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Filed Pursuant to Rule 424(b)(1)
Registration No. 333-171700
Registration No. 333-174116

33,000,000 Shares

Kosmos Energy Ltd.

Common Shares

        This is an initial public offering of common shares of Kosmos Energy Ltd. Prior to this offering, there has been no public market for our common shares. Our common shares have been approved for listing on the New York Stock Exchange under the symbol "KOS."

        The underwriters have an option to purchase a maximum of 4,950,000 additional common shares from us to cover over-allotments of common shares. The underwriters can exercise this option at any time within 30 days from the date of this prospectus.

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

        Delivery of the common shares will be made on or about May 16, 2011.

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

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

Joint Bookrunning Managers

Joint Lead Managers

Co-Managers

The date of this prospectus is May 10, 2011.

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        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 June 4, 2011, all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer's obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

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PROSPECTUS SUMMARY

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

Overview

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

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

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

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types offshore Morocco. The following table summarizes our existing licenses and their current development status.

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

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

Our History

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

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

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

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

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

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

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

Our Competitive Strengths

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

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

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

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

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Well-defined production and growth plan

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

Significant upside potential from exploratory assets

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

Oil-weighted asset portfolio in key strategic regions

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

New ventures group focused on expanding our asset portfolio

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

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

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

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

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

Strong financial position

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

Our Strategy

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

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

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

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

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

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

Focus on rapidly developing our discoveries to initial production

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

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

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Identify, access and explore emerging exploratory regions and hydrocarbon plays

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

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

Acquire additional exploration assets

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

Jubilee Phase 1 Reserve and Development Information

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

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

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

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

Discovery Information

        Information about our discoveries is summarized in the following table.

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Prospect Information

        Information about our prospects is summarized in the following table.

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Recent Events

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

        In March 2011, we executed definitive documentation to replace our previous commercial debt facilities with a new $2.0 billion commercial debt facility, with an additional $1.0 billion accordion accessible upon receiving additional commitments. Along with the proceeds of this offering, these funds will support our share of the Jubilee Field 1 development, appraisal of additional discoveries and ongoing exploration activities on new and existing licenses.

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

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

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

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

        In January 2011, we announced that the "Tweneboa-3" appraisal well in the DT Block had successfully confirmed the Greater Tweneboa Area's (comprising the Tweneboa-1 and Tweneboa-2 oil and gas-condensate fields and the neighboring Enyenra light oil field (formerly known as the Owo Field)) resource base potential. The results of drilling, wireline logs and reservoir fluid samples show the Tweneboa-3 appraisal well encountered approximately 29 feet (9 meters) of gas-condensate pay before the well was sidetracked. The sidetrack encountered approximately 112 feet (34 meters) of net gas-condensate pay in high-quality stacked reservoir sandstones in two zones.

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

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

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

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

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

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

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

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

Risks Associated with our Business

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

•

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



•

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



•

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



•

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

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•

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



•

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



•

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

Corporate Information

        We were incorporated pursuant to the laws of Bermuda as Kosmos Energy Ltd. in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings was formed as an exempted company limited by guarantee on March 5, 2004 pursuant to the laws of the Cayman Islands. Pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the closing of this offering, all of the interests in Kosmos Energy Holdings will be exchanged for newly issued common shares of Kosmos Energy Ltd. and as a result Kosmos Energy Holdings will become wholly-owned by Kosmos Energy Ltd.

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

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The Offering

        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.; and



•

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

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

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

Consolidated Statements of Operations Information:

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Consolidated Balance Sheets Information:

Consolidated Statements of Cash Flows Information:

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RISK FACTORS

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

Risks Relating to Our Business

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•

the timing and amount of capital expenditures;

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•

the operator's expertise and financial resources;



•

approval of other block partners in drilling wells;



•

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



•

selection of technology; and



•

the rate of production of reserves, if any.

