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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

Table of Contents

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

Registration No. 333-          

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

FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

Kosmos Energy Ltd.
(Exact name of registrant as specified in its charter)

Bermuda
(State or other jurisdiction of
Incorporation or organization)
  1311
(Primary Standard Industrial
Classification Code Number)
  98-0686001
(I.R.S. Employer
Identification Number)

Clarendon House
2 Church Street
Hamilton HM 11, Bermuda
(441) 295-1422

(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Brian F. Maxted, Chief Executive Officer
c/o Kosmos Energy Ltd.
8176 Park Lane, Suite 500
Dallas, TX 75231
(214) 445-9600

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Richard D. Truesdell, Jr., Esq.
Davis Polk & Wardwell LLP
450 Lexington Avenue
New York, NY 10017
(212) 450-4000

 

David J. Beveridge, Esq.
Shearman & Sterling LLP
599 Lexington Avenue
New York, NY 10022
(212) 848-4000

Approximate date of commencement of proposed sale to the public:
As soon as practicable after the effective date of this registration statement.

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

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

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

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

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o   Accelerated filer o   Non-accelerated filer ý
(Do not check if a
smaller reporting company)
  Smaller reporting company o



       
 
Title of each Class of Security
being registered

  Proposed Maximum
Aggregate Offering
Price(1)

  Amount of
Registration Fee

 

Common Shares, $0.01 par value per share(2)

  $500,000,000   $58,050

 

(1)
Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

(2)
Includes common shares which may be issued on exercise of a 30-day option granted to the underwriters to cover over-allotments, if any.

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


Table of Contents

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

SUBJECT TO COMPLETION, DATED JANUARY 13, 2011

                    Shares

LOGO

Kosmos Energy Ltd.

Common Shares

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

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

        Investing in our common shares involves risks. See "Risk Factors" on page 19.

                 
 
 
  Price to Public
  Underwriting
Discounts and
Commissions

  Proceeds
to Us

 

Per Common Share

  $     $     $  
 

Total

  $     $     $  

 

        Delivery of the common shares will be made on or about                    , 2010.

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

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

Credit Suisse   Citi

Barclays Capital

The date of this prospectus is                    , 2011.


Table of Contents


TABLE OF CONTENTS

 
  Page

PROSPECTUS SUMMARY

  1

RISK FACTORS

  19

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

  48

DIVIDEND POLICY

  50

USE OF PROCEEDS

  51

CORPORATE REORGANIZATION

  52

CAPITALIZATION

  53

DILUTION

  55

SELECTED HISTORICAL AND PRO FORMA FINANCIAL INFORMATION

  56

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

  59

INDUSTRY

  75

BUSINESS

  84

MANAGEMENT

  120

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

  135

PRINCIPAL SHAREHOLDERS

  136

DESCRIPTION OF SHARE CAPITAL

  139

SHARES ELIGIBLE FOR FUTURE SALE

  146

CERTAIN TAX CONSIDERATIONS

  148

UNDERWRITING

  151

LEGAL MATTERS

  158

EXPERTS

  158

WHERE YOU CAN FIND ADDITIONAL INFORMATION

  158

GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS

  159

INDEX TO FINANCIAL STATEMENTS

  F-1



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


Dealer Prospectus Delivery Obligation

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

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PROSPECTUS SUMMARY

        This summary highlights certain information appearing elsewhere in this prospectus. As this is a summary, it does not contain all of the information that you should consider in making an investment decision. You should read the entire prospectus carefully, including the information under "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the related notes included in this prospectus, before investing. Unless otherwise stated in this prospectus, references to "Kosmos," "we," "us" or "our company" refer to Kosmos Energy Holdings and its subsidiaries prior to the completion of our corporate reorganization, and Kosmos Energy Ltd. and its subsidiaries as of the completion of our corporate reorganization and thereafter. Although we believe that the estimates and projections included in this prospectus are based on reasonable assumptions, investors should be aware that these estimates and projections are subject to many risks and uncertainties as described in "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements." Unless we tell you otherwise, the information in this prospectus assumes that the underwriters will not exercise their over-allotment option. We have provided definitions for some of the industry terms used in this prospectus in the "Glossary of Selected Oil and Natural Gas Terms" beginning on page 159.

Overview

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

        Following our formation in 2003, we acquired our current exploration licenses and established a new, major oil province in West Africa with the discovery of the Jubilee Field in 2007. This was the first of our five discoveries offshore Ghana; it was one of the largest oil discoveries worldwide in 2007 and the largest find offshore West Africa in the last decade. Oil production from the Jubilee Field offshore Ghana commenced on November 28, 2010, and we anticipate receiving our first oil revenues in early 2011. We expect gross oil production from the Jubilee Field to reach its design capacity of 120,000 barrels of oil per day ("bopd") in mid 2011.

        Since our inception, over two thirds of our exploration and appraisal wells have encountered hydrocarbons in quantities that we believe will ultimately be commercially viable. These successes, all of which are offshore Ghana, include the Jubilee Field, Mahogany East (which includes the Mahogany Deep discovery) and three other discoveries in the appraisal and pre-development stage: Odum, Tweneboa and Enyenra (formerly known as Owo). To date we have identified 49 undrilled prospects within our existing license areas, including 20 prospects across three play types offshore Ghana, 10

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

License
  Gross
Acreage
  Location   Discovered
Fields
(Year of Discovery)
  Wells
Drilled
(Successful/
Total)
  Number of
Additional
Prospects
Identified
  Kosmos
Working
Interest
 

Ghana

                                 

West Cape Three Points ("WCTP")(1)

    369,917   Gulf of Guinea's   Jubilee (2007)(3)     13/14     13     30.875 %(4)
 

        Tano Basin   Odum (2008)                    

            Mahogany East (2009)                    

Deepwater Tano ("DT")

   
205,345
 

Gulf of Guinea's

 

Jubilee (2007)(3)

   
14/15
   
7
   
18.000

%(5)

        Tano Basin   Tweneboa (2009)                    

            Enyenra (2010)                    

Cameroon

                                 

Kombe-N'sepe

    747,741   Coastal strip of       0/1     6     35.000 %(6)

        Douala Basin                        

        bordering the Gulf                        

        of Guinea                        

Ndian River(1)

   
434,163

(2)

Coastal strip of

 

   
   
4
   
100.000

%(7)

        Rio del Rey Basin                        

        bordering the Gulf                        

        of Guinea                        

Morocco

                                 

Boujdour Offshore(1)

    10,869,654   Northwest Africa's           19     75.000 %(8)

        Aaiun Basin                        

(1)
Kosmos is the operator under these licenses.

(2)
This acreage reflects the relinquishment of 30% of the current license area of the Ndian River Block upon the approval by Cameroon's Ministry of Industry, Mines and Technological Development of the two year renewal of our exploration period for this block.

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

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

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

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

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

(8)
The Office National des Hydrocarbures et des Mines, the national oil company of Morocco ("ONHYM"), is the only other Boujdour Offshore Block partner and has a 25% participating interest, which will be carried through the exploration phase.

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

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

Our History

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

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

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

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reservoir fairways and attractive trapping geometries. This same approach was successfully employed by members of our management team while at Triton.

        In compiling our asset portfolio, we considered exploration opportunities spanning the entire Atlantic margin of Africa, from Morocco to South Africa. Due to our management team's successful exploration history in the Gulf of Guinea in West Africa during their tenure at Triton, our focus was on acquiring exploration licenses in the same geographical area. We currently hold five licenses from Ghana, Cameroon and Morocco, and we are the operator under three of these licenses.

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

        In 2009, Kosmos entered into a commercial agreement to sell our Ghanaian assets to Exxon Mobil Corporation ("ExxonMobil"). This sale was terminated in August 2010. From the date of the commercial agreement with ExxonMobil through December 31, 2010, we have spent approximately $630 million developing Jubilee Phase 1 and de-risking these assets, made the Enyenra discovery offshore Ghana and drilled six successful appraisal wells on our Mahogany East, Odum and Tweneboa discoveries.

Our Competitive Strengths

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

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

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

        Our asset portfolio consists of five discoveries including the Jubilee Field, which was one of the largest oil discoveries worldwide in 2007 and the largest find offshore West Africa in the last decade. Our other discoveries include Mahogany East, Odum, Tweneboa and Enyenra offshore Ghana, which have geologic characteristics similar to the Jubilee Field. In addition, we have identified 20 additional prospects offshore Ghana, 10 additional prospects in Cameroon and 19 additional prospects offshore Morocco. We expect to make new discoveries and to define additional prospects as our team continues to develop our current asset portfolio and identify and pursue new high-potential assets.

    Well-defined production and growth plan

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

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120,000 bopd design capacity of the floating production, storage and offloading ("FPSO") facility used at the field, in mid 2011. Within the next few years, we intend to expand upon the Jubilee Field Phase 1 development with three additional phases that are designed to maintain production and cash flow from partially de-risked locations. A phased development program allows us to develop the full Jubilee Field on a faster timeline and allowed us to achieve first oil production at an earlier date than traditional development techniques. In addition to Jubilee, we are currently in the development planning stage for Mahogany East, the pre-development planning stage for the Odum discovery, and the appraisal stage for the Tweneboa and Enyenra discoveries. We believe these assets provide additional mid-term production and cash flow opportunities to supplement the phased Jubilee Field development.

