for the discounted present value of our asset retirement obligations, with an offsetting increase to the related oil and natural gas properties on our balance sheet.

Inherent to the present value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free 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 abandonment liability, we will make corresponding adjustments to our oil and natural gas property balance. In addition, increases in the discounted abandonment liability resulting from the passage of time will be reflected as accretion expense in the consolidated statement of operations.

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

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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.
•: 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.

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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 operation.

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 nine months ending September 30, 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		(15,310	)		(13,917	)		(29,227	)
Contract maturities		—			3,142			3,142

Fair value of contracts outstanding as of September 30, 2010	$	(15,310	)	$	(10,775	)	$	(26,085	)

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 September 30, 2010.

			Year Ending December 31						Liability Fair Value at September 30 2010

			2011		2012		2013		Liability Fair Value at September 30 2010
Oil Derivatives:
	Deferred premium puts
		Average daily notional bbl volumes		11,332		4,625		2,515	$	12,221
		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	$	3,089
		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)			$	93.34	$	93.47	$	92.94

(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 January 7, 2011 market quotes.

Interest Rate Risk

At September 30, 2010, we had indebtedness outstanding under our commercial debt facilities of $950.0 million, of which $550.0 million bore interest at floating rates. The weighted average annual interest rate incurred on this indebtedness for the nine months ended September 30, 2010 was approximately 7.0%. At this level of floating rate debt, if LIBOR increased by 10%, we would incur an additional $0.2 million of interest expense per year on revolving credit facilities.

As of September 30, 2010, the fair market value of our interest rate swaps was a net liability of approximately $10.8 million. If the LIBOR rate increased by 10%, we estimate the liability would decrease approximately $9.7 million, and if the LIBOR rate decreased by 10%, we estimate the liability would increase to approximately $11.9 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. According to African Business Review, although Africa is estimated to only have approximately 10% of the world's proven oil reserves, by 2025 it will provide an estimated 25% of North America's oil imports. The compound annual growth rate of oil reserves from 1989 to 2009 in Africa was 1.4% and from 1999 to 2009 was 2.1%. 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. Based on marketing surveys and its quality, Jubilee oil is forecasted to ultimately sell 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 50^th 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 and Enyenra 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 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, so you should not place undue reliance on any of our measures."

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 fan and channel systems that were associated with a paleo-Volta River system. A number of these drainage systems exist along the ancient West African Transform Margin from Ghana to Sierra Leone. To date, the Turonian and Campanian reservoirs have proven to be of high quality with porosities in the 15% to 28% range and permeabilities typically in the 100 millidarcies to 2 darcies range.

These Late Cretaceous fan systems are laterally extensive and have been deposited at the base of the continental slope. This has resulted in updip pinch out of the reservoir intervals against Albian aged faulted terraces. 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.

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

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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 and, based on our drilling results to date, we estimate they have a mean hydrocarbon yield of 225 barrels of oil-equivalent per acre-foot.

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. Based on these results and industry analogues in the region, we estimate the Tano Basin has a mean hydrocarbon yield of 180 barrels of oil equivalent per acre-foot. 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.

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 238 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

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Company and Total S.A. ("Total"). According to Wood Mackenzie, during 2009, Cameroon produced 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, so you should not place undue reliance on any of our measures."

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 recoverable oil reserves of approximately 525 Mmbbl are being produced from the Late Cretaceous Ceiba and Northern Block G oil 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. Based on industry drilling results and production history, we estimate that reservoirs in this basin have a mean hydrocarbon yield of 390 barrels of oil equivalent per acre-foot. 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 structural closures. Discoveries in this region include the Kombo, Ekundu and Abana oil fields. It is estimated that 65% of Cameroon's 1.8 Bboe of commercial reserves lie in the offshore Rio del Rey Basin. 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 0.1 to 2 darcy range. Based on industry drilling results and production history, we estimate that reservoirs in this basin have an average hydrocarbon yield of 325 barrels of oil equivalent per acre-foot.

Most of the hydrocarbon traps in the Niger Delta are structural. Major trapping geometries include anticlinal dip closures, footwall closures and hangingwall closures. The productive fields are frequently located on the crests and flanks of these structures.

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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, Micoene, deepwater stratigraphic traps adjacent to the Kosmos license area. These discoveries are currently the focus of development drilling and contain reserves of 800 Mmboe according to IHS Inc. ("IHS").

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.

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

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in that region. Our exploration licenses in this region conflict with exploration licenses issued by the SADR."

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, so you should not place undue reliance on any of our measures."

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. According to Wood Mackenzie, during 2009, Morocco produced less than 100 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 Cap Juby oil discovery, which was discovered by 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 channel and sheet depositional 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.

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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. Although there is limited hydrocarbon production in Morocco, we estimate the average hydrocarbon yield for this basin to be of 150 barrels of oil equivalent per acre-foot, based on industry analogues in depositional environments similar to those we expect to encounter in our Boujdour Offshore Block prospects.

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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 high-impact exploration opportunities as well as defined, multi-year visibility in the reserve and production growth of 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 five 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 anticipate receiving our first oil revenues in early 2011. We expect gross oil production from the Jubilee Field to reach its design capacity of 120,000 bopd in mid 2011.

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.

Our asset portfolio consists of five 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 and Enyenra offshore Ghana, which have geologic characteristics similar to the Jubilee Field. In addition, we have identified 20 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.

Well-defined production and growth plan

Our plan for developing the Jubilee Field provides highly 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 floating production, storage and offloading ("FPSO") facility used at the field, in mid 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 the Jubilee Field on a faster timeline and allowed us to achieve first oil production at an earlier date than

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traditional development techniques. 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 and Enyenra 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

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, we expect crude oil from the Jubilee Field will ultimately command 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 high-quality asset portfolio

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

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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.

Strong financial position

Our Strategy

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

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

Focus on rapidly developing our discoveries to initial production

First oil from the Jubilee Field commenced on November 28, 2010, and we anticipate receiving 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, 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.

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 extremely 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.

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Acquire additional exploration assets

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. 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

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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 highly 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 are estimated by Wood MacKenzie to hold approximately 1,700 Mmboe of reserves on a combined basis. The Ceiba and North Block G Complex, discovered between 1998 and 1999, are estimated by Wood MacKenzie to hold approximately 525 Mmboe of reserves. Triton's Malaysia—Thailand Joint Development Area discoveries, initially drilled between 1995 and 1997, are estimated by Wood MacKenzie to 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.

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 will not be the operator on all of our license areas, and, 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 assets."

Discoveries		License				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
	Tweneboa	DT(4)	19,200	18.0000	%	Tullow	Appraisal	Deepwater	2012(7)
	Enyenra	DT(4)	28,100	18.0000	%	Tullow	Appraisal	Deepwater	2013

(1): For information concerning our estimated proved reserves in the Jubilee Field as of June 30, 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 anticipate receiving 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

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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.

Prospect Information

Information about our prospects as of June 30, 2010 is summarized in the following table.

Prospect		License			Block Operator	Type	Projected Spud Year(3)

Ghana(1)
	Teak	WCTP	21,800	30.875	Kosmos	Deepwater	2010
	Banda Campanian	WCTP	8,800	30.875	Kosmos	Deepwater	2011
	Banda Cenomanian	WCTP	15,000	30.875	Kosmos	Deepwater	2011
	Makore	WCTP	12,300	30.875	Kosmos	Deepwater	2011
	Odum East	WCTP	3,100	30.875	Kosmos	Deepwater	2011
	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
	Tweneboa Deep	DT	20,100	18.000	Tullow	Deepwater	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
	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	12,100	100.000	Kosmos	Onshore	2012
	Liwenyi South	Ndian River	4,000	100.000	Kosmos	Onshore	Post 2012
	Meme	Ndian River	1,600	100.000	Kosmos	Onshore	Post 2012
	Bamusso	Ndian River	3,800	100.000	Kosmos	Onshore	Post 2012
Morocco
	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

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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): 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. 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): 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."
(4): We have not yet made a decision as to whether or not to continue into the drilling phase of the license. If we do, we anticipate the first well to drill within the Boujdour Offshore Block will be post 2012.

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, and Enyenra discoveries.

The Tano Basin represents the eastern extension of the Deep Ivorian Basin which resulted from Albian trans-tension associated with opening of the Atlantic Ocean between the St. Paul and Romanche fracture zones, 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 was a depositional focus for a thick Upper Cretaceous, deepwater clastic 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 a large plunging nose (the South Tano high) 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. Subsequently, Kosmos entered into the WCTP Petroleum Agreement in 2004. Kosmos recognized the potential for large, Late Cretaceous clastic 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 pinchout of reservoir sands, (2) combination fault and three-way dip closed structures, and (3) four-way dip closures or anticlinal traps.

The primary prospect types consist of well imaged Turonian and Campanian fans deposited against the steeply dipping shelf margin and trapped in an up dip direction by pinchout of the 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, three-way and four-way closures are also present within the WCTP Block. These discoveries and prospects are described in more detail below.

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Our Ghanaian Discoveries

The following is a brief discussion of our discoveries to date on our two blocks offshore Ghana. In this prospectus, we use "estimated pay thickness" to refer to the estimated mean vertical extent of the effective hydrocarbon-bearing rock (expressed in feet). See "Risk Factors—We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects, so you should not place undue reliance on any of our measures."

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—Unitization and Unit Operating Agreement." 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). This field has an estimated pay thickness of approximately 153 feet (47 meters). The 17 wells and two sidetracks drilled to date have encountered high-quality sandstone reservoirs with good porosity and permeability. 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.

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

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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.

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 9⁵/8 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. This discovery has an estimated pay thickness of approximately 66 feet (20 meters). 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.

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

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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 clastics. 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. This discovery has an estimated pay thickness of 60 feet (18 meters). 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.

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, and Tweneboa-3 wells have intersected multiple natural gas, condensate and oil bearing reservoirs in this Turonian turbidite sequence. This discovery area has an estimated pay thickness of approximately 56 feet (17 meters). 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 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 and Owo-1 ST1 wells have intersected multiple oil and natural gas bearing reservoirs in this Turonian turbidite sequence. This discovery has an estimated pay thickness of approximately 65 feet (20 meters). 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.

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Our Ghanaian Prospects

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

Teak

Teak is located in the western portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 1,650 to 3,600 feet (500 to 1,100 meters). It is a large structural-stratigraphic trap with an element of four-way dip closure. It contains multiple stacked objectives with strong amplitude support ranging in age from Albian to Campanian. Teak is adjacent to and updip from the Jubilee Field and is located in the thickest part of the reservoir fairway penetrated by the Jubilee wells. Teak has an estimated pay thickness of approximately 90 feet. The first well to drill Teak was spud in December 2010.

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 defined by a high resolution 3D seismic data survey as a combination structural-stratigraphic trap where a Campanian channel system is sealed updip by a series of listric faults and encased in marine shale. Banda Campanian has similar geologic characteristics to the Odum discovery and has an associated amplitude versus offset ("AVO") anomaly, 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 clastics interlayered with marine argillaceous sediments. Banda Campanian has an estimated pay thickness of approximately 45 feet. The first well to drill Banda Campanian is anticipated to be spud in the first half of 2011.

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, it is a large amplitude anomaly draped over the flank of a four-way dip closure thought to consist of channel and fan reservoirs within the Upper Cretaceous Cenomanian aged interval. Banda Cenomanian has an estimated pay thickness of approximately 80 feet. The first well to drill Banda Cenomanian is anticipated to be spud in the first half of 2011.

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. Makore has an estimated pay thickness of approximately 35 feet. 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 clastics. Odum East has an estimated pay

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thickness of approximately 40 feet. The first well to drill Odum East is anticipated to be spud in 2011.

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 broad system of channel belts which amalgamate to form an extensive depositional system with associated channel margin facies confining the width of the stratigraphic trap to approximately 6.2 miles (10 kilometers) wide. High resolution 3D seismic information indicates a high-energy deposition. Sapele has an estimated pay thickness of approximately 115 feet. 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 information indicates a high-energy deposition. The prospect has an estimated pay thickness of approximately 120 feet. 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 clastics interlayered with marine argillaceous sediments. Assin has an estimated pay thickness of approximately 25 feet. 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. Okoro has an estimated pay thickness of approximately 105 feet. 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 dip closures to stratiographic channel traps. These targets have an estimated pay thickness of approximately 45 feet. If a target matures into a prospect, the first well to drill one of these targets is anticipated to be spud post 2012.