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

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

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

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

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

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

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

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

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

•

actual prices we receive for oil and natural gas;



•

actual cost of development and production expenditures;



•

derivative transactions;



•

the amount and timing of actual production; and



•

changes in governmental regulations or taxation.

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

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

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

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

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

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

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

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

•

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



•

oil and natural gas prices;



•

our ability to locate and acquire hydrocarbon reserves;



•

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



•

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



•

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



•

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

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

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

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

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

•

changes in supply and demand for oil and natural gas;



•

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

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•

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



•

global economic conditions;



•

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



•

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



•

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



•

the level of global oil inventories and oil refining capacities;



•

weather conditions and natural disasters;



•

technological advances affecting energy consumption;



•

governmental regulations and taxation policies;



•

proximity and capacity of transportation facilities;



•

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



•

the price and availability of alternative fuels.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

We are subject to drilling and other operational environmental hazards.

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

•

fires, blowouts, spills, cratering and explosions;



•

mechanical and equipment problems, including unforeseen engineering complications;



•

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



•

gas flaring operations;



•

marine hazards with respect to offshore operations;



•

formations with abnormal pressures;



•

pollution, other environmental risks, and geological problems; and



•

weather conditions and natural disasters.

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

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

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

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

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

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

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

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

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

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

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

•

severe weather or natural disasters or other acts of God;



•

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



•

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



•

military conflicts.

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

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

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

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

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

•

disrupt our operations;



•

require us to incur greater costs for security;



•

restrict the movement of funds or limit repatriation of profits;



•

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



•

limit access to markets for periods of time.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•

licenses for drilling operations;



•

tax increases, including retroactive claims;



•

unitization of oil accumulations;



•

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



•

environmental requirements and obligations, including remediation or investigation activities.

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

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

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

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

•

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



•

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



•

higher operating costs;



•

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



•

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



•

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



•

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•

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



•

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



•

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

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

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

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

•

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



•

our incurrence of additional indebtedness;



•

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



•

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



•

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



•

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



•

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

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

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

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

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

•

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



•

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



•

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

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•

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



•

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



•

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



•

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



•

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

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

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

        In April 2010, an explosion occurred on 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.

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

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

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

•

recoverable reserves;



•

future oil and natural gas prices and their appropriate differentials;



•

development and operating costs; and



•

potential environmental and other liabilities.

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

•

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



•

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



•

difficulty associated with coordinating geographically separate organizations; and



•

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

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

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

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

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

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

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

•

institute a more comprehensive compliance function;



•

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



•

comply with rules promulgated by the NYSE;



•

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



•

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



•

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



•

establish an investor relations function.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Risks Relating to This Offering

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

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

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

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

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

•

the price of oil and natural gas;



•

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



•

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



•

the recruitment or departure of key personnel;



•

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



•

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



•

analysts' reports or recommendations;



•

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



•

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



•

the issuance of any additional securities of ours;



•

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



•

general economic, political and market conditions.

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

        All of the shares being sold in this offering will be freely tradable without restrictions or further registration under the federal securities laws, unless purchased by our "affiliates" as that term is defined in Rule 144 under the Securities Act. The remaining common shares issued and outstanding upon the closing of this offering are restricted securities as defined in Rule 144 under the Securities Act. Restricted securities may be sold in the U.S. public market only if registered or if they qualify for an exemption from registration, including by reason of Rule 144 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

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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 75% of our issued and outstanding common shares. Consequently, these shareholders have significant influence over all matters that require approval by our shareholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

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

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

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

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

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

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

•

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



•

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



•

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



•

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Forward-Looking Statements

        This prospectus contains estimates and forward-looking statements, principally in "Prospectus Summary," "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Industry" and "Business." Our estimates and forward-looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in this prospectus, may adversely affect our results as indicated in forward-looking statements. You should read this prospectus and the documents that we have filed as exhibits to the registration statement of which this prospectus is a part completely and with the understanding that our actual future results may be materially different from what we expect.