    Significant upside potential from exploratory assets

        Since our inception we have focused on acquiring exploratory licenses in emerging petroleum basins in West Africa. This led to the assembly of a hydrocarbon asset portfolio of five licenses with significant upside potential and attractive fiscal terms. In Ghana, we believe our existing licenses offer substantial opportunities for significant growth in shareholder value as a result of numerous high value exploration prospects that are partially de-risked due to their similarity and proximity to our existing discoveries. For instance, we are currently drilling the Teak-1 exploration well north of the Jubilee Field. We plan to drill two exploratory wells in Cameroon, one on our Kombe-N'sepe Block in early 2011 and the other on our Ndian River Block in early 2012.

    Oil-weighted asset portfolio in key strategic regions

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

    New ventures group focused on expanding our high-quality asset portfolio

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

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

        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

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

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

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

    Strong financial position

        Since inception we have been backed by our Investors, namely Warburg Pincus and The Blackstone Group, each supporting our initial growth with substantial equity investments. Each Investor will retain a significant interest in Kosmos following this offering. With the proceeds from this offering, our cash on hand and our commercial debt commitments, we believe we will possess the necessary financial strength to implement our business strategy through early 2013. As of September 30, 2010, we had approximately $292 million of total cash on hand, including $89 million of restricted cash, and $300 million of committed undrawn capacity under our commercial debt facilities. In addition, we have demonstrated the ability to raise capital, having secured commitments for approximately $1.1 billion of private equity funding and $1.25 billion of commercial debt commitments in the last seven years. Furthermore, we anticipate receiving our first oil revenues in early 2011 from the Jubilee Field, after which time a portion of these revenues will be used to fund future exploration and development activities.

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Our Strategy

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

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

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

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

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

    Focus on rapidly developing our discoveries to initial production

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

        First oil from the Jubilee Field commenced on November 28, 2010 and we anticipate receiving our first oil revenues in early 2011. This development timeline from discovery to first oil is significantly less than the industry average of seven to ten years and is a record for a deepwater development at this water depth in West Africa. This condensed timeline reflects the lessons learned by members of our seasoned management while at Triton and during their time at other major deepwater operators. At Triton, the team took the 50,000 bopd Ceiba Field offshore Equatorial Guinea from discovery to first

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oil in fourteen months. Additionally, members of our development team have led other larger scale deepwater developments, such as Neptune and Mensa in the U.S. Gulf of Mexico. These experiences drove the 42-month record timeline from discovery to first oil achieved by the significantly larger Jubilee Field Phase 1 development.

    Identify, access and explore emerging exploratory regions and hydrocarbon plays

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

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

    Acquire additional exploration assets

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

Jubilee Phase 1 Reserve and Development Information

        Jubilee Field Phase 1 is the first of our discoveries to have been determined to have proved reserves. As of June 30, 2010, Netherland, Sewell & Associates, Inc. ("NSAI"), our independent reserve engineers, evaluated the Jubilee Field Phase 1 development to hold gross proved reserves of 250 Mmboe. We currently hold a 23.4913% unit participation interest in this development (subject to any redetermination among the unit partners in this field. See "Risk Factors—The unit partners' respective interests in the Jubilee Unit are subject to redetermination and our interests in such unit may decrease as a result" and "Business—Material Agreements—Exploration Agreements—Ghana—Jubilee Field Unitization"). NSAI estimated our net proved reserves to be approximately 59 Mmboe as of June 30, 2010, consisting of approximately 94% oil. All of our proved reserves are currently located in the Jubilee Field Phase 1 development. Our other discoveries outside of the Jubilee Field Phase 1, including Mahogany East, Odum, Tweneboa, Enyenra and other Jubilee Field phases, do not yet have approved plans of development ("PoDs") and therefore cannot be classified as proved reserves.

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        The Jubilee Field Phase 1 development employs safe, industry standard deepwater equipment with conventional "off-the-shelf" technologies. We believe such technologies and development infrastructure meet industry safety standards and have been consistently used in deepwater oilfield development, with appropriate advancements in recent years. The Jubilee Field Phase 1 development was designed to provide suitable flexibility and expandability in order to minimize capital expenditures associated with subsequent phases of development. The FPSO facility used at the field was delivered and moored to the seabed in July 2010. Planning is underway for the development of additional reservoirs and subsequent phases of the Jubilee Field.

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

Discovery Information

        Information about our discoveries is summarized in the following table.

Discoveries
  License   Kosmos
Working
Interest
  Block Operator(s)   Stage   Type   Expected
Year of PoD
Submission
 

Ghana

                             
 

Jubilee Field Phase 1(1)(2)

  WCTP/DT(3)     23.4913% (5) Tullow/Kosmos(6)   Production   Deepwater     2008 (2)
 

Jubilee Field subsequent phases(2)

  WCTP/DT(3)     23.4913% (5) Tullow/Kosmos(6)   Development   Deepwater     2011  
 

Mahogany East

  WCTP(4)     30.8750 % Kosmos   Development planning   Deepwater     2011  
 

Odum

  WCTP(4)     30.8750 % Kosmos   Development planning   Deepwater     2011  
 

Tweneboa

  DT(4)     18.0000 % Tullow   Appraisal   Deepwater     2012 (7)
 

Enyenra

  DT(4)     18.0000 % Tullow   Appraisal   Deepwater     2013  

(1)
For information concerning our estimated proved reserves in the Jubilee Field as of June 30, 2010, see "Business—Our Reserves."

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

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

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

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

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

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

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Ghana Well Information

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

 
  Operator   Spud Date(1)   Total
Depth
(feet)
  Net
Hydrocarbon
Pay
(feet)
  Status(2)   Comments

Jubilee

                           

J-09 (Mahogany-1)

  Kosmos   05/30/07     12,553     321   Completion Pending   Discovery well for Jubilee in WCTP Block. Drill stem tested at rates in excess of 20,500 bopd. Lower completion installed.

Hyedua-1

  Tullow   07/27/07     13,130     180   Plugged Back   Downdip confirmation well in DT Block.
 

J-10 Water Injector ("WI") (Hyedua-1BP1)

  Tullow   07/27/07     12,631     136   Completion Pending   Whole core obtained. Injectivity test conducted at rates in excess of 20,000 bwpd.

J-16GI Gas Injectors ("GI") (Mahogany-2)

  Tullow   03/06/08     11,296     164   Completion Pending   Updip confirmation well for Jubilee reservoirs. Whole core obtained. Two Drill Stem Tests ("DSTs") conducted.

J-08 (Hyedua-2)

  Tullow   10/09/08     12,018     180   Producing   Drill stem tested at rates in excess of 16,500 bopd. Whole core obtained.

J-04

  Tullow   01/17/09     15,121     90   Plugged Back   Tested the Southeastern edge of the Jubilee fairway.
 

J-04 Sidetrack ("ST")

  Tullow   01/17/09     13,803     199   Completion Pending   Observation well for interference testing.

J-01

  Tullow   03/18/09     12,411     140   Producing    

J-02

  Tullow   03/25/09     13,829     186   Producing   Observation well for interference testing.

J-11WI

  Tullow   05/06/09     13,822     121   Completion Pending   Down structure water injector—net reservoir 281 feet.

J-12WI

  Tullow   05/11/09     14,081     188   Injecting   Down structure water injector—net reservoir 319 feet.

J-15WI

  Tullow   05/14/09     16,949     47   Completion Pending   Only drilled through Upper Mahogany—down structure water injector-net reservoir 87 feet.

J-07

  Tullow   05/19/09     13,599     121   Plugged Back   Whole core obtained.
 

J-07ST

  Tullow   05/19/09     13,701     116   Production Ready    

J-03

  Tullow   09/29/09     12,507     173   Completion Pending   Lower completion installed.

J-05

  Tullow   07/08/09     13,753     193   Completion Pending   Lower completion installed.

J-17

  Tullow   10/07/09     19,390     174   Plugged Back   Only drilled through Upper Mahogany reservoirs.
 

J-17STGI

  Tullow   10/07/09     19,574     197   Completion Pending    

J-13WI

  Tullow   10/10/09     13,058     143   Completion Pending   Down structure water injector—net reservoir 348 feet.

J-14WI

  Tullow   10/14/09     13,999     77   Injecting   Down structure water injector—net reservoir 334 feet.

Mahogany East

                           

Mahogany-3

  Kosmos   11/27/08     14,262     108   Suspended   Discovery well for Mahogany Deep.

Mahogany-4

  Kosmos   08/28/09     12,074     141   Suspended   Updip confirmation well for the Mahogany East reservoirs.

Mahogany Deep-2

  Kosmos   09/29/09     14,193     49   Suspended   Drilled to delineate deep reservoirs—net reservoir of 384 feet.

Mahogany-5

  Kosmos   04/18/10     13,084     75   Suspended   Eastern confirmation of Mahogany East reservoirs.

Odum

                           

Odum-1

  Kosmos   01/18/08     11,109     72   Suspended   Discovery well for Odum.