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Tweneboa Deep

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 pinch out and is similar in age to the deeper reservoirs encountered in Mahogany East. Tweneboa Deep has an estimated pay thickness of approximately 60 feet. The first well to drill Tweneboa Deep is anticipated to be spud in 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 a fairway of upper slope stratigraphic and downthrown fault closures varying in age from Turonian to Campanian. Walnut has an estimated pay thickness of approximately 55 feet. 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 exploration target has an estimated pay thickness of approximately 35 feet. 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 fault closure at the Albian level. Wassa has an estimated pay thickness of approximately 95 feet. The first well to drill Wassa is anticipated to be spud post 2012.

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 a fairway of upper slope stratigraphic and downthrown fault closures varying in age from Turonian to Campanian. Adinkra has an estimated pay thickness of approximately 55 feet. 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 a fairway of upper slope stratigraphic and downthrown fault closures of Albian to Cenomanian age. Oyoko has an estimated pay thickness of approximately 65 feet. The first well to drill Oyoko is anticipated to be spud in 2012.

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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 with a seismic AVO signature. Ananta has an estimated pay thickness of approximately 60 feet. 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.

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

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.

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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 four-way dip and three-way prospects, 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. N'gata has an estimated pay thickness of approximately 130 feet. An exploration well is anticipated to be drilled in the first half of 2011.

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. N'donga has an estimated pay thickness of approximately 130 feet. An exploration well is anticipated to be drilled post 2012.

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. Disangue has an estimated pay thickness of approximately 130 feet. An exploration well is anticipated to be drilled post 2012.

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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. Pongo Songo has an estimated pay thickness of approximately 130 feet. 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. Bonongo has an estimated pay thickness of approximately 130 feet. 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. Coco East has an estimated pay thickness of approximately 130 feet. 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 thrust 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. It has an estimated pay thickness of approximately 90 feet. 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 thrust 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. It has an estimated pay thickness of approximately 140 feet. 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 three-way listric roll-over trapped on the downthrown side of an extensional 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. It has an estimated pay thickness of approximately 140 feet. 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 bounded extensional structure within the Upper Cretaceous section. Bamusso has an estimated pay thickness of approximately 140 feet. 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 comprises an area of more than 10.87 million acres (44,000 square kilometers), 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 channel and sheet 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 dip 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 clastic 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 continue into the drilling phase of the license. If we do, we anticipate 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 clastics trapped in a number of different structural trends. In the inboard area a number of three-way fault closures are present which contain Early to Mid Cretaceous clastic sequences some of which have been penetrated in wells on the continental shelf. Outboard of these fault trap trends, large four-way dip closure and combination structural stratigraphic traps are present in discrete northeast to southwest trending structurally defined fairways.

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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 dip closures which sit on a 328 mile (100 kilometer) long compressional 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. Gargaa has an estimated pay thickness of approximately 260 feet. 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 dip closures which sit on a 328 mile (528 kilometers) long compressional 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. Argane has an estimated pay thickness of approximately 330 feet. 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 compressional 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. Safsaf has an estimated pay thickness of approximately 205 feet. 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 dip 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. Aarar has an estimated pay thickness of approximately 205 feet. 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 dip 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. Zitoune has an estimated pay thickness of approximately 175 feet. 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 closure on the upthrown side of an extensional 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. Al Arz has an estimated pay thickness of approximately 380 feet. 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. Felline has an estimated pay thickness of approximately 140 feet. 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. Nakhil has an estimated pay thickness of approximately 125 feet. 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. These prospects have an estimated pay thickness of 310 feet. Exploration wells are anticipated to be drilled post 2012.

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Our Reserves

The following table sets forth summary information about our oil and natural gas reserves as of December 31, 2009 and June 30, 2010. As of December 31, 2009 and June 30, 2010, all of our proved reserves were classified as proved undeveloped. Given the commencement of production from the Jubilee Field on November 28, 2010, we expect a significant portion of our proved undeveloped reserves will be reclassified as proved developed. 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						June 30, 2010
Reserves Category		Natural Gas		Oil, Condensate, NGLs		Total		Natural Gas		Oil, Condensate, NGLs		Total
		(Bcf)		(Mmbbl)		(Mmboe)		(Bcf)		(Mmbbl)		(Mmboe)
*Ghana*
	Jubilee Field Phase 1		—		55		55		23		55		59

The following table sets forth the estimated future net revenues, excluding derivatives contracts, from net proved reserves, the present value of those net revenues at a 10% discount rate (PV-10), and the expected benchmark prices used in projecting net revenues at June 30, 2010.

		Projected Net Revenues (in Millions except $/bbl)

Future net revenues		$	1,617
*Present value of future net revenues:*
	Before income tax (PV-10)(1)		1,072
	After income tax (Standardized Measure)(2)		1,072
Benchmark and differential oil price($/bbl)(3)		$	74.88

(1): PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. 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 tax characteristics of such entities.
(2): Our PV-10 and our Standardized Measure are equivalent because as of June 30, 2010, we were a Cayman company limited by guarantee and not subject to entity level taxation. Accordingly, no provision for corporate income taxes has been provided because taxable income was passed through to our equity holders. Prior to the consummation of this offering we will become an exempted company organized under the laws of Bermuda, however we do not believe our corporate income tax liability will change as a result of our corporate reorganization. Standardized Measure represents the present value of estimated future net cash inflows from proved oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses (if applicable), discounted at 10% per annum to reflect timing of future cash flows.

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(3): The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months was $74.53/bbl for Dated Brent at June 30, 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 marketing surveys, the Jubilee oil is forecasted to sell for a $0.35/bbl premium relative to Dated Brent. The adjusted price utilized to derive the PV-10 is $74.88/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 six months ended June 30, 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" beginning on page 159 of this prospectus. 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 June 30, 2010 are based on costs in effect at June 30, 2010 and the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period July 2009 through June 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. There are numerous uncertainties inherent in estimating reserves and related information and different reserve engineers often arrive at different estimates for the same assets. 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 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 June 30, 2010 and related future net revenues and PV-10 at June 30, 2010 are based on reports prepared by NSAI, our independent reserve engineers, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and current guidelines 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 June 30, 2010 report was completed on September 10, 2010 and the December 31, 2009 report was

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completed on February 2, 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 June 30, 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 June 30, 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 June 30, 2010, based upon its evaluation. NSAI's primary economic assumptions in estimates included an ability to sell oil at a price of $74.88/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, 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 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.

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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. Our Reservoir Engineering Managers report directly to our Senior Vice President, Production and Operations.

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 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, the International Energy Agency ("IEA") projects demand for oil to be up in 2010 and 2011, at 86.6 million bopd and 87.9 million bopd, respectively. 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, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.

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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		0		0		747,741		261,709		747,741		261,709
	Ndian River		0		0		434,163		434,163		434,163		434,163
*Morocco*
	Boujdour Offshore Block		0		0		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): Deepwater Tano acreage does not reflect the subsequent 25% relinquishment expected to occur in connection with the extension of the DT Petroleum Agreement into the next phase in January 2011.

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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
		Productive				Dry				Total				Productive				Dry				Total				Total Net		Total Gross
		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Total Net		Total Gross
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 January 11, 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		—		—		—		—		8		2.32		4		0.94
	Deepwater Tano		—		—		2		0.36		5		0.97		4		0.72
*Cameroon*
	Kombe-N'sepe		—		—		—		—		—		—		—		—

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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 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 intend to formally submit a proposed new petroleum agreement for these areas in early 2011. The current exploration phase over the undeveloped acreage of the DT Block expires 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 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. We expect that such application will be approved, but upon approval we will be required to relinquish 30% of the 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 expected to be spud by the end of the first quarter of 2011.

Under the Boujdour Offshore Petroleum Agreement, the current exploration phase expires on February 26, 2011, and 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 current 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.

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, and GNPC entered into the WCTP Petroleum Agreement covering the WCTP Block 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

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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, with Kosmos Ghana entitled to receive all of EO Group's production proceeds until repayment in full. 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 a portion of GNPC's production revenues under the terms of the WCTP Petroleum Agreement.

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% 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

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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.

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, 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 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.

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

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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 Integrated Project Team ("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 September 30, 2010, Kosmos has 514 allocated days remaining for use of the Atwood Hunter drilling rig.

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. The Boujdour Offshore Block comprises approximately 10.87 million acres (44,000 square kilometers). 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

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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 current 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. 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. 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 exploration and appraisal phases and has the option to back into the project with an interest of up to 15% upon approval of a PoD. 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 now ends 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.

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Sales and Marketing

Production from the Jubilee Field began on November 28, 2010 and, as provided under the UUOA and the WCTP and DT Petroleum Agreements, we will be 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. We believe Jubilee oil will ultimately sell 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 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 (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,

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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.

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 may be 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

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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. 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.

Oil Spill Response

Kosmos has developed and adopted an Oil Spill Response Plan ("OSRP") for the coordination of responses to oil spills or other emergencies arising from its operations in Ghana, including the WCTP Block. In addition, Tullow maintains an Oil Spill Contingency Plan ("OSCP") covering the Jubilee Field and DT Block. Under the OSRP and OSCP, Emergency Response Teams may be activated to respond to oil spill incidents. In addition, Oil Spill Response Limited ("OSRL") of Southampton, United Kingdom may be engaged to provide oil spill response services comprising technical expertise and assistance, including access to response equipment and dispersant spraying systems. Kosmos maintains an annual subscription to the West and Central Africa Aerial Surveillance and Dispersant Spraying Service, through which OSRL may use aircraft in surveillance and in the spraying of dispersant. The OSCP also provides for use of this service.

Other Regulation of the Oil and Gas Industry

Ghana

The Ghanaian Petroleum Law currently governs the Ghanaian oil and natural gas regulatory regime and sets out the local policy and framework for industry participants. The law allows for petroleum agreement terms to be agreed between GNPC and oil and gas companies. 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. 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. 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

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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 of such petroleum agreements without the prior written consent of GNPC and Ghana's Ministry of Energy. Such 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.

Ghana's parliament is considering the enactment of a new Petroleum Law. Industry participant commentary has been sought and submitted and such law is currently in its draft stages. We currently believe that such law 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. 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 December 1999, the government of Cameroon approved the Petroleum Code 1999 (the "Cameroon Petroleum Code") that was designed to simplify regulation of the local oil and gas industry. The Cameroon Petroleum Code applies to all license awards and existing license holders had the opportunity to convert from the previous system of permitting and contracting to the Cameroon Petroleum Code's system of production sharing contracts. Companies who wish to gain rights to explore and produce in Cameroon can only do so by entering into a production sharing contract with Cameroon, represented by SNH, the Cameroon national oil company, and assignments of such contracts require the consent of SNH. SNH, established in March 1980, participates in the form of joint ventures with the "contractors."

Morocco

The two main legislative acts in Morocco relevant to petroleum exploration and production are (i) Law 21-90 (1 April 1992) amended and completed by Law 27-99 (15 February 2000); and (ii) Decree 2-93-786 (3 November 1993) 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 the Environment and the national oil company is ONHYM. ONHYM acts on behalf of the state in licensing matters and has a 25% interest in field developments. Companies who wish to gain rights to explore and produce in Morocco can only do so by entering into a petroleum agreement with ONHYM, and assignments of such agreements require the consent of ONHYM. All licenses to explore and produce in Morocco, represented by such petroleum agreements, are governed by concession fiscal terms. The fiscal terms are based on the model petroleum agreement dated October 20, 2000.

The SADR has claimed sovereignty over the Western Sahara territory and accordingly 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 SADR" and "Industry—Morocco—Country Overview."

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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.

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

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MANAGEMENT

The following table sets forth certain information concerning our board of directors, executive officers and key employees:

Name		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
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	55	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 April 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. Since joining Blackstone in 1995, Mr. Foley has been involved in the execution of several of Blackstone's investments including: Foundation Coal Holdings, OSUM Oil Sands Corp., Moser Baer, PBF Investments, Premcor, World Power Holdings G. P. LTD, Texas Genco, and American Petroleum Tankers. Mr. Foley focuses on investments in the energy and transportation sectors. Before joining Blackstone, Mr. Foley worked with AEA Investors, where he worked on several of the firm's private equity investments. Mr. Foley also worked as a consultant for the Monitor

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Company between August 1989 and August 1991. Mr. Foley currently serves as a Director of Republic Services Inc., Moser Baer, OSUM Oil Sands Corp., PBF Investments, World Power Holdings G. P. LTD and American Petroleum Tankers. Mr. Foley received a Bachelor of Arts and Masters of Arts in Economics from Northwestern University and received a Masters 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, 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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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 April 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 1988 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, 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.