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

•

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



•

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



•

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



•

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



•

termination of or intervention in concessions, rights or authorizations granted by the Ghanaian, Cameroon or Moroccan governments or national oil companies, or any other federal, state or local governments, to us;



•

our dependence on our key management personnel and our ability to attract and retain qualified technical personnel;



•

the ability to obtain financing and the terms under which such financing may be available;



•

the volatility of oil and natural gas prices;



•

the availability and cost of developing appropriate infrastructure around and transportation to our discoveries and prospects;



•

the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;



•

other competitive pressures;



•

potential liabilities inherent in oil and natural gas operations, including drilling risks and other operational and environmental hazards;



•

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



•

cost of compliance with laws and regulations;



•

changes in environmental, health and safety or climate change laws, greenhouse gas regulation or the implementation, or interpretation, of those laws and regulations;



•

environmental liabilities;



•

geological, technical, drilling and processing problems;

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•

military operations, terrorist acts, wars or embargoes;



•

the cost and availability of adequate insurance coverage;



•

our vulnerability to severe weather events; and



•

other risk factors discussed in the "Risk Factors" section of this prospectus.

        The words "aim," "anticipate," "believe," "continue," "estimate," "expect," "intend," "may," "plan," "should," "will" and similar words are intended to identify estimates and forward-looking statements. Estimates and forward-looking statements speak only as of the date they were made, and, except to the extent required by law, we undertake no obligation to update or to review any estimate and/or forward-looking statement because of new information, future events or other factors. Estimates and forward-looking statements involve risks and uncertainties and are not guarantees of future performance. As a result of the risks and uncertainties described above, the estimates and forward-looking statements discussed in this prospectus might not occur and our future results and our performance may differ materially from those expressed in these forward-looking statements due to, including, but not limited to, the factors mentioned above. Because of these uncertainties, you should not place undue reliance on these forward-looking statements when making an investment decision.

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DIVIDEND POLICY

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

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USE OF PROCEEDS

        We estimate that our net proceeds from the sale of 33,000,000 common shares in this offering will be approximately $552.9 million after deducting estimated offering expenses payable by us of $5.5 million and underwriting discounts and commissions. If the over-allotment option is exercised in full, we estimate that our net proceeds will be approximately $636.6 million.

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

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

•

$175.0 million for development in Ghana;



•

$225.0 million for exploration and appraisal in Ghana;



•

$30.0 million for exploration and appraisal in Cameroon;



•

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



•

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

        The ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil and natural gas and the prices we receive from the sale thereof, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, and the actual cost of exploration, appraisal and development of our oil and natural gas assets. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

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CORPORATE REORGANIZATION

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

        The reorganization will consist of a series of internal transactions and changes followed by an exchange of the vested and unvested common and preferred units in Kosmos Energy Holdings for common shares in Kosmos Energy Ltd. Upon completion of the reorganization, Kosmos Energy Ltd. will directly own all of the equity interests in Kosmos Energy Holdings, and the former holders of the common and preferred units in Kosmos Energy Holdings will own an aggregate of 341,176,471 common shares based on their relative rights as set forth in Kosmos Energy Holdings' operating agreement. See "Description of Share Capital" for additional information regarding the terms of our memorandum of association and bye-laws as will be in effect upon the closing of this offering.

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

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

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CAPITALIZATION

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

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

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DILUTION

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

        Our pro forma net tangible book value at December 31, 2010 after giving effect to our corporate reorganization was $364,095,000, or $1.07 per common share, based on 341,176,471 common shares issued and outstanding prior to the closing of this offering. After giving effect to our corporate reorganization and the sale of 33,000,000 common shares by us in this offering at the initial public offering price set forth on the cover page of this prospectus, less the estimated underwriting discounts and commissions and the estimated offering expenses payable by us, our pro forma as adjusted net tangible book value at December 31, 2010 would be $916,955,000, or $2.45 per common share. This represents an immediate increase in the pro forma net tangible book value of $1.38 per common share to existing shareholders and an immediate dilution of $15.55 per common share to new investors purchasing common shares in this offering. The following table illustrates this per share dilution:

        The following table shows, at December 31, 2010, on a pro forma basis as described above, the difference between the number of common shares purchased from us, the total consideration paid to us and the average price paid per common share by existing shareholders and by new investors purchasing common shares in this offering:

        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 90% and will increase the number of common shares held by new investors to 37,950,000, or 10%. This information is based on common shares issued and outstanding as of December 31, 2010, after giving effect to our corporate reorganization. No material change has occurred to our equity capitalization since December 31, 2010, after giving effect to our corporate reorganization and this offering.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL INFORMATION

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

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

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Consolidated Statements of Operations Information:

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Consolidated Balance Sheets Information:

Consolidated Statements of Cash Flows Information:

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MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Overview

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

        We were incorporated pursuant to the laws of Bermuda as Kosmos Energy Ltd. in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed March 5, 2004. As a holding company, its management operations are conducted through a wholly-owned subsidiary, Kosmos Energy, LLC. Kosmos Energy, LLC is a privately held Texas limited liability company that was formed April 23, 2003. Kosmos Energy, LLC became a wholly-owned subsidiary of Kosmos Energy Holdings on March 9, 2004. Pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the closing of this offering, all of the interests in Kosmos Energy Holdings will be exchanged for newly issued common shares of Kosmos Energy Ltd. and as a result Kosmos Energy Holdings will become wholly-owned by Kosmos Energy Ltd.

Exploration and Other Agreements

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

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Factors Affecting Comparability of Future Results

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

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

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

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

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

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

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

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

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        We entered into the Boujdour Offshore Petroleum Agreement in May 2006. This agreement provides for a tax holiday, at a 0% tax rate, for a period of 10 years beginning on the date of first production from the Boujdour Offshore Block. We currently have recorded deferred tax assets of $6.8 million, recorded at the Moroccan statutory rate of 30%, with an offsetting valuation allowance of $6.8 million. Once we enter into the tax holiday period (when production begins) we will re-evaluate our deferred tax position and at such time may reduce the statutory rate applied to the deferred tax assets in Morocco to the extent those deferred tax assets are realized within the tax holiday period.

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

        We expect to earn income from:

•

oil and natural gas sales to international markets; and



•

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

        We expect that our expenses will include:

•

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



•

maintenance and repair of property and equipment;



•

depreciation of fixed assets;



•

depletion of oilfields and associated abandonment costs;



•

exploration and appraisal costs;



•

costs of acquiring seismic or other geological and geophysical data;



•

selling expenses and general and administrative expenses; and



•

financing expenses, interest expense and foreign exchange losses.

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

•

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



•

changes in the market prices of oil and natural gas;



•

changes in fair value of derivative financial instruments;



•

our success in obtaining new licenses and other acquisitions;



•

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



•

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



•

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

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Results of Operations

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

Year Ended December 31, 2010 vs. 2009

        Oil and gas revenue.    We have recently commenced oil and natural gas production. We did not realize any oil and gas revenue during the years ended December 31, 2009 and 2010.

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

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

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

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

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

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

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

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

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

        Income tax expense (benefit).    Income tax decreased by $78.1 million during the year ended December 31, 2010, as compared to the year ended December 31, 2009, due to the release of the Ghana valuation allowance at December 31, 2010. This release was warranted as it was determined it is more likely than not that Kosmos Ghana will utilize its net deferred tax asset due to the beginning of oil production in late November 2010 and future projected taxable income to be generated from oil sales.

Year Ended December 31, 2009 vs. 2008

        Oil and gas revenue.    We have recently commenced oil and natural gas production. We did not realize any oil and gas revenue during the years ended December 31, 2008 and 2009.