Odum-2

  Kosmos   11/12/09     8,222     66   Suspended   Confirmation well for Odum.

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  Operator   Spud Date(1)   Total
Depth
(feet)
  Net
Hydrocarbon
Pay
(feet)
  Status(2)   Comments

Tweneboa

                           

Tweneboa-1

  Tullow   01/26/09     13,002     69   Suspended   Discovery well for Tweneboa condensate pays.

Tweneboa-2

  Tullow   12/06/09     13,878     105   Suspended   Confirmation well for Tweneboa. Discovery of Central Oil Channel below condensate pays. Whole core obtained.

Tweneboa-3

  Tullow   11/26/10     12,811     29   Plugged back   Confirmation well for Tweneboa.

Tweneboa-3ST

  Tullow   12/22/10     12,816     112   Suspended    

Onyina

                           

Onyina-1

  Tullow   09/25/10             Abandoned   Dry hole.

Enyenra (formerly known as Owo)

                           

Owo-1

  Tullow   06/10/10     12,766     174   Plugged Back   Discovery well for Enyenra.
 

Owo-1 ST1

  Tullow   07/28/10     13,117     115   Suspended   Lateral confirmation well for Enyenra channels, and discovery wells for deeper condensate pays. Whole core obtained.

Dahoma

                           

Dahoma-1

  Kosmos   02/04/10     14,403       Abandoned   Dry hole.

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

(2)
These terms have the following meanings:

Abandoned   Exploration / appraisal well that was deemed to have no further utility. The well was permanently abandoned, per approved government procedures.

Completion Pending

 

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

Injection Ready

 

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

Plugged Back

 

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

Production Ready

 

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

Suspended

 

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

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Prospect Information

        Information about our prospects is summarized in the following table.

Prospect
  License   Kosmos
Working
Interest (%)
  Block
Operator
  Type   Projected
Spud Year(3)

Ghana(1)

                     
 

Teak

  WCTP     30.875   Kosmos   Deepwater   2010
 

Banda Campanian

  WCTP     30.875   Kosmos   Deepwater   2011
 

Banda Cenomanian

  WCTP     30.875   Kosmos   Deepwater   2011
 

Makore

  WCTP     30.875   Kosmos   Deepwater   2011
 

Odum East

  WCTP     30.875   Kosmos   Deepwater   2011
 

Sapele

  WCTP     30.875   Kosmos   Deepwater   2012
 

Funtum

  WCTP     30.875   Kosmos   Deepwater   2012
 

Assin

  WCTP     30.875   Kosmos   Deepwater   2012
 

Okoro

  WCTP     30.875   Kosmos   Deepwater   Post 2012
 

Late Cretaceous WCTP Play (4 identified targets)

  WCTP     30.875   Kosmos   Deepwater   Post 2012
 

Tweneboa Deep

  DT     18.000   Tullow   Deepwater   2012
 

Walnut

  DT     18.000   Tullow   Deepwater   2012
 

DT Sapele

  DT     18.000   Tullow   Deepwater   2012
 

Wassa

  DT     18.000   Tullow   Deepwater   Post 2012
 

Adinkra

  DT     18.000   Tullow   Deepwater   Post 2012
 

Oyoko

  DT     18.000   Tullow   Deepwater   Post 2012
 

Ananta

  DT     18.000   Tullow   Deepwater   Post 2012

Cameroon(2)

                     
 

N'gata

  Kombe-N'sepe     35.000   Perenco   Onshore   2011
 

N'donga

  Kombe-N'sepe     35.000   Perenco   Onshore   Post 2012
 

Disangue

  Kombe-N'sepe     35.000   Perenco   Onshore   Post 2012
 

Pongo Songo

  Kombe-N'sepe     35.000   Perenco   Onshore   Post 2012
 

Bonongo

  Kombe-N'sepe     35.000   Perenco   Onshore   Post 2012
 

Coco East

  Kombe-N'sepe     35.000   Perenco   Onshore   Post 2012
 

Liwenyi

  Ndian River     100.000   Kosmos   Onshore   2012
 

Liwenyi South

  Ndian River     100.000   Kosmos   Onshore   Post 2012
 

Meme

  Ndian River     100.000   Kosmos   Onshore   Post 2012
 

Bamusso

  Ndian River     100.000   Kosmos   Onshore   Post 2012

Morocco(4)

                     
 

Gargaa

  Boujdour Offshore     75.000   Kosmos   Deepwater   Post 2012
 

Argane

  Boujdour Offshore     75.000   Kosmos   Deepwater   Post 2012
 

Safsaf

  Boujdour Offshore     75.000   Kosmos   Deepwater   Post 2012
 

Aarar

  Boujdour Offshore     75.000   Kosmos   Deepwater   Post 2012
 

Zitoune

  Boujdour Offshore     75.000   Kosmos   Deepwater   Post 2012
 

Al Arz

  Boujdour Offshore     75.000   Kosmos   Deepwater   Post 2012
 

Felline

  Boujdour Offshore     75.000   Kosmos   Deepwater   Post 2012
 

Nakhil

  Boujdour Offshore     75.000   Kosmos   Deepwater   Post 2012
 

Barremian Tilted Fault Block Play (11 identified structures)

  Boujdour Offshore     75.000   Kosmos   Deepwater   Post 2012

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

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

(3)
See "Risk Factors—Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling" and "Risk Factors—Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects."

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

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Recent Events

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

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

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

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

        In August 2010, we announced the execution of definitive documentation to increase our commercial debt facilities by $350 million, raising the total amount of our debt commitments to $1.25 billion. Along with the proceeds from this offering, these funds will support our share of the Jubilee Field Phase 1 development, appraisal of additional discoveries, and ongoing exploration activities.

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

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

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

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

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Risks Associated with our Business

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

Corporate Information

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

        We maintain a registered office in Bermuda at Clarendon House, 2 Church Street, Hamilton HM11, Bermuda. Our registered offices are located at Clarendon House, 2 Church Street, Hamilton HM11, Bermuda. The telephone number of our registered offices is (441) 295-1422. Our U.S. subsidiary maintains its headquarters at 8176 Park Lane, Suite 500, Dallas, Texas 75231 and its telephone number is (214) 445-9600. Our web site is www.kosmosenergy.com. The information on our web site does not constitute part of this prospectus.

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The Offering

Issuer

  Kosmos Energy Ltd.

Common shares offered by us

 

            common shares

Common shares to be issued and outstanding after this offering

 

            common shares

Over-allotment option

 

We have granted to the underwriters an option, exercisable upon notice to us, to purchase up to additional        common shares at the offering price to cover over-allotments, if any, for a period of 30 days from the date of this prospectus.

Use of Proceeds

 

We intend to use the net proceeds from this offering and other resources available to us to fund our capital expenditures, and in particular our exploration and appraisal drilling program and development activities through early 2013 and associated operating expenses, and for general corporate purposes. See "Use of Proceeds" on page 51 of this prospectus for a more detailed description of our intended use of the proceeds from this offering.

Listing

 

We intend to apply to have our common shares listed on the New York Stock Exchange (the "NYSE") under the symbol "KOS."

        Except as otherwise indicated, all information in this prospectus assumes:

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

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

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

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

        The summary historical financial data set forth below should be read in conjunction with the sections entitled "Corporate Reorganization", "Selected Historical and Pro Forma Financial Information" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and with Kosmos Energy Holdings' financial statements and the notes to those financial statements included elsewhere in this prospectus. Kosmos Energy Holdings has been a development stage company. The consolidated statements of operations and cash flows for the years ended December 31, 2005, 2006, 2007, 2008 and 2009 and the consolidated balance sheets as of December 31, 2005, 2006, 2007, 2008 and 2009 were derived from Kosmos Energy Holdings' audited consolidated financial statements. We derived the consolidated statements of operations and cash flows for the nine months ended September 30, 2009 and 2010 and for the period April 23, 2003 (Inception) through September 30, 2010, and the consolidated balance sheets as of September 30, 2009 and 2010 from Kosmos Energy Holdings' unaudited consolidated financial data appearing elsewhere in this prospectus, which, in management's opinion, includes all adjustments necessary for the fair presentation of Kosmos Energy Holdings' financial condition as of such date and Kosmos Energy Holdings' results of operations for such periods. Results of operations for the nine months ended September 30, 2010 are not necessarily indicative of the results of operations that may be achieved for the entire year. The summary unaudited pro forma financial data set forth below is derived from Kosmos Energy Holdings' audited and unaudited consolidated financial statements appearing elsewhere in this prospectus and is based on assumptions and includes adjustments as explained in the notes to the tables.