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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 eight directors: Messrs. Kemp, Maxted, Foley, Harris, Krieger, Melwani, Ogunlesi, 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 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. , , and 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 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.

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Audit committee. The members of our audit committee are Messrs. , , and , each of whom our board of directors has determined is financially literate. Mr. is the Chairman of this committee. Our board of directors has determined that Mr. 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;
•: 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. , , and . Mr. 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.

Nominating and corporate governance committee. The members of our nominating and corporate governance committee are Messrs. , , and . Mr. 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.

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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) if it owns 20% or more of the outstanding common shares 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) if it owns 7.5% or more of the outstanding common shares. Under the shareholders agreement, subject to the corporate governance requirements of the NYSE, 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).

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.

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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 $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".

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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.

Equity-based incentive awards

Each of our named executive officers has received grants of partnership 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 converted into common shares and awards on common shares. 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 stock options, restricted stock, restricted stock units and stock 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.

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

James C. Musselman Chairman and Chief Executive Officer	2010	593,000	—	—	—	—	—
W. Greg Dunlevy Executive Vice President and Chief Financial Officer	2010	428,917	469,700	—	—	—	—	14,785	908,309
Brian F. Maxted 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	1,438,668
Dennis C. McLaughlin Senior Vice President of Development	2010	333,225	406,700	—	782,550	—	—	28,247	1,556,722

(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).
(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 17 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

James C. Musselman	—	—	85
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, accelerated vesting of unvested profit units and payment of legal fees provided to Mr. Musselman under his retirement agreement. The value of such accelerated vesting is based on an assumed initial offering price of $ per common share, the midpoint of the estimated public offering price on the cover page of this prospectus. See "Potential Payments on Termination or Change in Control—Mr. Musselman."

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 converted into awards on common shares in connection with this offering. The share numbers set forth in the table assume solely for this purpose that this conversion had occurred as of the grant date of these units (based on an assumed initial public offering price of $ per common share, the midpoint of the estimated public offering price range set forth on the cover page of this prospectus).



			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 ($)
									Estimated Future Payouts Under Equity Incentive Plan Awards								Exercise or Base Price of Option Awards ($/Sh)
Name	Grant Date(1)		Threshold ($)		Target ($)		Maximum ($)		Threshold (#)		Target (#)		Maximum (#)				Exercise or Base Price of Option Awards ($/Sh)
James C. Musselman		—		—		—		—		—		—		—	—	—		—		—
W. Greg Dunlevy		—		—		—		—		—		—		—	—	—		—		—
Brian F. Maxted		—		—		—		—		—		—		—	—	—		—		—
William S. Hayes		12/9/2010		—		—		—		—		—		—				—		782,550
Dennis C. McLaughlin		12/9/2010		—		—		—		—		—		—	—	—		—		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".

Outstanding Equity Awards at 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 converted into common shares and awards on common shares in connection with this offering. The amounts set forth in the table assume solely for this purpose that this conversion had occurred as of December 31, 2010 (based on an assumed initial public offering

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price of $ 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 ($)
James C. Musselman	6/13/2007		—		—		—		—		—				—		—
	6/11/2008		—		—		—		—		—				—		—
W. Greg Dunlevy	6/13/2007		—		—		—		—		—				—		—
	6/11/2008		—		—		—		—		—				—		—
Brian F. Maxted	6/13/2007		—		—		—		—		—				—		—
	6/11/2008		—		—		—		—		—				—		—
William S. Hayes	10/11/2007		—		—		—		—		—				—		—
	6/11/2008		—		—		—		—		—				—		—
	12/10/2008		—		—		—		—		—				—		—
	12/9/2010		—		—		—		—		—				—		—
Dennis C. McLaughlin	2/6/2008		—		—		—		—		—				—		—
	6/11/2008		—		—		—		—		—				—		—
	12/10/2008		—		—		—		—		—				—		—
	12/9/2010		—		—		—		—		—				—		—

(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.

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 converted into common shares in connection with this offering. The number of shares and value realized in the table assume solely for this purpose that this conversion had occurred as of the vesting date of the interests (based on an assumed initial public offering price of $ 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		—		—
W. Greg Dunlevy		—		—
Brian F. Maxted		—		—
William S. Hayes		—		—
Dennis C. McLaughlin		—		—

Pension Benefits

We do not maintain any defined benefit pension plans.

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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 $ per common share, the midpoint of the estimated public offering price on the cover page of this prospectus) are as follows: Mr. Dunlevy ($ ), Mr. Maxted ($ ), Mr. Hayes ($ ) and Mr. McLaughlin ($ ).

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 consummation 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 $ (based on an assumed initial public offering price of $ 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 converted into 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.

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

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

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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 converted into 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.

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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, 2009 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 nine months ended September 30, 2010. For the twelve months ended December 31, 2009, 12,013,750 Series B Convertible Preferred Units were issued by Kosmos Energy Holdings in exchange for $300,343,750 in consideration and 884,956 Series C Convertible Preferred Units and 2,500,000 C1 Common Units were issued by Kosmos Energy Holdings in exchange for a total of $25,000,007 in consideration. 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 $136.6 million at September 30, 2010 and $87.9 million at December 31, 2009. In addition, as a result of the issuance of Series C Convertible Preferred Units and the associated C1 Common Units, a discount exists on the Series C Convertible Preferred Units of approximately $11.8 million, which will be accreted once redemption of the units is probable.

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 amended to remove the various classes of units, the rights of our Investors and management to appoint directors to the board of Kosmos Energy Holdings and the rights of Kosmos Energy Holdings to make any additional capital calls. In connection with our corporate reorganization, we have entered into a reorganization agreement with the Investors and certain other parties. See "Corporate Reorganization."

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 September 30, 2010, and after giving effect to our corporate reorganization, for:

•: each of our named executive officers;
•: each of our directors;
•: all our current named 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 September 30, 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 common shares issued and outstanding on September 30, 2010, after giving effect to our corporate reorganization, plus common shares that we are selling in this offering. The underwriters have an option to purchase up to 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 Named Executive Officers
John R. Kemp III
David I. Foley
Jeffrey A. Harris(4)
	Warburg Pincus LLC
	450 Lexington Avenue
	New York, NY 10017
David Krieger(4)
	Warburg Pincus LLC
	450 Lexington Avenue
	New York, NY 10017
Prakash A. Melwani
Adebayo O. Ogunlesi
Christopher A. Wright
Brian F. Maxted
W. Greg Dunlevy
Paul Dailly
Marvin M. Garrett
William S. Hayes
Dennis C. McLaughlin
All directors and named executive officers as a group (13 individuals)
Five Percent Shareholders
Warburg, Pincus International Partners, L.P.(3)
	450 Lexington Ave
	New York, NY 10017
Warburg, Pincus Private Equity VIII, L.P.(3)
	450 Lexington Ave
	New York, NY 10017
Blackstone Funds(5)
	c/o Walkers Corporate Services Limited
	87 Mary Street
	George Town, Grand Cayman KY1-9005
	Cayman Islands

(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 stockholders are Warburg Pincus International Partners, L.P., and two affiliated partnership ("WPIP") and Warburg Pincus Private Equity VIII, L.P., and two affiliated partnerships ("WP VIII"). Warburg Pincus Partners LLC ("WP Partners"), a direct subsidiary of Warburg Pincus & Co. ("WP"), is the sole general partner of WPIP and WP VIII. WPIP and WP VIII are managed by Warburg Pincus LLC ("WP LLC"). The address of the Warburg Pincus entities is 450 Lexington Avenue, New York, New York 10017.

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(4): Messrs. Harris and Krieger, directors of the Company, 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.
(5): 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, BCP IV-A, Family and Participation, the "Blackstone Funds"). The Blackstone Funds beneficially own (i) shares, which are held by BCP IV, (ii) shares, which are held by BCP IV-A, (iii) shares, which are held by Family, (iv) shares, which are held by Participation, and (v) 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.

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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 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 common shares, par value $0.01 per share, and preference shares, par value $0.01 per share. Upon completion of this offering, there will be outstanding common shares and no preference shares. All of our 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 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 eight 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 owns (A) 20% or more of the outstanding common shares 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 owns 7.5% or more of the 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 beneficially own more than 50% of the outstanding shares entitled to vote, all directors will be up for election each year at our annual 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 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 meeting of shareholders. See "Description of Share Capital—Meetings of Shareholders."

Under our bye-laws, prior to the first date on which the Investors no longer beneficially own more than 50% of the outstanding shares entitled to vote, directors may be removed with or without cause by the affirmative vote of a majority of the 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 outstanding shares entitled to vote. Any vacancy created by the removal of a director at a special 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 if at least one director designated by each Investor then entitled to designate a director is not present at a meeting, such meeting will be postponed for up to 48 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 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.

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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 that would otherwise be imposed on them by virtue of any rule of law, except for cases of fraud or dishonesty.

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.

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Meetings of Shareholders

Under Bermuda law, a company is required to convene at least one meeting of shareholders each calendar year. Under Bermuda law and our bye-laws, a special 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 entitled to vote at meetings of shareholders.

Unless otherwise provided in our bye-laws, at any meeting of shareholders the presence in person or by proxy of shareholders representing a majority of the 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 outstanding shares voting at a meeting at which a quorum is present.

Shareholder Proposals

Under Bermuda law, shareholders holding at least 5% of the outstanding shares entitled to vote or any group comprised of at least 100 or more shareholders may require a proposal to be submitted to an annual 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 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 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 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 a majority of the 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 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 any sale, lease or exchange by us of all or substantially all of our assets will require the approval of our board of directors and of 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

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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 outstanding shares, and the share premium account is the aggregate amount paid for 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 would after the repurchase be, unable to pay its liabilities as they become due.

Transactions with Significant Shareholders

The 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 officer or controlling shareholder 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 to us unless, in the case of any such person who is one of our directors or officers, any such business opportunity is expressly offered to such person solely in his or her capacity as our director or officer.

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

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where an act requires the approval of a greater percentage of the company's shareholders than that which actually approved it.

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 meetings of shareholders and the company's audited financial statements. The company's audited financial statements must be presented at the annual meeting of shareholders. The company's share register is open to inspection by shareholders without charge, and by members of the general public on payment of a fee. A company is required to maintain its share register in Bermuda but may, subject to the provisions of the 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 , who will serve as branch registrar and transfer agent.

Listing

We have applied to list our common shares on the NYSE under the symbol "KOS". Settlement will take place through The Depository Trust Company in U.S. dollars.

Certain Provisions of Bermuda Law

The Bermuda Monetary Authority has given its consent for the issue and free transferability of all of the common shares that are the subject of this offering to and between non-residents of Bermuda for exchange control purposes, provided our shares remain listed on an appointed stock exchange, which includes the NYSE. Approvals or permissions given by the Bermuda Monetary Authority do not constitute a guarantee by the Bermuda Monetary Authority as to our performance or our creditworthiness. Accordingly, in giving such consent or permissions, the Bermuda Monetary Authority

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shall not be liable for the financial soundness, performance or default of our business or for the correctness of any opinions or statements expressed in this prospectus. Certain issues and transfers of common shares involving persons deemed resident in Bermuda for exchange control purposes require the specific consent of the Bermuda Monetary Authority.

This prospectus will be filed with the Registrar of Companies in Bermuda pursuant to Part III of the Companies Act 1981 of Bermuda. In accepting this prospectus for filing, the Registrar of Companies in Bermuda shall not be liable for the financial soundness, performance or default of our business or for the correctness of any opinions or statements expressed in this prospectus.

In accordance with Bermuda law, share certificates are only issued in the names of companies, partnerships or individuals. In the case of a shareholder acting in a special capacity (for example as a trustee), certificates may, at the request of the shareholder, record the capacity in which the shareholder is acting. Notwithstanding such recording of any special capacity, we are not bound to investigate or see to the execution of any such trust. We will take no notice of any trust applicable to any of our shares, whether or not we have been notified of such trust.

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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. We intend to apply to have our common shares listed on the NYSE under the symbol "KOS".