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

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

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

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

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

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

Liquidity and Capital Resources

        As we have, until recently, been a development stage entity, we are actively engaged in an ongoing process to anticipate and meet our funding requirements related to exploring for and developing oil and natural gas resources in Africa. To meet our ongoing liquidity requirements, we have historically secured funding from equity commitments and from commercial debt facilities. We have a proven ability to raise capital, having secured commitments for approximately $2.3 billion of private equity funding and commercial debt funding in the last seven years. In addition, we received our first oil revenues in early 2011 from production from Jubilee Field Phase 1. Accordingly, the cash generated from our operating activities will provide an additional source of funding going forward. We believe that our available cash, together with the net proceeds from this offering and borrowings under our commercial debt facility, will be sufficient to meet our operating needs, service our existing debt, finance internal growth and fund capital expenditures through 2013.

Significant Sources of Capital

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

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

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

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

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

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

        The new commercial debt facility contains financial covenants, requiring the maintenance of:

•

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



•

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

in each case, as calculated on the basis of all available information. The "field life cover ratio" is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of net cash flow through the depletion of the Jubilee Field plus the net present value of capital expenditures incurred in relation to the Jubilee field and certain other fields in Ghana, to (y) the aggregate loan amounts outstanding under the facility. The "loan life cover ratio" is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of net cash flow through the maturity date of the commercial debt facility plus the net present value of capital expenditures incurred in relation to the Jubilee field and certain other fields in Ghana, to (y) the aggregate loan amounts outstanding under the facility.

        Kosmos has the right to cancel all the undrawn commitments under the facility. The amount of funds available to be borrowed under the facility, also known as the borrowing base amount, is determined on June 15 and December 15 of each year as part of a forecast that is prepared and agreed by Kosmos and the Technical and Modelling Banks. The formula to calculate the borrowing base amount is based, in part, on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages.

        As of December 31, 2010, borrowings against our previous commercial debt facilities totaled $1.05 billion, of which $970.0 million was senior debt and $75.0 million was junior debt. As of December 31, 2010, the availability under our commercial debt facilities was $203.0 million, with $205.0 million of committed undrawn capacity provided for in such facilities (the difference being the result of borrowing base constraints). As of March 31, 2011, borrowings against the new commercial debt facility totaled $1.3 billion, with $151 million of availability and $700 million of committed undrawn capacity under such facility.

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

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

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

Capital Expenditures and Investments

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

•

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



•

drill two exploration wells in Cameroon;



•

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



•

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



•

develop our discoveries which we determine to be commercially viable.

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

        In budgeting for our future activities, we have relied on a number of assumptions, including with regard to our discovery success rate, the number of wells we plan to drill, our working interests in our prospects, the costs involved in developing or participating in the development of a prospect, the timing of third party projects and the availability of both suitable equipment and qualified personnel. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if one or more of our assumptions prove to be incorrect or if we choose to expand our hydrocarbon asset acquisition, exploration, appraisal or development efforts more rapidly than we presently anticipate, and we may decide to raise additional funds even before we need them if the conditions for raising capital are favorable. We may seek to sell equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could result in dilution to our shareholders. The incurrence of additional indebtedness could result in increased fixed obligations and could also result in additional covenants that could restrict our operations.

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

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

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

•

$175.0 million for development in Ghana;



•

$225.0 million for exploration and appraisal in Ghana;



•

$30.0 million for exploration and appraisal in Cameroon;



•

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



•

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

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

Cash Flows

        Operating activities.    Net cash used in operating activities in 2010 was $191.8 million compared with net cash used in operating activities of $27.6 million and $65.7 million in 2009 and 2008, respectively. The increase in cash used in 2010 when compared to 2009 is mainly due to changes in working capital related to receivables of $66.1 million, primarily joint interest billings, timing of payments of $15.1 million, prepaid drilling costs of $12.5 million, increases in interest expense of $45.7 million and $28.3 million of general and administrative expenses. The decrease in cash used in 2009 when compared to 2008 is primarily attributed to timing of payments related to working capital expenditures offset by increases in seismic exploration costs of $6.7 million and $6.8 million of interest expense.