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Consolidated Statements of Operations Information:

 
   
   
   
   
   
   
   
  Period
April 23, 2003
(Inception)
through
September 30
2010
 
 
  Year Ended December 31   Nine Months Ended
September 30
 
 
  2005   2006   2007   2008   2009   2009   2010  
 
   
   
   
   
   
  (Unaudited)
  (Unaudited)
  (Unaudited)
 
 
  (In thousands)
 

Revenues and other income:

                                                 
 

Oil and gas revenue

  $   $   $   $   $   $   $   $  
 

Interest income

    252     445     1,568     1,637     985     595     2,548     7,459  
 

Other income

    1,822     3,100     2     5,956     9,210     7,578     3,793     25,383  
                                   
   

Total revenues and other income

    2,074     3,545     1,570     7,593     10,195     8,173     6,341     32,842  

Costs and expenses:

                                                 
 

Exploration expenses, including dry holes

    6,718     9,083     39,950     15,373     22,127     17,191     52,764     146,088  
 

General and administrative

    7,801     9,588     18,556     40,015     55,619     43,425     50,804     188,002  
 

Depreciation and amortization

    340     401     477     719     1,911     1,369     1,655     5,737  
 

Amortization—debt issue costs

                    2,492         20,555     23,047  
 

Interest expense

            8     1     6,774         45,645     52,452  
 

Derivatives, net

                            15,310     15,310  
 

Equity in losses of joint venture

    5,157     9,194     2,632                     16,983  
 

Other expenses, net

    7     7     17     21     46     39     20     875  
                                   
   

Total costs and expenses

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

Loss before income taxes

    (17,949 )   (24,728 )   (60,070 )   (48,536 )   (78,774 )   (53,851 )   (180,412 )   (415,652 )

Income tax expense (benefit)

            718     269     973     30     (174 )   1,786  
                                   

Net loss

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

Pro forma net loss (unaudited)(1):

                                                 

Pro forma basic and diluted net loss per common share

                          $                      $          
                                               

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

                          $           $                     
                                               

(1)
Pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the closing of this offering, all of the interests in Kosmos Energy Holdings will be exchanged for newly issued common shares of Kosmos Energy Ltd. based on these interests' relative rights as set forth in Kosmos Energy Holdings' current operating agreement. The weighted average common shares outstanding have been calculated as if the owenership structure resulting from the corporate reorganization was in place since inception. Pro forma information does not give effect to this offering.

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Consolidated Balance Sheets Information:

 
  As of December 31   As of September 30   Pro Forma as
Adjusted as of
September 30
2010(1)
 
 
  2005   2006   2007   2008   2009   2009   2010  
 
   
   
   
   
   
  (Unaudited)
  (Unaudited)
  (Unaudited)
 
 
  (In thousands)
 

Cash and cash equivalents

  $ 14,349   $ 9,837   $ 39,263   $ 147,794   $ 139,505   $ 60,818   $ 202,846   $           

Total current assets

    16,346     10,334     65,960     205,708     256,728     176,536     491,638        

Total property and equipment

    3,788     1,567     18,022     208,146     604,007     492,202     884,628        

Total other assets

    727     3,704     3,393     1,611     161,322     22,650     175,622        

Total assets

    20,861     15,605     87,375     415,465     1,022,057     691,388     1,551,888        

Total current liabilities

    430     1,436     28,574     68,698     139,647     143,829     168,310        

Total long-term liabilities

    1,312             444     287,022     1,902     967,211        

Total convertible preferred units

    41,937     61,952     167,000     499,656     813,244     750,065     813,244        

Total unit holdings

    (22,818 )   (47,783 )   (108,199 )   (153,333 )   (217,856 )   (204,408 )   (396,877 )      

Total liabilities, convertible preferred units and unit holdings

    20,861     15,605     87,375     415,465     1,022,057     691,388     1,551,888        

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

Consolidated Statements of Cash Flows Information:

 
   
   
   
   
   
   
   
  Period
April 23, 2003
(Inception)
through
September 30
2010
 
 
  Year Ended December 31   Nine Months Ended September 30  
 
  2005   2006   2007   2008   2009   2009   2010  
 
   
   
   
   
   
  (Unaudited)
  (Unaudited)
  (Unaudited)
 
 
  (In thousands)
 

Net cash provided by (used in):

                                                 

Operating activities

  $ (13,978 ) $ (9,617 ) $ (17,386 ) $ (65,671 ) $ (27,591 ) $ (6,506 ) $ (133,180 ) $ (272,389 )

Investing activities

    (3,980 )   (14,663 )   (58,161 )   (156,882 )   (500,393 )   (309,801 )   (451,164 )   (1,190,215 )

Financing activities

    30,895     19,768     104,973     331,084     519,695     229,331     647,685     1,665,450  

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RISK FACTORS

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


Risks Relating to Our Business

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

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

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

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We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects, so you should not place undue reliance on any of our measures.

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

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

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

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

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

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

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

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

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

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

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exploration well on the Kombe-N'sepe Block expected to be spud by the end of the first quarter of 2011. Under the production sharing contract covering the Ndian River Block (the "Ndian River Production Sharing Contract"), the initial exploration phase to the Ndian River Block expired on November 20, 2010. On September 16, 2010, in compliance with the Ndian River Production Sharing Contract, we applied to Cameroon's Minister of Industry, Mines, and Technological Development for a two-year renewal of the exploration period (the first of two additional exploration periods of two years each). This application suspends the termination of the license until approval is obtained. We expect that such application will be approved, but upon approval we will be required to relinquish 30% of the license area of the Ndian River Block.

        Regarding our license in Morocco, under the petroleum agreement covering the Boujdour Offshore Block (the "Boujdour Offshore Petroleum Agreement"), the current exploration phase expires on February 26, 2011, and we entered a memorandum of understanding with ONHYM to enter a new petroleum agreement covering the highest potential areas of this block under essentially the same terms as the current license.

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

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

        We may be liable for certain costs if third parties who contract with us are unable to meet their commitments under such agreements. We are currently exposed to credit risk through joint interest receivables from our block and/or unit partners. If any of our partners in the blocks or unit in which we hold interests are unable to fund their share of the exploration and development expenses, we may be liable for such costs. In the past, certain of our WCTP and DT Block partners have not paid their share of block costs in the time frame required by the joint operating agreements for these blocks. This has resulted in such party being in default, which in return requires Kosmos and its non-defaulting block partners to pay their proportionate share of the defaulting party's costs during the default period. Should a default not be cured, Kosmos could be required to pay its share of the defaulting party's costs going forward.

        Furthermore, MODEC, Inc. ("MODEC"), the contractor for the FPSO we are using to produce hydrocarbons from the Jubilee Field, has made a disclosure regarding potential violations by MODEC under the U.S. Foreign Corrupt Practices Act ("FCPA") and other similar anti-corruption legislation. The Jubilee Unit partners as well as the International Finance Corporation ("IFC") are working with MODEC and its legal advisors to investigate this matter. As a result of these concerns, MODEC's long-term funding from a syndicate of international banks for the repayment of funds originally loaned by us, Tullow and Anadarko for the financing of the construction of such FPSO has been suspended pending this investigation. If MODEC cannot access such funding arrangements or otherwise source alternative funding, we may not be repaid for these amounts owed to us. In addition, in order to continue the production activities on the Jubilee Unit, we may be required to contribute further funds before September 15, 2011 in order to purchase the FPSO or find an alternative funding source or buyer. If we were unable to do so and lost access to the MODEC FPSO, we would be unable to produce hydrocarbons from the Jubilee Field unless and until we arranged access to an alternative FPSO.

        Our principal exposure to credit risk will be through receivables resulting from the sale of our oil, which we plan to market to energy marketing companies, refineries, and to cover our commodity derivatives contracts. The inability or failure of our significant customers or counter-parties to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In

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addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Joint interest receivables arise from our block partners. The inability or failure of third parties we contract with to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

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

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

We are not, and may not be in the future, the operator on all of our license areas, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

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

    the timing and amount of capital expenditures;

    the operator's expertise and financial resources;

    approval of other block partners in drilling wells;

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

    selection of technology; and

    the rate of production of reserves, if any.

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

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

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

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

        The process of estimating oil and natural gas reserves is technically complex. It requires interpretations of available technical data and many assumptions, including those relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this prospectus. See "Business—Our Reserves" for information about our estimated oil and natural gas reserves and the PV-10 and Standardized Measure of discounted future net revenues as of June 30, 2010.

        In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is prepared in consultation with independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise.

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

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

        You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with new U.S. Securities and Exchange Commission ("SEC") requirements, we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the

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first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas assets will be affected by factors such as:

    actual prices we receive for oil and natural gas;

    actual cost of development and production expenditures;

    derivative transactions;

    the amount and timing of actual production; and

    changes in governmental regulations or taxation.

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

        Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus. If oil prices decline by $1.00 per bbl, then our PV-10 as of June 30, 2010 would decrease by approximately $23.0 million.

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

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

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

        We expect our capital outlays and operating expenditures to be substantial over the next several years as we expand our operations. Obtaining seismic data, as well as exploration, appraisal, development and production activities entail considerable costs, and we expect that we will need to raise substantial additional capital, through future private or public equity offerings, strategic alliances or additional debt financing.

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

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

    oil and natural gas prices;

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    our ability to locate and acquire hydrocarbon reserves;

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

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

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

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

        While we believe our operations, upon the consummation of this offering, will be adequately funded through early 2013, we do not currently have any commitments for future external funding beyond the capacity of our commercial debt facilities. Additional financing may not be available on favorable terms, or at all. Even if we succeed in selling additional securities to raise funds, at such time the ownership percentage of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we choose to farm-out interests in our licenses, we may lose operating control or influence over such license areas.