Based on the number of common shares issued and outstanding as of September 30, 2010 after giving effect to our reorganization, upon completion of this offering, 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 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 of our common shares will be eligible for sale under Rule 144 by our affiliates, subject to the above restrictions. Upon the expiration of any lock-up period and the six-month holding period, approximately

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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.

Rule 701

In general, under Rule 701 under the Securities Act, any of our employees, consultants or advisors who purchased common shares from us in connection with a qualified compensatory share plan or other written agreement is eligible to resell those shares 90 days after the effective date of this offering in reliance on Rule 144, but without compliance with the various restrictions, including the holding period, contained in Rule 144. Subject to the provisions of the lock-up agreements referred to below, approximately of our common shares will be eligible for sale in accordance with Rule 701.

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 consummation of this offering, we will enter into a registration rights agreement with certain of our shareholders pursuant to which we will grant certain of our shareholders and their affiliates certain registration rights with respect to our common shares owned by them. 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 28, 2016, 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 Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc. are acting as representatives (the "Representatives"), the following respective numbers of common shares:

Underwriter			Number of Common Shares

Credit Suisse Securities (USA) LLC
Citigroup Global Markets Inc.
Barclays Capital Inc.
	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 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.

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Our officers, directors and certain shareholders have agreed, subject to certain exceptions, that they will not offer, sell, contract to sell, pledge 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.

We intend to apply to list our common shares on the NYSE under the symbol "KOS."

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;
•: 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.

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•: 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.

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,

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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.

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

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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
•: in a transaction that, in accordance with article L.411-2-II-1°-or-2°-or 3° of the French Code 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

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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 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

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(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.

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 2008, and for each of the three years in the period ended December 31, 2009 and for the period April 23, 2003 (Inception) through December 31, 2009 and the schedule of Kosmos Energy Holdings as of December 31, 2009 and 2008 and for each of the three years in the period ended December 31, 2009, 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 June 30, 2010. The reserve estimates at June 30, 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.
"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.
"Appraisal well"		A well drilled after an exploratory well to gain more information on the drilled reservoirs.
"AVO"		A measure of the variation in seismic reflection amplitude 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. 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.
"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.
"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.

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"bopd"		Barrels of oil per day.
"bwpd"		Barrels of water per day.
"Closure"		A trapping configuration.
"Completion"		The procedure used in finishing and equipping an oil or natural gas well for production.
"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.
"Development"		The phase in which an oil field is brought into production by drilling development wells and installing appropriate production systems.
"Development well"		A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
"Drilling and completion costs"		All costs, excluding operating costs, of drilling, completing, testing, equipping and bringing a well into production or plugging and abandoning it, including all costs associated with labor and other construction and installation, location and surface damages, cementing, drilling mud and chemicals, drillstem tests and core analysis, engineering and well site geological expenses, electric logs, plugging back, deepening, rework operations, repairing or performing remedial work of any type, plugging and abandoning.
"Dry hole"		A well that has not encountered a hydrocarbon bearing reservoir.
"E&P"		Exploration and production.
"Estimated pay thickness"		The mean vertical extent of the effective hydrocarbon bearing rock (expressed in feet).
"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.

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"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 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.
"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 yield"		An estimated measure of the quantity of oil ultimately recoverable from a given volume of reservoir rock (expressed in barrels of oil per acre-foot). Estimating hydrocarbon yield involves an analysis of a combination of several factors, including reservoir characteristics, hydrocarbon and fluid properties and recovery efficiency.
"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.

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"Mcfpd"		Thousand cubic feet per day.
"Mmbbl"		Million barrels of oil.
"Mmboe"		Million barrels of oil equivalent.
"Mmcf"		Million cubic feet.
"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.
"OPEC"		Organization of the Petroleum Exporting Countries.
"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"		Porosity is the percentage of pore volume or void space within a sedimentary layer that can contain fluids.
"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).
"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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"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.
"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.
"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.
"Stratigraphy"		The study of the composition, relative ages and distribution of layers of sedimentary rock.
"Trap"		A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.
"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.
"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



Kosmos Energy Holdings
Unaudited Consolidated Financial Statements (a Development Stage Entity)
	Consolidated Balance Sheets as of December 31, 2009 and September 30, 2010	F-2
	Consolidated Statements of Operations for the nine months ended September 30, 2009 and 2010 and for the Period April 23, 2003 (Inception) through September 30, 2010	F-3
	Consolidated Statements of Unit Holdings Equity for the nine months ended September 30, 2010	F-4
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 and 2010 and for the Period April 23, 2003 (Inception) through September 30, 2010	F-5
	Notes to Consolidated Financial Statements	F-6
Audited Consolidated Financial Statements (a Development Stage Entity)
	Report of Independent Registered Public Accounting Firm	F-33
	Consolidated Balance Sheets as of December 31, 2008 and 2009	F-34
	Consolidated Statements of Operations for the years ended December 31, 2007, 2008 and 2009 and for the Period April 23, 2003 (Inception) through December 31, 2009	F-35
	Consolidated Statements of Unit Holdings Equity for the years ended December 31, 2007, 2008 and 2009	F-36
	Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2008 and 2009 and for the Period April 23, 2003 (Inception) through December 31, 2009	F-37
	Notes to Consolidated Financial Statements	F-38
	Supplementary Oil and Gas Data (Unaudited)	F-60

F-1

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Balance Sheets

			December 31 2009			September 30 2010

						(Unaudited)
			(In thousands)
Assets
Current assets:
	Cash and cash equivalents		$	139,505		$	202,846
	Receivables:
		Joint interest billings		42,616			144,322
		Notes		52,318			112,956
		Other		1,693			1,516
	Inventories			19,621			22,807
	Prepaid expenses and other			975			7,191

Total current assets				256,728			491,638
Property and equipment:
	Oil and gas properties, net of accumulated depletion of zero			595,091			876,254
	Other property, net of accumulated depreciation of $3,193 and $4,848, respectively			8,916			8,374

	Property and equipment—net			604,007			884,628
Other assets:
	Restricted cash			30,000			89,000
	Long-term receivables—joint interest billings			41,593			—
	Debt issue costs and other assets, net of accumulated amortization of $3,266 and $23,821, respectively			89,729			86,489
	Derivatives			—			133

Total assets			$	1,022,057		$	1,551,888

Liabilities and unit holdings
Current liabilities:
	Accounts payable		$	97,837		$	132,269
	Accrued liabilities			41,810			25,279
	Derivatives			—			10,762

Total current liabilities				139,647			168,310
Long-term debt				285,000			950,000
Long-term derivatives				—			15,456
Leasehold improvement allowance—long-term				1,369			1,102
Long-term deferred tax liability				653			653
Convertible preferred units, 100,000 units authorized:
	Series A—30,000 units issued at December 31, 2009 and September 30, 2010			300,000			300,000
	Series B—20,000 units issued at December 31, 2009 and September 30, 2010			500,000			500,000
	Series C—885 units issued at December 31, 2009 and September 30, 2010			13,244			13,244
Unit Holdings:
	Common units, 100,000 units authorized; 18,667 and 18,689 issued at December 31, 2009 and September 30, 2010, respectively			516			516
	Additional paid-in capital			19,108			20,780
	Deficit accumulated during development stage			(237,480	)		(417,718	)
	Accumulated other comprehensive loss			—			(455	)

Total unit holdings				(217,856	)		(396,877	)

Total liabilities, convertible preferred units and unit holdings			$	1,022,057		$	1,551,888

See accompanying notes

F-2

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Operations

(Unaudited)

									Period April 23, 2003 (Inception) through September 30 2010

			Nine Months Ended September 30
			2009			2010
			(In thousands)
Revenues and other income:
	Oil and gas revenue		$	—		$	—		$	—
	Interest income			595			2,548			7,459
	Other income			7,578			3,793			25,383

		Total revenues and other income		8,173			6,341			32,842
Costs and expenses:
	Exploration expenses, including dry holes			17,191			52,764			146,088
	General and administrative			43,425			50,804			188,002
	Depreciation and amortization			1,369			1,655			5,737
	Amortization—debt issue costs			—			20,555			23,047
	Interest expense			—			45,645			52,452
	Derivatives, net			—			15,310			15,310
	Equity in losses of joint venture			—			—			16,983
	Other expenses, net			39			20			875

		Total costs and expenses		62,024			186,753			448,494

Loss before income taxes				(53,851	)		(180,412	)		(415,652	)
	Income tax expense (benefit)			30			(174	)		1,786

Net loss			$	(53,881	)	$	(180,238	)	$	(417,438	)

See accompanying notes.

F-3

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Unit Holdings Equity

(Unaudited)

									Deficit Accumulated During Development Stage

		Common Units										Accumulated Other Comprehensive Loss
		Common Units					Additional Paid-in Capital
		Units			Amount		Additional Paid-in Capital								Total
		(In thousands)
Balance as of December 31, 2009			18,667		$	516	$	19,108	$	(237,480	)	$	—		$	(217,856	)
	Issuance of profit units		28			—		—		—			—			—
	Relinquishments		(6	)		—		—		—			—			—
	Unit-based compensation		—			—		1,672		—			—			1,672
	Derivatives, net		—			—		—		—			(455	)		(455	)
	Net loss		—			—		—		(180,238	)		—			(180,238	)

Balance as of September 30, 2010			18,689		$	516	$	20,780	$	(417,718	)	$	(455	)	$	(396,877	)

See accompanying notes.

F-4

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Cash Flows

(Unaudited)

									Period April 23, 2003 (Inception) through September 30 2010

			Nine Months Ended September 30
			2009			2010
			(In thousands)
Operating activities
Net loss			$	(53,881	)	$	(180,238	)	$	(417,438	)
Adjustments to reconcile net loss to net cash used in operating activities:
	Equity in losses of joint venture			—			—			16,983
	Depreciation and amortization			1,369			22,210			28,784
	Deferred income taxes			—			—			527
	Deferred rent income			(177	)		(267	)		(533	)
	Leasehold improvement incentive			1,791			—			1,989
	Gain (loss) on disposal of inventory and other property			333			2			584
	Unsuccessful well costs			100			43,127			86,518
	Derivative related activity			—			25,630			25,630
	Unit-based compensation			2,806			1,672			9,274
	Leasehold impairment			—			—			3,000
	Changes in assets and liabilities:
		Increase in receivables		(39,714	)		(59,696	)		(145,838	)
		Increase in inventories		(11,828	)		(3,188	)		(23,030	)
		Decrease in prepaid expenses and other		(6,063	)		(6,216	)		(6,458	)
		Increase in accounts payable		97,314			34,574			132,269
		Increase (decrease) in accrued liabilities		1,444			(10,790	)		15,350

Net cash used in operating activities				(6,506	)		(133,180	)		(272,389	)
Investing activities
Oil and gas assets				(303,571	)		(330,173	)		(953,866	)
Other property				(6,230	)		(1,113	)		(13,699	)
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				—			(60,878	)		(112,956	)
Restricted cash				—			(59,000	)		(89,000	)

Net cash used in investing activities				(309,801	)		(451,164	)		(1,190,215	)
Financing activities
Borrowings under long-term debt				—			665,000			950,000
Net proceeds from issuance of units				250,409			—			824,986
Debt issue costs				(21,078	)		(17,315	)		(109,536	)

Net cash provided by financing activities				229,331			647,685			1,665,450

Net increase (decrease) in cash and cash equivalents				(86,976	)		63,341			202,846
Cash and cash equivalents at beginning of period				147,794			139,505			—

Cash and cash equivalents at end of period			$	60,818		$	202,846		$	202,846

Supplemental cash flow information
Cash paid for:
	Interest		$	5		$	35,125		$	41,926

	Income taxes (net of refunds received)		$	95		$	762		$	1,553

Non cash activity:
	Deemed repayment and termination of notes receivable		$	—		$	90,197		$	90,197

See accompanying notes.

F-5

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 a development stage company whose primary goal is to explore for and develop oil and gas resources in Africa.

We have one business segment which is the exploration, development 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 $350,000, 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 12—Convertible Preferred Units.

As of September 30, 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.

2. Accounting Policies

General

The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of September 30, 2010, the consolidated results of operations for the nine months ended September 30, 2009 and 2010, and consolidated cash flows for the nine months ended September 30, 2009 and 2010. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. These consolidated financial statements and the notes thereto should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2009.

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.

F-6

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

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.

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 September 30, 2010, Kosmos had $89.0 million of restricted cash on hand. 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 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 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 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.