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

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

Contractual Obligations

        The following table summarizes by period the payments due for our estimated contractual obligations as of December 31, 2010:

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        The following table presents maturities by expected maturity dates under our commercial debt facilities, the weighted average interest rates expected to be paid on the credit facilities given current contractual terms and market conditions and the debt's estimated fair value. Weighted-average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not take into account any amortization of debt issue costs.

Off-Balance Sheet Arrangements

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

Critical Accounting Policies

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

        Revenue Recognition.    We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. Oil production commenced on November 28, 2010 and we received revenues from oil production in early 2011. As of December 31, 2010, no revenues had been recognized in our financial statements.

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

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

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

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

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

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

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

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

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

        The Company had net deferred tax assets in Ghana totaling approximately $20.6 million at December 31, 2009 primarily relating to capitalized operating expenses incurred during the development phase of the Jubilee Field. Prior to the commencement of production from the Jubilee Field on November 28, 2010, the Company maintained a full valuation allowance against its net deferred tax asset. However, at December 31, 2010, the Company determined that it was more likely than not that the deferred tax asset for its Ghana operations would be recognized, resulting in the valuation allowance no longer being necessary. Therefore, we released the $20.6 million deferred tax asset valuation allowance and recognized $56.9 million of deferred tax assets generated during 2010. The factors that the Company considered are discussed below. Based on these factors, the Company concluded that many of the considerations that previously led to the need for a valuation allowance related to the Ghana deferred tax assets no longer exist as of December 31, 2010. The net change in the valuation allowance of $3.6 million is due to the release of the Ghana valuation allowance netted against current year activity in Morocco and Cameroon.

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

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

•

The commencement of oil production on November 28, 2010. Equipment and infrastructure was fully in place in the fourth quarter of 2010 immediately prior to production commencing, and

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the November 28, 2010 successful commencement of production confirmed our expectations that these assets could be utilized to successfully produce from the field with an economical cost structure.

•

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



•

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



•

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



•

The ability to recover our deferred tax assets based on our projections of taxable income for 2011 and future years. Production volumes utilized in our projection are based on our proved reserve estimates, which have been independently verified, and our schedule for production which has been approved by the Jubilee Unit partners and, to date, has matched actual production volumes achieved since first oil production commenced on November 28, 2010. Such schedule anticipates that the FPSO producing from the field will reach its maximum production capacity of 120,000 boepd (28,200 boepd net to us) in the third quarter of 2011. Prices have been estimated based on prices utilized to calculate our standardized measure as of December 31, 2010. We have estimated our expenses based on current contracts and cost structures in place. Our current production is consistent with our development plan and there have been no negative indicators that our production forecast will not be met in 2011. Since year-end, our current production continues to increase according to our plan, currently achieving 60,000-70,000 boepd.



•

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



•

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

Our projection of taxable income is based on a per barrel price of $79.35, which is also used to calculate our standardized measure, and our production forecast, which is based on our proved reserve estimates and our schedule for production. Based on this projection, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2012. Assuming a 25% decrease in prices or volumes, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2013. Assuming a 25% decrease in prices and volumes, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2015. Assuming a decrease in the price of oil to $50 per barrel and no change in anticipated production volumes, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2015. A $50 per barrel price represents an average price per barrel lower than the average price during 2008 and 2009 when oil prices sustained substantial price declines and a 57% decrease from the Dated Brent price of $116.45 per barrel on March 2, 2011. Conversely, assuming a 25% increase in prices (or $99.19 per barrel which would still be less than the $116.45 per barrel price of Dated Brent on March 2, 2011, the date of our financial statements for the year ended December 31, 2010 included herein) and no change in volume, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2011.