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

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

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

    changes in supply and demand for oil and natural gas;

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

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

    global economic conditions;

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

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

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

    the level of global oil inventories and oil refining capacities;

    weather conditions and natural disasters;

    technological advances affecting energy consumption;

    governmental regulations and taxation policies;

    proximity and capacity of transportation facilities;

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

    the price and availability of alternative fuels.

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

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

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

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

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

        The development of the market for natural gas in West Africa is in its early stages. Currently the infrastructure to transport and process natural gas on commercial terms is limited and the expenses associated with constructing such infrastructure ourselves may not be commercially viable given local prices currently paid for natural gas. We will not receive any payment for this quantity of natural gas. Accordingly, there may be limited or no value derived from any natural gas produced from our West African license areas.

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

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

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

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

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

        Furthermore, the marketability of expected oil and natural gas production from our discoveries and prospects will also be affected by numerous factors. These factors include, but are not limited to, market fluctuations of prices, proximity, capacity and availability of processing facilities, transportation vehicles and pipelines, equipment availability and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, domestic supply requirements,

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importing and exporting of oil and natural gas, environmental protection and climate change). The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital.

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

We are subject to drilling and other operational environmental hazards.

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

    fires, blowouts, spills, cratering and explosions;

    mechanical and equipment problems, including unforeseen engineering complications;

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

    gas flaring operations;

    marine hazards with respect to offshore operations;

    formations with abnormal pressures;

    pollution, other environmental risks, and geological problems; and

    weather conditions and natural disasters.

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

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

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

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

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

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

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

        All of our proved reserves and our discovered fields are located offshore Ghana. The WCTP Petroleum Agreement and the DT Petroleum Agreement cover the two blocks that form the basis of our exploration, development and production operations in Ghana. Pursuant to these petroleum agreements, most significant decisions, including our plans for development and annual work programs, must be approved by GNPC and/or Ghana's Ministry of Energy. We previously had disagreements with Ghana and GNPC regarding certain of our rights and responsibilities under these petroleum agreements and the Petroleum Law of 1984 (PNDCL 84) (the "Ghanaian Petroleum Law"). These included disagreements over sharing information with prospective purchasers of our interests, pledging our interests to finance our development activities, potential liabilities arising from discharges of small quantities of drilling fluids into Ghanaian territorial waters and the failure to approve the proposed sale of our Ghanaian assets. In addition, we were requested to provide information to Ghana's Ministry of Justice in connection with its investigation of the EO Group, however, we are not a subject of this investigation. These past disagreements have been resolved and did not and are not expected to materially affect our operations, exploration or development activities.

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

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

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

    severe weather or natural disasters or other acts of God;

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

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

    military conflicts.

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

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

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

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

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

    disrupt our operations;

    require us to incur greater costs for security;

    restrict the movement of funds or limit repatriation of profits;

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

    limit access to markets for periods of time.

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

        Our operations may also be adversely affected by laws and policies of the jurisdictions, including Ghana, Cameroon, Morocco, the United States, the United Kingdom, Bermuda and the Cayman

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Islands and other jurisdictions in which we do business, that affect foreign trade and taxation. Changes in any of these laws or policies or the implementation thereof, could materially and adversely affect our financial position, results of operations and cash flows.

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

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

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

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

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

        In early 2010, Ghana's western neighbor, the Republic of Côte d'Ivoire, petitioned the United Nations to demarcate the Ivorian territorial maritime boundary with Ghana. In response to the petition, Ghana established a Boundary Commission to undertake negotiations in order to determine Ghana's land and maritime boundaries. Meetings between the Ghanaian Boundary Commission and Ivorian delegates concerning the boundary demarcation occurred in April 2010, although the results of the meeting were not announced and the issue remains unresolved at present. The Ghanaian-Ivorian maritime boundary forms the western boundary of the DT Block offshore Ghana. While we believe the prospects we have identified in the DT Block to date do not fall within the area implicated by the demarcation, some uncertainty remains with regard to the outcome of the boundary demarcation between Ghana and Côte d'Ivoire and we do not know if the maritime boundary will change, therefore affecting our rights to explore and develop our discoveries or prospects within such areas.

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

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

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

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

    licenses for drilling operations;

    tax increases, including retroactive claims;

    unitization of oil accumulations;

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

    environmental requirements and obligations, including remediation or investigation activities.

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

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

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

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increased certain of the risks faced by those drilling for oil in deepwater regions, including, without limitation, the following:

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

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

    higher operating costs;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

        In January 2009, the U.S. Department of Justice ("DOJ") was notified of an alleged possible violation of the FCPA by Kosmos and EO Group and its principals in connection with securing the WCTP Petroleum Agreement. We and our outside FCPA counsel undertook a thorough investigation and found no basis for such allegations and cooperated fully with the DOJ in its investigation. On May 12, 2010, the DOJ notified us through a letter of declination and on June 2, 2010 the DOJ notified EO Group and its principals that they presently do not intend to take any enforcement action and have closed their inquiry into this matter. In addition, we were required to provide information to Ghana's Ministry of Justice in connection with its investigation of the EO Group, however, we are not a subject of this investigation.

        MODEC, the contractor for the FPSO for the Jubilee Field Phase 1 development, is being investigated for certain potential FCPA violations by the Jubilee Unit partners and the syndicate of international banks who had committed to refinance the construction costs of the FPSO (a portion of

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such costs were originally loaned by the Jubilee Unit partners, including Kosmos). See "Risk Factors—The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results." While we had no prior knowledge of the events under investigation, should the DOJ become involved, there can be no assurance that the Jubilee Unit partners, including us, would not be subject to enforcement actions which may have a material adverse affect on our business.

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

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

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

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

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

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

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

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

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

Increased costs of capital could adversely affect our business.

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

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

        Our commercial debt facilities include certain covenants that, among other things, restrict:

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

    our incurrence of additional indebtedness;

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

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

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

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

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

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

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

        As of December 31, 2010 we had $1.05 billion of indebtedness outstanding under our $1.25 billion commercial debt facilities. In the future, we may incur significant indebtedness in order to make future investments or acquisitions or to explore, appraise or develop our oil and natural gas assets.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    recoverable reserves;

    future oil and natural gas prices and their appropriate differentials;

    development and operating costs; and

    potential environmental and other liabilities.

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

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

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

    difficulty associated with coordinating geographically separate organizations; and

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

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

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

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

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

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

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

    institute a more comprehensive compliance function;

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

    comply with rules promulgated by the NYSE;

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

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

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

    establish an investor relations function.

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

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

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

        As a result, our directors and Investors and their affiliates may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they or their affiliates have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to our directors and Investors and their affiliates could adversely impact our business or future prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. See "Description of Share Capital—Corporate Opportunities."

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

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

We may become subject to taxes in Bermuda after March 28, 2016, which may have a material adverse effect on our results of operations and your investment.

        The Bermuda Minister of Finance, under the Exempted Undertakings Tax Protection Act 1966 of Bermuda, as amended, has given us an assurance that if any legislation is enacted in Bermuda that would impose tax computed on profits or income, or computed on any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance tax, then the imposition of any such tax will not be applicable to us or any of our operations, shares, debentures or other obligations until March 28, 2016, except insofar as such tax applies to persons ordinarily resident in Bermuda or to any taxes payable by us in respect of real property owned or leased by us in Bermuda. See "Certain Tax Considerations—Bermuda Tax Considerations." Given the limited duration of the Bermuda Minister of Finance's assurance, we cannot assure you that we will not be subject to any Bermuda tax after March 28, 2016.

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

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

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

        We use derivative instruments to manage our commodity price risk. The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (the "CFTC") and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the

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

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

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

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

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

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Risks Relating to This Offering

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

        Prior to this offering, our common shares were not traded on any market. An active and liquid trading market for our common shares may not develop or be maintained after this offering. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors' purchase and sale orders. The market price of our common shares could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common shares, you could lose a substantial part or all of your investment in our common shares. The initial public offering price will be negotiated between us and representatives of the underwriters and may not be indicative of the market price of our common shares after this offering. Consequently, you may not be able to sell our common shares at prices equal to or greater than the price paid by you in the offering.

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

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

    the price of oil and natural gas;

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

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

    the recruitment or departure of key personnel;

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

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

    analysts' reports or recommendations;

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

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

    the issuance of any additional securities of ours;

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

    general economic, political and market conditions.