Receivables

Receivables are stated net of allowances. Joint interest billings, notes and other receivables had no allowances as of December 31, 2009 and September 30, 2010.

Inventories

Inventories were comprised of $19.6 million and $22.8 million of materials and supplies as of December 31, 2009 and September 30, 2010, respectively. The Company's materials and supplies inventory is primarily comprised of casing and wellheads. Inventory is stated at the lower of cost, using the weighted average cost method or market.

Exploration and Development Costs

F-7

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

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 nine months ended September 30, 2009 and 2010, Kosmos recognized exploration expense of $17.2 million and $52.8 million, respectively.

Depletion, Depreciation and Amortization

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

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

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 shall be 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 shall be 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 shall be recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset

F-8

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

retirement costs by increasing the carrying amount of the related long-lived asset by the same amount as the liability. As of December 31, 2009 and September 30, 2010, we had no material asset retirement obligations. On November 28, 2010, we commenced oil production from the Jubilee Field offshore Ghana. As a result, we will be required to record a separate liability in the fourth quarter of 2010 for the discounted present value of our asset retirement obligations, with an offsetting increase to the related oil and natural gas properties on our balance sheet.

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 will absorb a majority of the VIE's expected losses, receive a majority of the VIE's expected residual returns, or both. 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.

Impairment of Long-Lived Assets

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

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

F-9

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

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.

Revenue Recognition

We will use the sales method of accounting for oil and gas revenues. Under this method, we will 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. As of September 30, 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.

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 the implementation of this standard, we recognized no material adjustment for unrecognized income tax benefits.

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.

F-10

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

Comprehensive Loss

The components of other comprehensive loss are as follows:

			Nine Months Ended September 30

			2009			2010
			(In thousands)
Net Loss			$	(53,881	)	$	(180,238	)
Other comprehensive loss:
	Change in fair value of cash flow hedges			—			(4,838	)
	Loss on cash flow hedge included in operations			—			4,383

		Other Comprehensive loss		—			(455	)

Comprehensive loss			$	(53,881	)	$	(180,693	)

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. See Note 17—Profit Units.

Employees

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

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 ("VIE"s). 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.

F-11

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

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.

In January 2010, the FASB issued ASU No. 2010-06—Fair Value Measurements and Disclosures (ASC 820) Improving Disclosures and Fair Value Measurements to improve disclosure requirements and thereby increase transparency in financial reporting. The Company adopted the update as of December 31, 2009, and it did not have a material impact on the Company's financial position or results of operation.

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 has taken 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

F-12

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 (Continued)

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 and Long-term Notes Receivable

Effective May 7, 2010, Tullow Ghana Limited ("TGL"), acting on behalf of the Unitization and Unit Operating Agreement ("UUOA") parties, entered into an advance payments agreement with MODEC related to the construction, installation, lease, operations and maintenance 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. As of September 30, 2010, Kosmos Ghana's share of the payments made under the advance payments agreement is $113.0 million and is recorded as notes receivable.

5. Jubilee Field Unitization

F-13

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

5. Jubilee Field Unitization (Continued)

to consist of 35% of an area from the WCTP contractors and 65% of an area from the DT contractors. 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 interests 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 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 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. Long-term Receivables—Joint Interest Billings

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Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

6. Long-term Receivables—Joint Interest Billings (Continued)

acquire an additional paying interest of 2.5% of WCTP in the commercial discovery with respect to the Jubilee Field development. In January 2009, under the DT Petroleum Agreement, GNPC exercised its option to acquire an additional paying interest of 5% of DT in the commercial discovery with respect to the Jubilee Field development. GNPC is obligated to pay its 2.5% of WCTP and its 5% of DT of all future petroleum costs, including development and production costs. 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 and we anticipate revenues from oil production in early 2011. As a result, all related receivables for EO Group and GNPC were classified as current as of September 30, 2010.

7. Property and Equipment

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

		December 31 2009			September 30 2010

		(In thousands)
Oil and gas properties, net:
	Proved properties	$	251,814		$	370,260
	Unproved properties		128,557			178,522
	Support equipment and facilities		214,720			327,472
	Less: accumulated depletion		—			—

		$	595,091		$	876,254

Other property, net:
	Leasehold improvements	$	5,041		$	5,041
	Computer equipment and software		3,539			4,643
	Office equipment and furniture		3,529			3,538
	Less: accumulated depreciation		(3,193	)		(4,848	)

		$	8,916		$	8,374

The Company recorded $1.3 million and $1.7 million of depreciation expense for the nine months ended September 30, 2009 and 2010, respectively.

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.

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Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

8. Suspended Well Costs (Continued)

The following table reflects the Company's capitalized exploratory well activities during the nine months ended September 30, 2010. The table excludes costs related to exploratory dry holes of $40.6 million which were incurred and subsequently expensed in 2010.

	Nine Months Ended September 30, 2010

	(In thousands)
Beginning balance	$	114,307
Additions to capitalized exploratory well costs pending the determination of proved reserves		56,791
Reclassification due to determination of proved reserves		—
Capitalized exploratory well costs charged to expense		(2,502	)

Ending balance	$	168,596

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:

	December 31 2009		September 30 2010

	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	91,909	$	108,696
Exploratory well costs capitalized for a period greater than one year		22,398		59,900

Ending balance	$	114,307	$	168,596

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		1		3

As of September 30, 2010, the exploratory well costs capitalized in excess of one year since the completion of drilling relate to the Odum-1 and Mahogany-3 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. As provided under Article 8.17 of the WCTP Petroleum Agreement, the contractor group intends to perform such additional evaluation, studies, planning and potential well operations, including exploration activities. 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, 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.

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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 additional 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—One appraisal well, Tweneboa-2, has been drilled and suspended. Additional appraisal wells, Tweneboa-3, Tweneboa-4 and a drill stem test ("DST"), are planned for late 2010 to early 2011. A decision regarding commerciality of the Tweneboa discovery is expected to be made by the 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 September 30, 2010, $97.8 million and $132.3 million were recorded for invoices received but not paid in 2009 and 2010, respectively. Accrued liabilities were $41.8 million and $25.3 million at December 31, 2009 and September 30, 2010, respectively. Accrued liabilities consist of the following:

		December 31 2009		September 30 2010

		(In thousands)
Accrued liabilities:
	Accrued exploration and development	$	34,723	$	8,533
	Accrued general and administrative expenses		2,236		16,078
	Accrued debt issue costs		3,232		—
	Taxes other than income		979		666
	Income taxes		640		2

		$	41,810	$	25,279

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 pledged 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

F-17

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

10. Commercial Debt Facilities (Continued)

amended on December 24, 2009, increasing the total commercial debt facilities for up to $900.0 million ($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 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 September 30, 2010, borrowings against the commercial debt facilities totaled $950.0 million, of which $900.0 million is senior debt and $50.0 million is junior debt. As of September 30, 2010, the availability under our commercial debt facilities was $200.0 million, with $300.0 million of committed undrawn capacity provided for in such facilities (with the difference being the result of borrowing base constraints).

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 $40.4 million (net of capitalized interest of $7.1 million) and commitment fees were $5.2 million for the nine months ended September 30, 2010.

The facilities contain certain financial covenants which include the maintenance of the: debt service coverage ratio not less than 1.2x; field life cover ratio not less than 1.35x; loan life cover ratio not less than 1.15x; and funding sufficiency ratio not less than 1:1x, in each case, as calculated by the Technical and Modeling Banks on the basis of all information made available to it. 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.

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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)

At September 30, 2010, the scheduled maturities of long-term debt during the next five years and thereafter are as follows:

	Payments Due By Year

	2010(1)		2011		2012		2013		2014		Thereafter
	(In thousands)
Commercial debt facilities	$	—	$	175,000	$	250,000	$	200,000	$	175,000	$	150,000

(1): Represents payments for the period October 1, 2010 through December 31, 2010.

Debt issue costs associated with the facilities were $92.2 million and $109.5 million at December 31, 2009 and September 30, 2010, respectively. The Company amortizes debt issue costs using the straight-line method over the life of the facilities. Amortization expense of $20.6 million was recorded for the nine months ended September 30, 2010.

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.

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.

F-19

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

11. Derivative Financial Instruments (Continued)

Oil Derivative Contracts

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 September 30, 2010, the net liability of commodity derivative contracts was reduced by $1.8 million for estimated nonperformance risk.

The following table sets forth as of September 30, 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			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 summarizes our open interest rate swaps as of September 30, 2010, all of which were entered into as

F-20

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

11. Derivative Financial Instruments (Continued)

required under the terms of our commercial debt facilities and are with parties that are lenders under our commercial debt facilities:

Term	Notional Amount				Floating Rate

	(In thousands)
January 2010 - June 2016	$	161,250	2.22	%	6-month LIBOR
January 2010 - June 2016	$	161,250	2.31	%	6-month LIBOR
July 2010 - June 2014(1)	$	77,500	0.98	%	1-month LIBOR

(1): The floating rate changes to 6 month LIBOR beginning January 1, 2011.

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 September 30, 2010, the net liability of interest rate derivative contracts was reduced by $1.2 million for estimated nonperformance risk.

All of the Company's derivatives were made up of non-hedge derivatives as of September 30, 2010. The following tables provide disclosure of the Company's derivative instruments:

Fair Value of Derivative Instruments as of September 30, 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	$	3,831
	Interest rate derivatives	Derivatives—current		—	Derivatives—current		6,931
	Commodity derivatives	Derivatives—noncurrent		—	Long-term derivatives		11,479
	Interest rate derivatives	Derivatives—noncurrent		133	Long-term derivatives		3,977

Total derivatives not designated as hedging instruments				133			26,218

Total derivatives			$	133		$	26,218

F-21

Table of Contents

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

11. Derivative Financial Instruments (Continued)

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 September 30, 2011, the Company expects to reclassify $3.4 million of AOCI(L) losses to interest expense. See Note 14—Fair Value Measurements for additional information regarding the Company's derivative instruments.

On February 11, 2004, under the Kosmos Energy Holdings Contribution Agreement, Kosmos received provisional commitments of up to $300 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 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 million from Warburg Pincus, The Blackstone Group, the management group, certain accredited employee investors and directors. For each $28.25 contribution, one Series C was issued. Contributions began on November 2, 2009. Upon execution and delivery and per Section 1.4 of the Kosmos Energy Holdings Second Amended and Restated Contribution Agreement, the Company issued a total of 2,500,000 C1 Common Units to the Series C investors. The proceeds from the Series C issuance were allocated on a relative fair value basis between the Series C and the C1 Common Units, which created a discount on the Series C of approximately $11.8 million. As the Series C are not currently redeemable, the discount on the Series C will be accreted to redemption value once a redemption event is probable and will impact net income/loss available to common unit holders and earnings per unit calculations at that time.

Series A, Series B and Series C contributions were as follows (in thousands, including unit data):

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 accumulated preferred return for the Convertible Preferred Units totaled approximately $87.9 million and $136.6 million at December 31, 2009 and September 30, 2010, respectively. The holders of the Convertible Preferred Units will realize the accumulated preferred return upon the consummation of a Qualified Public Offering as defined in the Agreement. As no distributions have been declared to date and the Convertible Preferred Units are not currently redeemable, the preferred return on the Convertible Preferred Units has not been recorded, however the accumulated preferred return will be recorded once a Qualified Public Offering is probable and will be treated as a distribution to preferred holders, impacting net income/loss available to common unit holders and earnings per unit calculations at that time.

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" as defined in the Agreement, each outstanding Common Unit and each outstanding Convertible Preferred Unit would be converted (with values determined in the Agreement) into common shares and preferred shares, respectively, of the IPO Corporation, as defined in the Agreement. Upon consummation of a Qualified Public Offering, each share of preferred shares of the IPO Corporation would be redeemed for cash or common shares of the IPO Corporation for 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 value of any additional common shares issued will be treated as a distribution to the unit holders, impacting net income/loss available to common unit holders and earnings per unit calculations at that time. The Convertible Preferred Units are classified as mezzanine equity as the Company cannot solely control the method of redemption and the Convertible Preferred Unit holders control the Company's Board of Directors.

As a development stage entity with no revenues, Kosmos is actively engaged in an ongoing process to anticipate and meet its funding requirements. To date we have raised three rounds of equity funding: the Series A, Series B and Series C equity capital financings. During 2009, we secured commercial debt facilities from a number of financial institutions, including the IFC, for up to $900 million to be utilized in funding the Company's share of the Jubilee Field Phase 1 development. These facilities were closed on July 13, 2009. See Note 10—Commercial Debt Facilities and Note 20—Subsequent Events.