•

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

        ASC 740 provides a more-likely-than-not standard in evaluating whether a valuation allowance is necessary after weighing all of the available evidence. Using the more-likely-than-not standard and

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weighing all available positive and negative evidence, the Company concluded that the positive evidence outweighs the negative evidence of cumulative losses incurred during the development stage. Accordingly, we determined that it is more likely than not that the deferred tax asset for our Ghanaian operations would be realized and, therefore, released the $20.6 million valuation allowance that was recorded as of December 31, 2009 and recognized $56.9 million of deferred tax assets generated during 2010.

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

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

        Estimates of Proved Oil and Natural Gas Reserves.    Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As of December 31, 2010, our net proved reserves totaled 56 Mmboe. As additional proved reserves are found in the future, estimated reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the SEC and the FASB. The accuracy of these reserve estimates is a function of:

•

the engineering and geological interpretation of available data;



•

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



•

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



•

the judgments of the persons preparing the estimates.

        Asset Retirement Obligations.    We account for asset retirement obligations as required by the FASB ASC 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long-lived asset with an existing asset retirement obligation is acquired, a liability for that obligation shall be recognized at the asset's acquisition date as if that obligation were incurred on that date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long-lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time as accretion expense in the consolidated statement of operations. Estimating the future restoration and removal costs is difficult and requires management to make estimates and

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

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

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

New Accounting Pronouncements

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

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

•

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



•

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



•

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



•

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

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•

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

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

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

Qualitative and Quantitative Disclosures about Market Risk

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

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

Commodity Derivative Instruments

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

        We manage and control market and counterparty credit risk in accordance with policies and guidelines approved by the Board. In accordance with these policies and guidelines, our executive management determines the appropriate timing and extent of derivative transactions. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification. All of our commodity derivative contracts are with parties that are lenders under our commercial debt facilities. See Note 11—Derivative Financial Instruments in our consolidated financial statements for a description of the accounting procedures we follow relative to our derivative financial instruments.

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Commodity Price Sensitivity

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

Interest Rate Sensitivity

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

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

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INDUSTRY

Global Oil and Gas Industry

Location of Kosmos' Assets in Africa and Related Market Accessibility

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

Distribution of Proved Reserves in 1989, 1999 and 2009

        Source: BP Statistical Review.

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Brent Crude

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

West Africa

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

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

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

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

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

Ghana

Country Overview

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

        Ghana achieved its independence in 1957 under the leadership of Dr. Kwame Nkrumah. On March 6, 2007, Ghana celebrated its 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, Enyenra, Teak and Tweneboa Deep discoveries.

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

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

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

Tano Basin

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

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

Exploration History

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

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

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

Cameroon

Country Overview

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

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

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

Oil and Gas Industry

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

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

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

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

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

Douala Basin

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

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

Rio del Rey Basin

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

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

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

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

Exploration History

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

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

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

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

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

Morocco

Country Overview

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

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

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

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

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Oil and Gas Industry

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

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

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

Aaiun Basin

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

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

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

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

Exploration History

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

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BUSINESS

Overview

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

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

Our Competitive Strengths

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

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

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

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

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Well-defined production and growth plan

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

Significant upside potential from exploratory assets

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

Oil-weighted asset portfolio in key strategic regions

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

New ventures group focused on expanding our asset portfolio

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

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

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

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

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

Strong financial position

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

Our Strategy

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

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

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

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

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

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

Focus on rapidly developing our discoveries to initial production

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

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

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

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

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

Identify, access and explore emerging exploratory regions and hydrocarbon plays

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

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

Acquire additional exploration assets

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

Kosmos Exploration Approach

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

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

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

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

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

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

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

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

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

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

Our Discoveries and Prospects

        Information about our discoveries is summarized in the following table. In interpreting this information, specific reference should be made to the subsections of this prospectus titled "Risk Factors—Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling" and "Risk Factors—We are not, and may not be in the future, the operator on all of our license areas and do not, and may not in the future, hold all of the working interests in certain of our license areas. Therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and to an extent, any non-wholly owned, assets."