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

        All of the shares being sold in this offering will be freely tradable without restrictions or further registration under the federal securities laws, unless purchased by our "affiliates" as that term is defined in Rule 144 under the Securities Act. The remaining common shares issued and outstanding upon the closing of this offering are restricted securities as defined in Rule 144 under the Securities

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Act. Restricted securities may be sold in the U.S. public market only if registered or if they qualify for an exemption from registration, including by reason of Rules 144 or 701 under the Securities Act. All of our restricted shares will be eligible for sale in the public market beginning in 2011, subject in certain circumstances to the volume, manner of sale and other limitations under Rule 144, and also the lock-up agreements described under "Underwriting" in this prospectus. Additionally, we intend to register all our common shares that we may issue under our employee benefit plans. Once we register these shares, they can be freely sold in the public market upon issuance, unless pursuant to their terms these share awards have transfer restrictions attached to them. Sales of a substantial number of our common shares, or the perception in the market that the holders of a large number of shares intend to sell common shares, could reduce the market price of our common shares.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

        Our shareholders could have more difficulty protecting their interests than would shareholders of a corporation incorporated in a jurisdiction of the United States. As a Bermuda company, we are

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governed by the Companies Act 1981 of Bermuda (the "Bermuda Companies Act"). The Bermuda Companies Act differs in some material respects from laws generally applicable to U.S. corporations and shareholders, including the provisions relating to interested directors, mergers and acquisitions, takeovers, shareholder lawsuits and indemnification of directors. Set forth below is a summary of these provisions, as well as modifications adopted pursuant to our bye-laws, which differ in certain respects from provisions of Delaware corporate law. Because the following statements are summaries, they do not discuss all aspects of Bermuda law that may be relevant to us and our shareholders. See "Description of Share Capital."

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

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

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

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

        Our bye-laws contain a provision by virtue of which we and our shareholders waive any claim or right of action that they have, both individually and on our behalf, against any director or officer in relation to any action or failure to take action by such director or officer, except in respect of any fraud or dishonesty of such director or officer. Class actions and derivative actions generally are available to shareholders under Delaware law for, among other things, breach of fiduciary duty, corporate waste and actions not taken in accordance with applicable law. In such actions, the court has discretion to permit the winning party to recover attorneys' fees incurred in connection with such action.

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

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Forward-Looking Statements

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

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

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

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

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

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

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

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

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

    the volatility of oil and natural gas prices;

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

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

    other competitive pressures;

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

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

    cost of compliance with laws and regulations;

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

    environmental liabilities;

    geological, technical, drilling and processing problems;

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    military operations, terrorist acts, wars or embargoes;

    the cost and availability of adequate insurance coverage;

    our vulnerability to severe weather events; and

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

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

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DIVIDEND POLICY

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

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USE OF PROCEEDS

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

        We intend to use the net proceeds from this offering, available cash and borrowings under our commercial debt facilities to fund our capital expenditures, and in particular our exploration and appraisal drilling program and development activities through early 2013, our related operating expenses, and for general corporate purposes. As a result, management will retain broad discretion over the allocation of the net proceeds from this offering. Pending use of the net proceeds of this offering, we intend to invest the net proceeds in interest bearing, investment-grade securities.

        We estimate we will incur approximately $400.0 million of capital expenditures for the year ending December 31, 2011. This capital expenditure budget consists of:

    $135.0 million for development in Ghana;

    $175.0 million for exploration and appraisal in Ghana;

    $25.0 million for exploration and appraisal in Cameroon;

    $25.0 million for new ventures to expand our license portfolio (including geological and geophysical expenses); and

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

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

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

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CORPORATE REORGANIZATION

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

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

        Upon the completion of the reorganization, Kosmos Energy Holdings' current operating agreement will be amended and restated to remove the various classes of units and terminate the rights and obligations of Kosmos Energy Holdings' current unitholders, including the rights of our Investors and management to appoint directors to the board of Kosmos Energy Holdings and the rights of Kosmos Energy Holdings to make any additional capital calls.

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

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CAPITALIZATION

        The following table sets forth our capitalization as of September 30, 2010 on an actual basis, pro forma to give effect to our corporate reorganization and pro forma as adjusted for the effect of this offering.

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

 
  As of September 30, 2010  
 
  Actual   Pro Forma to
Give Effect to our
Corporate
Reorganization(1)
  Pro Forma as
Adjusted for the
Effect of this
Offering(1)(2)
 
 
  (Unaudited)
   
   
 
 
  (In thousands, except per share data)
 

Cash and cash equivalents

  $ 202,846   $        $       

Restricted cash

    89,000                    
               
 

Total Cash

  $ 291,846   $        $       
               

Short-term debt, including current portion of long-term debt

  $   $        $       

Long-term debt

    950,000                    
               
 

Total Debt

    950,000                    

Series A Convertible Preferred Units; 30,000,000 units outstanding, actual

    300,000          

Series B Convertible Preferred Units; 20,000,000 units outstanding, actual

    500,000          

Series C Convertible Preferred Units; 884,956 units outstanding, actual

    13,244          
               
 

Total Convertible Preferred Units

    813,244          

Common Units; 18,689,162 units outstanding, actual

    516          

Common shares, $0.01 par value per share;            shares issued and outstanding, pro forma to give effect to our corporate reorganization(3);            shares issued and outstanding, pro forma as adjusted for the effect of this offering(4)

                       

Additional paid-in capital

    20,780                    

Deficit accumulated during development stage/Retained deficit

    (417,718 )                  

Accumulated other comprehensive income (loss)

    (455 )                  
               
 

Total Unit Holdings capital/Shareholders' equity

    (396,877 )                  
               
 

Total Capitalization

  $ 1,366,367   $        $       
               

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

(2)
Also gives effect to the issuance of                    common shares contemplated by this offering at an assumed initial public offering price of $            per common share (the midpoint of the estimated

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    public offering price range set forth on the cover page of this prospectus) less underwriting discounts and commissions and expenses payable by us. A $1.00 decrease or increase in the assumed initial public offering price would result in approximately a $            million decrease or increase in each of the following pro forma as adjusted (i) cash and cash equivalents, (ii) additional paid-in capital, (iii) total unit holdings' capital/shareholders' equity and (iv) total capitalization, assuming the total number of common shares offered by us remains the same and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us.

(3)
Pursuant to the operating agreement, all of the preferred units and common units of Kosmos Energy Holdings, including (i) units issued to management and employees in connection with our corporate reorganization, (ii) all unvested units and (iii) any units reserved for future issuance, will be converted into common shares based on the pre-offering equity value of such interests. This results in the Series A, Series B, and Series C Preferred Units and the Common Units being converted into                 ;                ;                 and            common shares, respectively, or            common shares in the aggregate.                common shares issued and outstanding, pro forma to give effect to our corporate reorganization, excludes (i)             unvested shares granted to management and employees in connection with our corporate reorganization and (ii)             common shares which were reserved for issuance pursuant to our long-term incentive plan. Any increase or decrease in the initial public offering price from the assumed offering price of $                per common share will change the relative interest percentages of common shares owned by the different classes of unit holders but will not change the aggregate number of shares owned by all of the unit holders.

(4)
common shares issued and outstanding, pro forma as adjusted for the effect of this offering, includes            common shares issued pursuant to this offering and excludes (i)             unvested common shares granted to management and employees in connection with our corporate reorganization and (ii)             common shares which were reserved for issuance pursuant to our long-term incentive plan.

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DILUTION

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

        Our pro forma net tangible book value at September 30, 2010 after giving effect to our corporate reorganization was $            or $            per common share, based on                     common shares issued and outstanding prior to the closing of this offering. After giving effect to our corporate reorganization and the sale of            common shares by us in this offering at an assumed initial public offering price of $            per common share (the midpoint of the estimated public offering price range set forth on the cover page of this prospectus), less the estimated underwriting discounts and commissions and the estimated offering expenses payable by us, our pro forma as adjusted net tangible book value at September 30, 2010, would be $                , or $            per share. This represents an immediate increase in the pro forma net tangible book value of $                per share to existing shareholders and an immediate dilution of $                per share to new investors purchasing common shares in this offering. The following table illustrates this per share dilution:

Assumed initial public offering price

               $           

Pro forma net tangible book value per share as of September 30, 2010 after giving effect to our corporate reorganization

  $                        

Increase per share attributable to this offering

  $                        
             

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

               $           
             

Dilution per share to new investors in this offering

               $           
             

        The following table shows, at September 30, 2010, on a pro forma basis as described above, the difference between the number of common shares purchased from us, the total consideration paid to us and the average price paid per share by existing shareholders and by new investors purchasing common shares in this offering:

 
  Common Shares
Purchased
   
   
   
 
 
  Total Consideration    
 
 
  Average Price
Per Common Share
 
 
  Number   Percentage   Amount   Percentage  

Existing shareholders

                          % $          (1)            % $           

New investors

                          % $                       % $           

Total

                 100.00 % $              100.00 % $           

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

        Assuming the underwriters' over-allotment option is exercised in full, sales by us in this offering will reduce the percentage of common shares held by existing shareholders to        % and will increase the number of common shares held by new investors to                , or        %. This information is based on common shares issued and outstanding as of September 30, 2010, after giving effect to our corporate reorganization. No material change has occurred to our equity capitalization since September 30, 2010, after giving effect to our corporate reorganization and this offering.