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 $7.6 million and $3.8 million for the nine months ended September 30, 2009 and 2010, respectively.

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:

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 September 30, 2010, for each of the fair value hierarchy levels:

All fair values have been adjusted for nonperformance risk resulting in a decrease of the commodity derivative liabilities of approximately $1.8 million and a decrease of the interest rate derivatives of approximately of $1.2 million as of September 30, 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.

The following table presents the carrying amounts and fair values of the Company's financial instruments as of December 31, 2009 and September 30, 2010:

The book values of cash and cash equivalents, trade 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 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 September 30, 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.

The Company's interest rate derivative liabilities as of September 30, 2010 represent swap contracts for $400.0 million notional amount of debt, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate. The derivative liability values attributable to the Company's interest rate derivative contracts as of September 30, 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 liability measurements represent Level 2 inputs in the hierarchy priority.

The income tax provision (benefit) for the nine months ended September 30, 2009 and 2010 was $30 thousand and $(174) thousand, respectively. The income tax provision is primarily made up of U.S. federal income and Texas margin taxes. Due to the operating losses incurred since inception, the Company did not record a provision (benefit) for income taxes in any of the foreign jurisdictions. In addition, a valuation allowance has been recorded against the foreign net deferred tax assets of $74.8 million of which $53.8 million and $14.4 million is related to the Ghana and Cameroon operations, respectively.

The Company entered into a Petroleum Agreement in Morocco in 2006 with the Moroccan Government with respect to the Boujdour Offshore Block. The Agreement provides for a tax holiday, at a 0% tax rate, for a period of 10 years beginning on the date of first production of the Boujdour Offshore Block. The Company currently has recorded deferred tax assets of $6.6 million, recorded at the Moroccan statutory rate of 30%, with an offsetting valuation allowance of $6.6 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 files a U.S. federal income tax return and a Texas margin tax return. In addition to the United States, the Company files income tax returns in the countries in which we operate. The Company is open to U.S. federal income tax examinations for tax years 2007 through 2009, and to foreign income tax examinations for tax years 2004 through 2009. In addition, the Company is open to Texas tax examinations for the tax years 2005 through 2009.

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. During 2010 the Company, after being examined by the State of Texas, received a refund of $197 thousand for its 2007 and 2008 Texas margin tax returns.

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 $415 thousand and $409 thousand for the nine months ended September 30, 2009 and 2010, respectively.

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:

At September 30, 2010, the remaining unrecognized compensation cost from profit units was $1.9 million, which will be recognized over a weighted-average period of 1.9 years. Total profit unit compensation expense recognized in income was $2.8 million and $1.7 million for the nine months ended September 30, 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 1.4 to 8.1 years and projected turnover rate of 7.0% for employees and none for management.

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 the use of Atwood Hunter across the WCTP and DT Blocks during part of Kosmos Ghana's allocated time. The future minimum commitments under this contract as of September 30, 2010, are (in thousands): October 1 through December 31, 2010—$23,462; 2011—$123,856; and 2012—$133,131.

On October 18, 2009, Kosmos Ghana agreed to provide an irrevocable standby Letter of Credit ("LOC") in respect of its Jubilee paying interest share of Tullow Ghana Limited's LOC related to their drilling contract for the Eirik Raude drilling rig. Kosmos LOC is limited to a maximum amount of $23 million. See Note 20—Subsequent Events.

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.

These consolidated financial statements reflect management's evaluation of subsequent events through January 13, 2011, the date the Company's financial statements were available to be issued.

In November and December 2010, the Company borrowed an additional $95.0 million under the senior and junior commercial debt facilities. As of the date the financial statements are available to be issued, borrowings against the commercial debt facilities totaled $1.05 billion and the scheduled principal maturities during the next five years and thereafter are (in thousands): October 1 through December 31, 2010—zero; 2011—$245,000; 2012—$250,000; 2013—$200,000; 2014—$175,000 and thereafter—$175,000.

In December 2010, we entered into an interest rate swap to hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on the project finance commercial debt facilities. The interest rate swap converts $75.0 million, of the then $950.0 million, LIBOR based debt to fixed rate debt having a fixed rate of 1.344% plus an applicable margin, currently 5.5%, which will equal an average effective interest rate of 6.8%. The effective date of the swap is August 31, 2010, and the maturity date is June 30, 2015. Our interest rate swaps are entered into as required under the terms of our commercial debt facilities and are with parties that are lenders under our commercial debt facilities. We do not apply hedge accounting treatment to our interest rate swap derivative contracts and therefore, the changes in fair value will be recognized in income in the period of change.

Effective December 30, 2010, Kosmos Energy Finance provided a $23.0 million irrevocable standby 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.

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, 1,176,961 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.

On January 4, 2011, the Company announced that John R. Kemp III was named Chairman and Brian Maxted was promoted to President and Chief Executive Officer and made a member of the company's Board of Directors. Kemp has been an independent member of the Company's Board of Directors since March 2005. Maxted is one of the co-founders of the Company and previously held the position of Chief Operating Officer.

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, the Company's forecast of future production and the Company's 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.

A contingent amount of $15.0 million will be payable by the Company, but only at such time as the Company successfully completes an initial public offering or upon a sale of all or substantially all of the Company's assets. As this is not considered probable as of the date of these financial statements, no amounts have been currently accrued related to this contingency.

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 September 30, 2010 of $13.2 million are included in exploration expenses in the accompanying consolidated statement of operations. As of the date the financial statements are available to be issued, the Company estimates we will incur an additional $8.5 million of related well costs.

We have audited the accompanying consolidated balance sheets of Kosmos Energy Holdings (a development stage entity) (the "Company") as of December 31, 2008 and 2009, and the related consolidated statements of operations, unit holdings equity, and cash flows for each of the three years in the period ended December 31, 2009, and for the period April 23, 2003 (Inception) through December 31, 2009. Our audits also included the financial statement schedule included at Item 16(b). These consolidated financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and schedule 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, 2008 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, and for the period April 23, 2003 (Inception) through December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, 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.

Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements

We have one business segment which is the exploration, development 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.

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, 2009, 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.

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

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.

At December 31, 2009, Kosmos had $30.0 million of restricted cash on hand. In accordance with our project financing commercial debt facilities agreement, a balance at all times of not less than $30 million is required during the year prior to Project Completion of the Jubilee Phase 1 Development (as defined in the agreement). We have the option to invest the restricted cash in an account which is satisfactory to the facility agents. See Note 19—Subsequent Events.

Receivables are stated net of allowances. Joint interest billings, notes and other receivables had no allowances as of December 31, 2008 and 2009.

Inventories were comprised of $5.4 million and $19.6 million of materials and supplies as of December 31, 2008 and 2009, respectively. The Company's materials and supplies inventory is primarily comprised of casing and wellheads. Inventory is stated at the lower of cost, using the weighted average cost method or market.

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, 2007, 2008 and 2009, Kosmos recognized exploration expense of $40.0 million, $15.4 million and $22.1 million, respectively.

Proved properties will be 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 will be amortized using the unit-of-production method based on estimated proved developed oil and natural gas reserves.

Depreciation and amortization of other property is computed using the straight-line method over estimated useful lives ranging from 3 to 7 years.

are consolidated by the primary beneficiary, which is the entity that will absorb a majority of the VIE's expected losses, receive a majority of the VIE's expected residual returns, or both. 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.

During 2006, Kosmos recognized an impairment of $3.0 million for the Morocco Boujdour Reconnaissance license which expired in April 2006.

We will use the sales method of accounting for oil and gas revenues. Under this method, we will 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. As of December 31, 2009, no revenues have been recognized in our financial statements.

For the years ended December 31, 2008 and 2009, the Company had no components of comprehensive income (loss) other than those included in net loss.

The majority of our full-time employees are leased through TriNet Acquisition Corp. TriNet Acquisition Corp. administers all salaries, benefits and payment of taxes, and bills Kosmos semimonthly for its cost. This contract is for one year and may be cancelled with a 30-day notification.

The FASB ASC became effective on July 1, 2009. The ASC combined multiple sources of authoritative accounting literature into a single source of authoritative generally accepted accounting principles ("GAAP") organized by accounting topic. Since the ASC was not intended to change existing GAAP, the only impact on the Company's financial statements was that specific references to accounting principles have been changed to refer to the ASC. This statement was effective for interim and annual periods ending after September 15, 2009.

Effective January 1, 2009, the Company adopted the FASB accounting standard that clarifies the accounting for income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the financial statements (ASC 740—Income Taxes). As a result of the implementation of this standard, the Company recognized no material adjustment for unrecognized income tax benefits.

In April 2009, the FASB issued three standards to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities (ASC 825—Financial Instruments). These standards are effective for interim and annual periods ending after June 15, 2009. The adoption of these rules did not have a material impact on the Company's financial position or results of operations.

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. This Statement is effective January 1, 2010, and is not expected to have a material impact on the Company's consolidated financial statements.

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. This Statement is effective January 1, 2010, and is not expected to have a material impact on the Company's consolidated financial statements.

Effective June 30, 2009, the Company adopted the FASB accounting standard which provides guidance on the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued (ASC 855—Subsequent Events). The guidance in this standard is very similar to current guidance provided in accounting literature and, therefore, will not result in significant changes in practice. Subsequent events have been evaluated through April 15, 2010, the date the Company's financial statements were available to be issued.

In January 2010, the FASB issued Accounting Standards Update ("ASU") Extractive Activities—Oil and Gas (ASC 932) Oil and Gas Reserve Estimation and Disclosures, which is effective for year-end 2009 reporting and amends the requirements for oil and gas reserve estimation and disclosures. The objective of the ASU was to align accounting standards with the previously issued Securities and Exchange Commission ("SEC") requirements on oil and gas reserve estimation and disclosure. The main provisions of the ASU are to expand the definition of oil and gas producing activities to include the extraction of resources which are saleable as synthetic oil or gas, to change the price assumption used for reserve estimation and future cash flows to a twelve month average from the year-end price and to amend the geographic disclosure requirements for reporting reserves and other supplementary oil and gas data. See Note 20—Supplementary Oil and Gas Data.

3. Investment and Acquisition—Pioneer Natural Resources (Nigeria) 320 Limited

3. Investment and Acquisition—Pioneer Natural Resources (Nigeria) 320 Limited (Continued)

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. As of December 31, 2009, the Company was concluding its legal and financial affairs in Nigeria.

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 allow 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 being constructed by MODEC. Upon completion, the FPSO facility will be located in the Jubilee Unit. The amounts loaned to TGSL are recorded as short-term notes receivables and accrue interest at rates between 3.74% and 3.78% per annum. The total participation limit for Kosmos Ghana is $52.1 million which was fully funded as of December 31, 2009. The Company initially reflected this funding as an operating activity, but has reclassed to an investing activity in the consolidated statement of cash flows for the year ended December 31, 2009, as we believe this presentation to be more appropriate. Also, included in the notes receivable balance at December 31, 2009, is total interest income of $0.2 million for the year then ended. MODEC is required to repay TGSL the principal and accrued interest 15 days after the termination of the Letter of Intent for the FPSO, which is set to expire on May 7, 2010. Under the participation agreements, TGSL is then required to repay Kosmos Ghana its proportionate share of the principal and accrued interest within five business days after receipt of funds from MODEC.

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 Laws, 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 contractors and 65% of an area from the DT contractors. 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 commenced development operations and negotiated a more comprehensive unit agreement, the Unitization and Unit Operating Agreement ("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), 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 the 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 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.

As of December 31, 2009, $41.6 million were recorded as long-term receivables for joint interest billings to EO Group ($30.4 million) and GNPC ($11.2 million) for their respective share of the development costs for the Jubilee Unit. All of EO Group's share of costs to first production 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, with Kosmos Ghana entitled to receive all of EO Group's production proceeds until repayment in full. Under the WCTP Petroleum Agreement, GNPC exercised its option in December 2008 to acquire an additional paying interest of 2.5% of WCTP in the commercial discovery with respect to the Jubilee Field development. In January 2009, under the DT Petroleum Agreement, GNPC exercised its option to acquire an additional paying interest of 5% of DT in the commercial discovery with respect to the Jubilee Field development. GNPC is obligated to pay its 2.5% of WCTP and its 5% of DT of all future petroleum costs, including development and production costs. 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. We do not expect to begin commercial production until late 2010 and have revenues from production before 2011; therefore, no payments are due on these receivables until 2011.