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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.

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Prospect Information

        Information about our prospects is summarized in the following table.

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Ghana

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

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

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

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

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

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

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

Our Ghanaian Discoveries

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

Jubilee Discovery

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

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

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

Geology

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

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

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Subsurface Engineering

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

Facilities and wells

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

        The location of the field (in water depths ranging from 4,100 to 5,500 feet (1,250 to 1,700 meters)) led to the decision to use a FPSO as the production facility for the development. The FPSO was built by modifying a Very Large Crude Carrier ("VLCC") with the necessary modifications. The rechristened "Kwame Nkrumah" FPSO is capable of processing 120,000 bopd of oil, 160,000 Mcf per day ("Mcfpd") of natural gas, and storing up to 1.6 million bbl of stabilized crude. Further, the vessel can provide reservoir pressure maintenance through water and natural gas injection support of 232,000 bwpd and 160,000 Mcfpd respectively. Thus far, 16 of the 17 development wells have been drilled, all utilizing large bore 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. Fluid samples recovered from the wells indicate an oil gravity of between 31 and 37 degrees API.

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

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Odum Discovery

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

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

Teak Discovery

        Teak is located in the western portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 650 to 3,600 feet (200 to 1,100 meters). The field is covered by a 3D seismic survey and is a structural-stratigraphic trap with an element of four-way closure. Seismic data indicates the existence of multiple stacked reservoirs ranging in age from Turonian to Campanian. Teak is located updip and northeast of the Jubilee Field and is located within the same reservoir fairway penetrated by the Jubilee wells. The Teak-1 exploratory well penetrated net pay thickness of approximately 239 feet (73 meters) in five Campanian and Turonian zones of high-quality stacked reservoir sandstones consisting of 154 feet (47 meters) of gas and gas-condensate and (85 feet) 26 meters of oil. Oil samples recovered from the Teak-1 well indicate oil of approximately 40 degrees API gravity in Campanian reservoirs and 32 degrees API gravity in Turonian reservoirs. A follow-up appraisal well, Teak-2, was drilled in March 2011. This well penetrated net oil, gas and gas-condensate bearing pay of 89 feet (27 meters) in five Campanian and Turonian zones consisting of 62 feet (19 meters) of net gas-condensate pay, 23 feet (7 meters) of net oil pay, and 3 feet (1 meters) of undetermined hydrocarbon pay.

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

Tweneboa Discovery

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

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

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

Enyenra Discovery (formerly known as Owo)

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

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

Tweneboa Deep Discovery

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

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

Our Ghanaian Prospects

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

Banda Campanian

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

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

Banda Cenomanian

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

Makore

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

Odum East

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

Sapele

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

Funtum

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

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

Assin

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

Okoro

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

Late Cretaceous WCTP Play

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

Walnut

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

DT Sapele

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

Wassa

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

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Adinkra

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

Oyoko

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

Ananta

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

Cameroon

Overview

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

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

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

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

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Geology

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

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

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

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

Our Cameroon Prospects

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

N'gata

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

N'donga

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

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Disangue

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

Pongo Songo

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

Bonongo

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

Coco East

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

Liwenyi

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

Liwenyi South

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

Meme

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

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Bamusso

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

Morocco

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

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

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

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

Lower Cretaceous Play Concept

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

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

Our Moroccan Prospects

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

Gargaa

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

Argane

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

Safsaf

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

Aarar

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

Zitoune

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

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Al Arz

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

Felline

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

Nakhil

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

Barremian Tilted Fault Block Play

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

Our Reserves

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

Summary of Oil and Gas Reserves

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

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Estimated proved reserves

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

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

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

Independent petroleum engineers

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

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

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

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

Technology used to establish proved reserves

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

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

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

Internal controls over reserves estimation process

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

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

Price history

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

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

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

License Areas

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

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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:

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

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