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

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL INFORMATION

        The selected historical financial information set forth below should be read in conjunction with the sections entitled "Corporate Reorganization", "Management's Discussion and Analysis of Financial Condition and Results of Operations" and with Kosmos Energy Holdings' financial statements and the notes to those financial statements included elsewhere in this prospectus. Kosmos Energy Holdings has been a development stage company. The consolidated statements of operations and cash flows for the years ended December 31, 2005, 2006, 2007, 2008 and 2009 and the consolidated balance sheets as of December 31, 2005, 2006, 2007, 2008 and 2009 were derived from Kosmos Energy Holdings' audited consolidated financial statements. We derived the consolidated statements of operations and cash flows for the nine months ended September 30, 2009 and 2010, for the period April 23, 2003 (Inception) through September 30, 2010, and the consolidated balance sheets as of September 30, 2009 and 2010, from Kosmos Energy Holdings' unaudited consolidated financial information appearing elsewhere in this prospectus, which, in management's opinion, includes all adjustments necessary for the fair presentation of Kosmos Energy Holdings' financial condition as of such date and Kosmos Energy Holdings' results of operations for such periods. Results of operations for the nine months ended September 30, 2010, are not necessarily indicative of the results of operations that may be achieved for the entire year. The unaudited pro forma information is derived from Kosmos Energy Holdings' audited and unaudited consolidated financial statements appearing elsewhere in this document and is based on assumptions and includes adjustments as explained in the notes to the table.

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

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Consolidated Statements of Operations Information:

 
   
   
   
   
   
   
   
  Period
April 23, 2003
(Inception)
through
September 30
2010
 
 
  Year Ended December 31   Nine Months Ended
September 30
 
 
  2005   2006   2007   2008   2009   2009   2010  
 
   
   
   
   
   
  (Unaudited)
  (Unaudited)
  (Unaudited)
 
 
  (In thousands)
 

Revenues and other income:

                                                 
 

Oil and gas revenue

  $   $   $   $   $   $   $   $  
 

Interest income

    252     445     1,568     1,637     985     595     2,548     7,459  
 

Other income

    1,822     3,100     2     5,956     9,210     7,578     3,793     25,383  
                                   
   

Total revenues and other income

    2,074     3,545     1,570     7,593     10,195     8,173     6,341     32,842  

Costs and expenses:

                                                 
 

Exploration expenses, including dry holes

    6,718     9,083     39,950     15,373     22,127     17,191     52,764     146,088  
 

General and administrative

    7,801     9,588     18,556     40,015     55,619     43,425     50,804     188,002  
 

Depreciation and amortization

    340     401     477     719     1,911     1,369     1,655     5,737  
 

Amortization—debt issue costs

                    2,492         20,555     23,047  
 

Interest expense

            8     1     6,774         45,645     52,452  
 

Derivatives, net

                            15,310     15,310  
 

Equity in losses of joint venture

    5,157     9,194     2,632                     16,983  
 

Other expenses, net

    7     7     17     21     46     39     20     875  
                                   
   

Total costs and expenses

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

Loss before income taxes

    (17,949 )   (24,728 )   (60,070 )   (48,536 )   (78,774 )   (53,851 )   (180,412 )   (415,652 )

Income tax expense (benefit)

            718     269     973     30     (174 )   1,786  
                                   

Net loss

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

Pro forma net loss (unaudited)(1):

                                                 

Pro forma basic and diluted net loss per common share

                          $           $          
                                               

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

                          $           $          
                                               

(1)
Pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the closing of this offering, all of the interests in Kosmos Energy Holdings will be exchanged for newly issued common shares of Kosmos Energy Ltd. based on these interests' relative rights as set forth in Kosmos Energy Holdings' current operating agreement. The weighted average common shares outstanding have been calculated as if the ownership structure resulting from the corporate reorganization was in place since inception. Pro forma information does not give effect to this offering.

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Consolidated Balance Sheets Information:

 
  As of December 31   As of September 30   Pro Forma
as Adjusted as of
September 30
2010(1)
 
 
  2005   2006   2007   2008   2009   2009   2010  
 
   
   
   
   
   
  (Unaudited)
  (Unaudited)
  (Unaudited)
 
 
  (In thousands)
 

Cash and cash equivalents

  $ 14,349   $ 9,837   $ 39,263   $ 147,794   $ 139,505   $ 60,818   $ 202,846   $           

Total current assets

    16,346     10,334     65,960     205,708     256,728     176,536     491,638               

Total property and equipment

    3,788     1,567     18,022     208,146     604,007     492,202     884,628               

Total other assets

    727     3,704     3,393     1,611     161,322     22,650     175,622               

Total assets

    20,861     15,605     87,375     415,465     1,022,057     691,388     1,551,888               

Total current liabilities

    430     1,436     28,574     68,698     139,647     143,829     168,310               

Total long-term liabilities

    1,312             444     287,022     1,902     967,211               

Total convertible preferred units

    41,937     61,952     167,000     499,656     813,244     750,065     813,244               

Total unit holdings

    (22,818 )   (47,783 )   (108,199 )   (153,333 )   (217,856 )   (204,408 )   (396,877 )             

Total liabilities, convertible preferred units and unit holdings

    20,861     15,605     87,375     415,465     1,022,057     691,388     1,551,888               

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

Consolidated Statements of Cash Flows Information:

 
   
   
   
   
   
   
   
  Period
April 23, 2003
(Inception)
through
September 30
2010
 
 
  Year Ended December 31   Nine Months Ended September 30  
 
  2005   2006   2007   2008   2009   2009   2010  
 
   
   
   
   
   
  (Unaudited)
  (Unaudited)
  (Unaudited)
 
 
  (In thousands)
 

Net cash provided by (used in):

                                                 

Operating activities

  $ (13,978 ) $ (9,617 ) $ (17,386 ) $ (65,671 ) $ (27,591 ) $ (6,506 ) $ (133,180 ) $ (272,389 )

Investing activities

    (3,980 )   (14,663 )   (58,161 )   (156,882 )   (500,393 )   (309,801 )   (451,164 )   (1,190,215 )

Financing activities

    30,895     19,768     104,973     331,084     519,695     229,331     647,685     1,665,450  

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

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

Overview

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

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

Exploration and Other Agreements

        Each of our five exploration licenses is governed by related petroleum or license agreements. In July 2004, Kosmos signed the WCTP Petroleum Agreement. In July 2006, Kosmos signed the DT Petroleum Agreement. In 2006, Anadarko farmed in to the WCTP Block and DT Block while Tullow and Sabre farmed in to the WCTP Block. Following the discovery of the Jubilee Field, on July 13, 2009 Kosmos and the other WCTP and DT block partners signed the UUOA, which governs the interests in and development of the Jubilee Field and created the Jubilee Unit from portions of the WCTP Block and the DT Block. In November 2005, Kosmos farmed in to the Kombe-N'sepe License Agreements. In November 2006, Kosmos signed the Ndian River Production Sharing Contract. In May 2006, Kosmos signed the Boujdour Offshore Petroleum Agreement. Kosmos has also entered numerous agreements ancillary to the operation of the above license agreements or otherwise necessary to conduct Kosmos' oil and natural gas exploration, development and production activities.

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Factors Affecting Comparability of Future Results

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

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

        Oil and Gas Revenue.    We have recently commenced oil and natural gas production and we expect to generate revenue from such production in early 2011. No oil and gas revenue is reflected in our historical financial statements.

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

        General and Administrative.    We expect general and administrative expenses to increase as a result of commencing production from the Jubilee Field on November 28, 2010 and as a result of becoming a publicly traded company. Public company costs include expenses associated with our annual and quarterly reporting, investor relations, registrar and transfer agent fees, incremental insurance costs, and accounting and legal services. In addition, we expect to incur certain non-recurring expenses related to the offering in the quarter in which the offering occurs, including a $15.0 million payment that is payable upon successful completion of an initial public offering. These differences in general and administrative expenses are not reflected in our historical financial statements.

        Depletion, Depreciation and Amortization.    We have recently commenced oil and natural gas production and we will amortize the costs of successful exploration, appraisal, drilling and field development using the unit-of-production method based on estimated proved developed oil and natural gas reserves. No depletion of oil and natural gas properties is reflected in our historical financial statements.

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

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

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        We entered into the Boujdour Offshore Petroleum Agreement in May 2006. This agreement provides for a tax holiday, at a 0% tax rate, for a period of 10 years beginning on the date of first production from the Boujdour Offshore Block. We currently have recorded deferred tax assets of $6.6 million, recorded at the Moroccan statutory rate of 30%, with an offsetting valuation allowance of $6.6 million. Once we enter into the tax holiday period (when production begins) we will re-evaluate our deferred tax position and at such time may reduce the statutory rate applied to the deferred tax assets in Morocco to the extent those deferred tax assets are realized within the tax holiday period.

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

        We expect to earn income from:

    oil and natural gas sales to international markets; and

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

        We expect that our expenses will include:

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

    maintenance and repair of property and equipment;

    depreciation of fixed assets;

    depletion of oilfields and associated abandonment costs;

    exploration and appraisal costs;

    costs of acquiring seismic or other geological and geophysical data;

    selling expenses and general and administrative expenses; and

    financing expenses, interest expense and foreign exchange losses.