The Company recorded $0.3 million, $0.6 million and $1.9 million of depreciation expense for the years ended December 31, 2007, 2008 and 2009, respectively.

The following table reflects the Company's capitalized exploratory well activities during the years ended December 31, 2007, 2008 and 2009, respectively:

As of December 31, 2009, the exploratory well costs capitalized in excess of one year since the completion of drilling relate to the Odum-1 well in the WCTP Block. All costs incurred are approximately two years old. 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. As provided under Article 8.17 of the WCTP Petroleum Agreement, the contractor group intends to perform such additional evaluation, studies, planning and potential well operations, including exploration activities. 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, 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.

At December 31, 2008 and 2009, $16.8 million and $97.8 million were recorded for invoices received but not paid in 2008 and 2009, respectively. Accrued liabilities were $51.9 million and $41.8 million at December 31, 2008 and 2009, respectively. Accrued liabilities consist of the following:

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 offshore Ghana. 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, of which $825.0 million has been committed, and adding a new lender as a party to the facilities agreement. If the conditions set forth in the commercial debt facilities are met, the uncommitted $75.0 million is available to the Company by delivering a request notice to the senior facility agent. These conditions were not met as of December 31, 2009. See Note 19—Subsequent Events.

The revised $900.0 million of commercial debt facilities are divided among a senior facility of $700.0 million, a junior facility of $100.0 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 facilities have a final maturity date of December 15, 2015, while the junior facilities have a final maturity date of June 15, 2016.

Lenders include Standard Chartered Bank, BNP Paribas SA, Société Générale, IFC, Absa Bank Limited, Barclays Capital PLC, Credit Suisse International, Africa Finance Corporation, Calyon and Cordiant Emerging Loan Fund III, L.P. Standard Chartered Bank is the Global Coordinator for the

facilities, Co-Technical and Modeling Bank and Senior Facility Agent. BNP Paribas SA is Security Trustee, Junior Facility Agent and has the role of Hedging Coordinator Bank, and Société Générale is the Lead Technical and Modeling Bank.

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 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, 2009, borrowings against the commercial debt facilities totaled $285 million, all of which were senior debt. There was $540 million of availability from the commercial debt facilities as of December 31, 2009. See Note 19—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 (net of capitalized interest of $0.6 million) and commitment fees were $4.8 million for the year ended December 31, 2009.

At December 31, 2009, the scheduled maturities of long-term debt during the next five years and thereafter are as follows:

Debt issue costs associated with the facilities were $1.6 million and $92.2 million at December 31, 2008 and 2009, respectively. The Company amortizes debt issue costs using the straight-line method over the life of the facilities. Amortization expense of $2.5 million was recorded for the year ended December 31, 2009.

Series A, Series B and Series C contributions were as follows (in thousands, including unit data):

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 accumulated preferred return for the Convertible Preferred Units totaled approximately $36.4 million and $87.9 million at December 31, 2008 and 2009, respectively. The holders of the Convertible Preferred Units will realize the accumulated preferred return upon the consummation of a Qualified Public Offering. As no distributions have been declared to date and the Convertible Preferred Units are not currently redeemable, the preferred return on the Convertible Preferred Units has not been recorded, however the accumulated preferred return will be recorded once a Qualified Public Offering is probable and will be treated as a distribution to preferred holders, impacting net income/loss available to common unit holders and earnings per unit calculations at that time.

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 value 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" as defined in the Agreement, each outstanding Common Unit and each outstanding Convertible Preferred Unit would be converted (with values determined in the Agreement) into common shares and preferred shares, respectively, of the IPO Corporation, as defined in the Agreement. Upon consummation of a Qualified Public Offering, each share of preferred shares of the IPO Corporation would be redeemed for cash or common shares of the IPO Corporation for 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 value of any additional common shares issued will be treated as a distribution to the unit holders, impacting net loss available to common unit holders and earnings per unit calculations at that time. The Convertible Preferred Units are classified as mezzanine equity as the Company cannot solely control the method of redemption and the Convertible Preferred Unit holders control the Company's Board of Directors.

As a development stage entity with no revenues, Kosmos is actively engaged in an ongoing process to anticipate and meet its funding requirements. To date we have raised three rounds of equity funding: the Series A, Series B and Series C equity capital financings. During 2009, we secured commercial debt facilities from ten financial institutions, including the IFC, for up to $900 million, of which $825 million has been committed, to be utilized in funding the Company's share of the Jubilee Field Phase 1 development. These facilities were closed on July 13, 2009. See Note 10—Commercial Debt Facilities and Note 19—Subsequent Events.

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 zero, $6.0 million and $9.6 million for the years ended December 31, 2007, 2008 and 2009, respectively.

The Company measures fair value in accordance with the FASB ASC 820—Fair Value Measurements. These standards establish a hierarchy for the inputs used to measure fair value based on the source of the input, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3). Included in cash and cash equivalents is $59.8 million, which approximates fair value, in money market accounts that are considered Level 1 inputs. The carrying amount of our floating-rate debt approximates fair value. The Company does not have any other assets and liabilities measured at fair value on a recurring basis as of December 31, 2009. Additionally, the Company had no nonfinancial assets or liabilities carried at fair value, measured on a nonrecurring basis, at December 31, 2009.

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.

A reconciliation of the differences between the Company's applicable statutory tax rate and the Company's effective income tax rate follows:

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 effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows:

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 change in valuation allowance of $14.6 million is primarily due to current foreign activity. The net deferred tax asset for Cameroon and Morocco and its offsetting valuation allowance have been broken out in the table above for both the current and prior year. In the past, this net deferred tax asset and offsetting valuation allowance were shown as a net zero.

The Company has foreign net operating loss carryforwards of approximately $39.3 million which begin to expire in 2011 through 2014 and approximately $687 thousand 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 we operate. The Company is open to U.S. federal income tax examinations for tax years 2007 through 2009, and to foreign income tax examinations for tax years 2004 through 2009. In addition, the Company is open to Texas margin tax examinations for the tax years 2005 through 2009.

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.

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 $68 thousand, $315 thousand and $550 thousand for the years ended December 31, 2007, 2008 and 2009, respectively.

15.7 million are designated as profit units. The following is a summary of the Company's profit unit activity:

At December 31, 2009, the remaining unrecognized compensation cost from profit units was $3.4 million, which will be recognized over a weighted-average period of 2.5 years. Total profit unit compensation expense recognized in income was $0.4 million, $3.7 million and $3.5 million for the years ended December 31, 2007, 2008 and 2009, 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 1.4% to 5.1%, expected life ranging from 4.3 to 8.1 years and projected turnover rate of 7.0% for employees and none for management.

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, 2008 and 2009, liabilities of zero and $1.7 million, respectively, were recorded for tenant improvement allowances. The Company has received $2.0 million for leasehold incentives from Harvest/NPE LP as of December 31, 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 $0.4 million, $0.9 million and $1.4 million for the years ended December 31, 2007, 2008 and 2009, respectively.

Future minimum rental commitments under these leases at December 31, 2009, are as follows:

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, the rig rate was adjusted to $543 thousand per day. 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, 2009, are (in thousands): 2010—$107,533; 2011—$112,964; and 2012—$160,757.

On October 18, 2009, Kosmos Ghana agreed to provide an irrevocable standby Letter of Credit ("LOC") in respect of its Jubilee paying interest share of Tullow Ghana Limited's LOC related to their

drilling contract for the Eirik Raude drilling rig. Kosmos LOC is limited to a maximum amount of $23 million. Finalization of the terms is pending as of the date the financial statements are available to be issued.

In November 2007, Kosmos commenced arbitration proceedings in London against Orandi Petroleum ("Orandi") and Oranto Petroleum Ltd. ("Oranto") and Orandi began litigation against Kosmos in Nigeria regarding a dispute over costs of the Echim-1 well in Block OPL 320 in Nigeria. In March 2008, Kosmos received $6 million from Oranto as settlement of the London arbitration. On July 15, 2008, the parties agreed to settle all disputes whereby Oranto and Orandi would pay their share of all costs incurred after January 1, 2008. As of December 31, 2009, Orandi had paid all such costs incurred through January 1, 2009; however, Oranto has not paid any costs. The Company has withdrawn from Block OPL 320 and Joint Operating Agreement and is concluding its affairs in Nigeria.

We do not apply hedge accounting treatment to our oil derivative contracts and therefore the changes in the fair values of these instruments will be recognized in income in the period of change. The fair value changes, along with the cash settlements of expired contracts will be shown in our consolidated statements of operations.

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. We do not hold or issue derivative financial instruments for trading purposes. 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.

All of the mark-to-market valuations used for our oil derivative contracts are provided by external sources and are based on prices that are actively quoted. We manage and control market and counterparty credit risk in accordance with policies and guidelines approved by the Board. In accordance with those 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 derivative contracts are with parties that are lenders under our commercial debt facilities.

In March 2010, we also entered into interest rate swaps to hedge our exposure to the cash flow risk caused by the effects of LIBOR changes on the project finance commercial debt facilities. The interest rate swaps effectively convert $322.5 million, of the then $725.0 million, LIBOR based debt to fixed rate debt having an average interest rate of 2.27% plus an applicable margin, currently 5.81%, which will equal an average effective interest rate of 8.08%. The effective date of these swaps is January 5, 2010, and the maturity date is June 30, 2016. Our interest rate swaps are entered into as required under the terms of our commercial debt facilities and are with parties that are lenders under our commercial debt facilities.

We designated our interest rate swaps as a cash flow hedge. Based on our assessment of effectiveness using the change in variable cash flows method, we determined that the interest rate swaps are effective in offsetting the variability in interest payments on our $322.5 million variable rate debt resulting from changes in LIBOR. Under hedge accounting, we will adjust our cash flow hedges to their fair value on a quarterly basis with a corresponding offset to accumulated other comprehensive income. Also on a quarterly basis, we will measure hedge effectiveness by comparing the present value of the cumulative change in the expected future interest to be paid or received on the variable leg of our swaps against the expected future interest payments on our $322.5 million variable rate debt. Any ineffectiveness will be reclassified from accumulated other comprehensive income to interest expense.

In January 2010, the Company borrowed $360.9 million under the senior and junior facilities. Additionally, in March 2010, the Company borrowed $79.1 million under the senior facilities. As of the date the financial statements are available to be issued, borrowings against the commercial debt facilities totaled $725.0 million and the scheduled principal maturities during the next five years and thereafter are (in thousands): 2010—zero; 2011—$75,000; 2012—$250,000; 2013—$210,000; 2014—$90,000; and thereafter—$100,000.

Effective January 5, 2010, in accordance with the fourth amendment to our project financing commercial debt facilities agreement and in addition to the restricted cash described in Note 2—Accounting Policies, we have the following restricted cash on hand as of the date the financial statements are available to be issued: (1) not less than $50 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; (2) not less than $9 million in the Stamp Duty Reserve account which may be utilized to meet any payment of stamp duty taxes in Ghana; and (3) not less than $51.4 million in the Reserve Equity account which was deposited in order to maintain the Funding Sufficiency Ratio at 1:1 and can only be withdrawn some time after Project Completion or when there are available commitments to the facilities of at least $900 million. We have the option to invest the restricted cash in an account which is satisfactory to the facility agents.

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 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 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. Since we have not yet begun production as of December 31, 2009, there are no disclosures related to item (4) above. Since we had no proved oil and gas reserves to report as of December 31, 2008, there are no disclosures related to item (6) above.

The following table is a summary of net proved undeveloped oil reserves to Kosmos' interest in the Jubilee Field Phase 1 development in Ghana. There are no reportable gas reserves as of December 31, 2009.

Net proved reserves were calculated utilizing the twelve month average unweighted arithmetic average first day of the month oil price for Brent crude for the period January through December 2009. The average Brent crude price of $59.60 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 $59.95 per barrel. This oil price is held constant throughout the lives of the properties.

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 methods, and government regulations. Inherent uncertainties exist in estimating proved reserve quantities, projecting future production rates and timing of development expenditures.

The following table presents aggregate capitalized costs related to 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.

The following table provides projected future net cash flows based on the twelve month average unweighted arithmetic average first day of the month oil price for Brent crude for the period January through December 2009. The average Brent crude price of $59.60 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 $59.95 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 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.

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:

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 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.

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.

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, 2007, Kosmos Energy Holdings issued the following unregistered securities for the consideration listed:

During the fiscal year ended December 31, 2008, Kosmos Energy Holdings issued the following unregistered securities for the consideration listed:

During the fiscal year ended December 31, 2009, Kosmos Energy Holdings issued the following unregistered securities for the consideration listed:

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.

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.

Kosmos Energy Holdings

(A Development Stage Entity)

Condensed Parent Company Balance Sheets

Kosmos Energy Holdings

(A Development Stage Entity)

Condensed Parent Company Statements of Operations

Kosmos Energy Holdings

(A Development Stage Entity)

Condensed Parent Company Statements of Cash Flows

(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

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.

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 January 13, 2011.

KNOW ALL PERSONS BY THESE PRESENTS, that each individual whose signature appears below hereby constitutes and appoints each of Brian F. Maxted and W. Greg Dunlevy, acting singly, his true and lawful agent, proxy and attorney-in-fact, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to (i) act on, sign and file with the Securities and Exchange Commission and/or the Registrar of Companies in Bermuda any and all amendments (including post-effective amendments) to this registration statement together with all schedules and exhibits thereto and any subsequent registration statement filed pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and/or the Companies Act 1981 of Bermuda (the "Bermuda Companies Act") together with all schedules and exhibits thereto, (ii) act on, sign and file such certificates, instruments, agreements and other documents as may be necessary or appropriate in connection therewith, (iii) act on and file any supplement to any prospectus included in this registration statement or any such amendment or any subsequent registration statement filed pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and (iv) take any and all actions which may be necessary or appropriate in connection therewith, granting unto such agents, proxies and attorneys-in-fact, and each of them, full power and authority to do and perform each and every act and thing necessary or appropriate to be done, as fully for all intents and purposes as he might or could do in person, hereby approving, ratifying and confirming all that such agents, proxies and attorneys-in-fact or any of their substitutes may lawfully do or cause to be done by virtue thereof.

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.

We consent to the reference to our firm under the caption "Experts" and to the use of our report dated April 15, 2010, related to the consolidated financial statements and schedule of Kosmos Energy Holdings in the Registration Statement (Form S-1) and related Prospectus of Kosmos Energy Ltd. dated January 13, 2011.

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 2, 2010, and as of June 30, 2010, dated September 10, 2010, in this Form S-1 Registration Statement and the related Prospectus to be filed on or about January 14, 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 relate.

Kosmos Energy Ltd. is filing a Registration Statement on Form S-1 with the Securities and Exchange Commission under the Securities Act of 1933, as amended (the "Securities Act"), in connection with the initial public offering of its common shares. In connection therewith, I hereby consent, pursuant to Rule 438 of the Securities Act, to being named as a nominee to the board of directors of Kosmos Energy Ltd. in the Registration Statement, as may be amended from time to time. I also consent to the filing of this consent as an exhibit to such Registration Statement and any amendments thereto.

		Amount of Loss Recognized in AOCI(L) on Effective Portion

		Nine Months Ended September 30
	Location of Gain/(Loss)	Nine Months Ended September 30
Derivatives in Cash Flow Hedging Relationships	Location of Gain/(Loss)	2009		2010
		(In thousands)
Interest rate derivatives	AOCI(L)	$	—	$	(455	)

		Amount of Loss Reclassified from AOCI(L) into Earnings

		Nine Months Ended September 30
	Location of Gain/(Loss) Reclassified from AOCI(L) into Earnings	Nine Months Ended September 30
Derivatives in Cash Flow Hedging Relationships		2009		2010
		(In thousands)
Interest rate derivatives	Interest expense	$	—	$	(4,383	)

			Amount of Gain (Loss) Recognized in Earnings on Derivatives

			Nine Months Ended September 30
		Location of Gain (Loss) Recognized in Earnings on Derivatives	Nine Months Ended September 30
Derivatives Not Designated as Hedging Instruments			2009		2010
			(In thousands)
Commodity derivatives		Derivatives, net	$	—	$	(15,310	)
Interest rate derivatives		Interest expense		—		(9,079	)

	Total		$	—	$	(24,389	)

	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

Total Issuances—Series A	$	161,298	$	131,972	$	6,730		$	300,000

Series B:
2008 Issuance of 7,986 units	$	107,718	$	88,132	$	3,806		$	199,656
2009 Issuance of 12,014 units		161,576		132,199		6,569			300,344

Total Issuances—Series B	$	269,294	$	220,331	$	10,375		$	500,000

Series C:
November 2, 2009 Issuance of 885 units	$	7,126	$	5,830	$	288		$	13,244

Total Issuances—Series C	$	7,126	$	5,830	$	288		$	13,244

		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 September 30 2010
		(In thousands)
Assets:
Money market accounts		$	107,385	$	—	$	—	$	107,385
Interest rate derivatives			—		133		—		133

	Total assets	$	107,385	$	133	$	—	$	107,518

Liabilities:
Commodity derivatives		$	—	$	15,310	$	—	$	15,310
Interest rate derivatives			—		10,908		—		10,908

	Total liabilities	$	—	$	26,218	$	—	$	26,218

		December 31, 2009				September 30, 2010

		Carrying Value		Fair Value		Carrying Value		Fair Value
		(In thousands)
Assets:
	Money market accounts	$	59,757	$	59,757	$	107,385	$	107,385
	Interest rate derivatives	$	—	$	—	$	133	$	133
Liabilities:
	Commodity derivatives	$	—	$	—	$	15,310	$	15,310
	Interest rate derivatives	$	—	$	—	$	10,908	$	10,908

		Profit Units

		(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		28		6.18
	Relinquished		(6	)	3.41

Outstanding at September 30, 2010			13,529		0.83

		Profit Units

		(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		28		6.18
	Vested		(2,198	)	0.96
	Relinquished		(6	)	3.41

Non-vested at September 30, 2010			4,781		1.14

												Period April 23, 2003 (Inception) Through December 31 2009

			Years Ended December 31
			2007			2008			2009
			(In thousands)
Revenues and other income:
	Oil and gas revenue		$	—		$	—		$	—		$	—
	Interest income			1,568			1,637			985			4,911
	Other income			2			5,956			9,210			21,590

		Total revenues and other income		1,570			7,593			10,195			26,501
Costs and expenses:
	Exploration expenses, including dry holes			39,950			15,373			22,127			93,324
	General and administrative			18,556			40,015			55,619			137,198
	Depreciation and amortization			477			719			1,911			4,082
	Amortization—debt issue costs			—			—			2,492			2,492
	Interest expense			8			1			6,774			6,807
	Equity in losses of joint venture			2,632			—			—			16,983
	Other expenses, net			17			21			46			855

		Total costs and expenses		61,640			56,129			88,969			261,741

Loss before income taxes				(60,070	)		(48,536	)		(78,774	)		(235,240	)
	Income tax expense			718			269			973			1,960

Net loss			$	(60,788	)	$	(48,805	)	$	(79,747	)	$	(237,200	)

		Profit Units			Weighted-Average Grant-Date Fair Value

		(In thousands)
Outstanding at December 31, 2006			2,942		$	0.01
	Granted		1,067			0.46
	Relinquished		(25	)		0.11

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

		Profit Units			Weighted-Average Grant-Date Fair Value

		(In thousands)
Non-vested at December 31, 2006			1,915		$	0.01
	Granted		1,067			0.46
	Vested		(877	)		0.06
	Relinquished		(25	)		0.11

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

	Office Leases

	(In thousands)
2010	$	1,575
2011		1,615
2012		1,636
2013		1,660
2014		1,168
Thereafter		381

		Oil

		(Millions of barrels)
Net proved undeveloped reserves at December 31, 2008			—
	Discoveries and extensions		55
	Production		—
	Purchases of minerals-in-place		—

Net proved undeveloped reserves at December 31, 2009			55

		Ghana		Other West Africa		Total

		(In thousands)
*As of December 31, 2008*
	Unproved properties	$	198,039	$	5,352	$	203,391
	Proved properties		—		—		—

			198,039		5,352		203,391
Accumulated depreciation, depletion and amortization			—		—		—

Net capitalized costs		$	198,039	$	5,352	$	203,391

*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 depreciation, depletion and amortization			—		—		—

Net capitalized costs		$	587,885	$	7,206	$	595,091

		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

	Ghana

	(In millions)
*At December 31, 2009*
Future cash inflows	$	3,098
Future production and development costs		(1,620	)
Future foreign income tax expenses		(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


SEC registration fee	$	58,050
NYSE listing fee
FINRA filing fee		30,500
Accounting fees and expense
Printing and engraving expenses
Legal fees and expenses
Transfer Agent and Registrar fees
Miscellaneous

Total	$

Recipient	Securities Issued	Consideration Received by Kosmos Energy Holdings

Warburg Pincus	5,650,565 Series A Convertible Preferred Units	$	56,505,650
Blackstone	4,623,188 Series A Convertible Preferred Units	$	46,231,880
Members of management, accredited employee investors and directors, in the aggregate	231,048 Series A Convertible Preferred Units	$	2,310,480

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

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

Exhibit Number			Description of Document

	1.1		Form of Underwriting Agreement*
	3.1		Memorandum of Association of Kosmos Energy Ltd. (the "Company")*
	3.2		Bye-laws of the Company*
	3.3		Fourth Amended and Restated Operating Agreement of Kosmos Energy Holdings (the "Predecessor")*
	3.4		Memorandum of Association of the Predecessor*
	3.5		Articles of Association of the Predecessor*
	4.1		Specimen share certificate*
	4.2		Form of Reorganization Agreement*
	5.1		Opinion of Conyers Dill & Pearman Limited*
	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.*
	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.*

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		Common Terms Agreement, dated July 13, 2009 among Kosmos Energy Finance ("Kosmos Finance"), Kosmos Ghana, Kosmos Energy Development ("Kosmos Development") and the various financial institutions and others party thereto, as amended.*
	10.18		Definitions Agreement, dated July 13, 2009 among Kosmos Finance, Kosmos Ghana, Kosmos Development and the various financial institutions and others party thereto, as amended.*
	10.19		Senior Bank Facility Agreement, dated July 13, 2009 among Kosmos Finance, Kosmos Development, Kosmos Ghana, Standard Chartered Bank, BNP Paribas SA, Societe Generale, Calyon, ABSA Bank Limited, Africa Finance Corporation, Cordiant Emerging Loan Fund III, L.P. and various other financial institutions party thereto, as amended.*
	10.20		Intercreditor Agreement, dated July 13, 2009 among Kosmos Finance, Kosmos Ghana, Kosmos Development and the various financial institutions and others party thereto, as amended.*
	10.21		Form of Long-term Incentive Plan of the Company*
	10.22		Form of Director Indemnification Agreements*
	10.23		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.*
	10.24		Consulting Agreement dated November 17, 2010 between Kosmos Energy Holdings and John R. Kemp*
	21.1		List of Subsidiaries*
	23.1		Consent of Ernst & Young LLP
	23.2		Consent of Netherland, Sewell & Associates, Inc.
	23.3		Consent of Davis Polk & Wardwell LLP*
	23.4		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 June 30, 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


		Kosmos Energy Ltd.
		By:		/s/ BRIAN F. MAXTED Brian F. Maxted Director and Chief Executive Officer

SIGNATURE	TITLE	DATE


/s/ BRIAN F. MAXTED Brian F. Maxted	Director and Chief Executive Officer (Principal Executive Officer)	January 13, 2011
/s/ W. GREG DUNLEVY W Greg. Dunlevy	Chief Financial Officer and Executive Vice President (Principal Financial Officer and Principal Accounting Officer)	January 13, 2011
/s/ JOHN R. KEMP John R. Kemp	Chairman of the Board of Directors	January 13, 2011


		NETHERLAND, SEWELL & ASSOCIATES, INC.
		By:		/s/ G. LANCE BINDER, P.E. G. Lance Binder, P.E. Executive Vice President


		/s/ DAVID I. FOLEY Name: David I. Foley Date: January 13, 2011


		/s/ JEFFREY A. HARRIS Name: Jeffrey A. Harris Date: January 13, 2011


		/s/ DAVID KRIEGER Name: David Krieger Date: January 13, 2011


		/s/ PRAKASH A. MELWANI Name: Prakash A. Melwani Date: January 13, 2011