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

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

    changes in the market prices of oil and natural gas;

    changes in fair value of derivative financial instruments;

    our success in obtaining new licenses and other acquisitions;

    the successful implementation of our drilling and development plans;

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

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

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Results of Operations

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

    Nine Months Ended September 30, 2010 vs. 2009

 
  Nine Months Ended
September 30
   
 
 
  Increase
(Decrease)
 
 
  2009   2010  
 
  (Unaudited)
   
 
 
  (In thousands)
 

Revenues and other income:

                   
 

Oil and gas revenue

  $   $   $  
 

Interest income

    595     2,548     1,953  
 

Other income

    7,578     3,793     (3,785 )
               
   

Total revenues and other income

    8,173     6,341     (1,832 )

Costs and expenses:

                   
 

Exploration expenses, including dry holes

    17,191     52,764     35,573  
 

General and administrative

    43,425     50,804     7,379  
 

Depreciation and amortization

    1,369     1,655     286  
 

Amortization—debt issue costs

        20,555     20,555  
 

Interest expense

        45,645     45,645  
 

Derivatives, net

        15,310     15,310  
 

Other expenses, net

    39     20     (19 )
               
   

Total costs and expenses

    62,024     186,753     124,729  
               

Loss before income taxes

    (53,851 )   (180,412 )   (126,561 )

Income tax expense (benefit)

    30     (174 )   (204 )
               

Net loss

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

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

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

        Other income.    Other income decreased by $3.8 million during the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009, primarily due to a decrease in technical services fees and overhead charges billed to the Unit Operator as a result of the Jubilee Field Phase 1 development nearing completion.

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

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

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

        Amortization—debt issue costs.    Amortization—debt issue costs increased by $20.6 million during the nine months ended September 30, 2010, as compared to the nine months ended September 30, 2009, due to the amortization of the fees which were capitalized in connection with the initial draw on the commercial debt facilities in November 2009.

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

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

    Year Ended December 31, 2009 vs. 2008

 
  Years Ended
December 31
   
 
 
  Increase
(Decrease)
 
 
  2008   2009  
 
  (In thousands)
 

Revenues and other income:

                   
 

Oil and gas revenue

  $   $   $  
 

Interest income

    1,637     985     (652 )
 

Other income

    5,956     9,210     3,254  
               
   

Total revenues and other income

    7,593     10,195     2,602  

Costs and expenses:

                   
 

Exploration expenses, including dry holes

    15,373     22,127     6,754  
 

General and administrative

    40,015     55,619     15,604  
 

Depreciation and amortization

    719     1,911     1,192  
 

Amortization—debt issue costs

        2,492     2,492  
 

Interest expense

    1     6,774     6,773  
 

Other expenses, net

    21     46     25  
   

Total costs and expenses

    56,129     88,969     32,840  
               

Loss before income taxes

    (48,536 )   (78,774 )   (30,238 )

Income tax expense

    269     973     704  
               

Net loss

  $ (48,805 ) $ (79,747 ) $ (30,942 )
               

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

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

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

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

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

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

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

    Year Ended December 31, 2008 vs. 2007

 
  Years Ended
December 31
   
 
 
  Increase
(Decrease)
 
 
  2007   2008  
 
  (In thousands)
 

Revenues and other income:

                   
 

Oil and gas revenue

  $   $   $  
 

Interest income

    1,568     1,637     69  
 

Other income

    2     5,956     5,954  
               
   

Total revenues and other income

    1,570     7,593     6,023  

Costs and expenses:

                   
 

Exploration expenses, including dry holes

    39,950     15,373     (24,577 )
 

General and administrative

    18,556     40,015     21,459  
 

Depreciation and amortization

    477     719     242  
 

Interest expense

    8     1     (7 )
 

Equity in losses of joint venture

    2,632         (2,632 )
 

Other expenses, net

    17     21     4  
               
   

Total costs and expenses

    61,640     56,129     (5,511 )
               

Loss before income taxes

    (60,070 )   (48,536 )   11,534  

Income tax expense

    718     269     (449 )
               

Net loss

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

        Oil and gas revenue.    We have recently commenced oil and natural gas production. We did not realize any oil and gas revenue during the years ended December 31, 2007 and 2008.

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

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

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

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

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

Liquidity and Capital Resources

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

    Significant Sources of Capital

        To date all of our equity has been provided by funds affiliated with either Warburg Pincus or The Blackstone Group, as well as the management group, certain accredited employee investors and directors. We have received three rounds of equity funding commitments aggregating $1.1 billion.

        During 2009, we secured commercial debt facilities from a number of financial institutions, including the IFC, for up to $900 million to be used in funding our share of Jubilee Field Phase 1 development. The facilities were amended in August 2010 to increase the total commercial debt facilities amount to $1.25 billion and to add additional lenders.

        The revised $1.25 billion of commercial debt facilities are divided among a senior facility of $950.0 million, a junior facility of $200.0 million and additional facilities of $100.0 million ($50.0 million senior facility and $50.0 million junior facility) from the IFC. The senior and junior facilities of $950.0 million and $200.0 million include a syndicate of institutions led by Standard Chartered Bank, the Global Coordinator for the facilities. Standard Chartered Bank is also the Co-Technical and Modeling Bank and Senior Facility Agent, BNP Paribas SA is the Security Trustee, Junior Facility Agent, and has the role of Hedging Coordinator Bank, and Société Générale is the Lead Technical and Modeling Bank. The senior facilities have a final maturity date of December 15, 2015, while the junior facilities have a final maturity date of June 15, 2016.

        The interest is the aggregate of the applicable margin (5% to 6% on the senior facilities and 9% to 9.5% on the junior facilities); LIBOR; and mandatory cost (if any, as defined in the relevant documentation). Interest on each loan is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). Kosmos pays commitment fees on the undrawn and uncancelled portion of the

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

        Certain facilities contain certain financial covenants, which include:

    Before project completion, maintenance of the funding sufficiency ratio, not less than 1:1x; and;

    After project completion, maintenance of:

              (i)  the debt service coverage ratio, not less than 1.2x;

             (ii)  the field life cover ratio, not less than 1.35x; and

            (iii)  the loan life cover ratio, not less than 1.15x

in each case, as calculated on the basis of all available information. Kosmos has the right to cancel all the undrawn commitments under the facilities if such cancellation is simultaneous with the full repayment of all outstanding loans made under the facilities. The amount of funds available to be borrowed under the senior facilities, also known as the borrowing base amount, is determined on June 15 and December 15 of each year as part of a forecast that is prepared and agreed by Kosmos and the Technical and Modeling Banks. The formula to calculate the borrowing base amount is based, in part, on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages. As of September 30, 2010, borrowings against the commercial debt facilities totaled $950.0 million, of which $900.0 million is senior debt and $50.0 million is junior debt. As of September 30, 2010, the availability under our commercial debt facilities was $200.0 million, with $300.0 million of committed undrawn capacity provided for in such facilities (the difference being the result of borrowing base constraints).

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

    Capital Expenditures and Investments

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

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

    drill two exploration wells in Cameroon;

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

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

    develop our discoveries which we determine to be commercially viable.

        Oil production from the Jubilee Field commenced on November 28, 2010, and we anticipate receiving our first oil revenues in early 2011. We expect gross oil production from the Jubilee Field to reach its design capacity of 120,000 bopd in mid 2011.

        In budgeting for our future activities, we have relied on a number of assumptions, including with regard to our discovery success rate, the number of wells we plan to drill, our working interests in our prospects, the costs involved in developing or participating in the development of a prospect, the timing of third party projects and the availability of both suitable equipment and qualified personnel. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if one or more of

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our assumptions prove to be incorrect or if we choose to expand our hydrocarbon asset acquisition, exploration, appraisal or development efforts more rapidly than we presently anticipate, and we may decide to raise additional funds even before we need them if the conditions for raising capital are favorable. We may seek to sell equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could result in dilution to our shareholders. The incurrence of additional indebtedness could result in increased fixed obligations and could also result in additional covenants that could restrict our operations.

        Furthermore, if MODEC, the contractor for the FPSO we are using to produce hydrocarbons from the Jubilee Field, is unable to secure financing for the cost of such FPSO in order to repay amounts originally loaned by us and certain other Jubilee Unit partners under an Advance Payments Agreement for the financing of the construction of such FPSO, the Jubilee Unit partners may need to directly purchase the FPSO or find an alternative funding source or buyer. MODEC is required to repay amounts advanced on the earlier of September 15, 2011 or the date of the first drawdown under MODEC's long-term financing. The Advance Payments Agreement grants to the Jubilee Unit partners the option to purchase the FPSO from MODEC on or before that same date, at a discount to the market value of the FPSO. Although we have a letter agreement with certain of our partners in which they agree to purchase the vessel and lease it back to the Jubilee Unit partners, should we elect to participate in the purchase or should they fail to perform their obligations under the letter agreement, our share of the remaining balance of cost to make such purchase is up to approximately $120.0 million. See "Risk Factors—The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results."

        We estimate we will incur approximately $400.0 million of capital expenditures for the year ending December 31, 2011. This capital expenditure budget consists of:

    $135.0 million for development in Ghana;

    $175.0 million for exploration and appraisal in Ghana;

    $25.0 million for exploration and appraisal in Cameroon;

    $25.0 million for new ventures to expand our license portfolio (including geological and geophysical expenses); and

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

        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.

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Cash Flows

 
   
   
   
   
   
  Period
April 23, 2003
(Inception)
through
September 30
2010
 
 
  Year Ended December 31   Nine Months
Ended September 30
 
 
  2007   2008   2009   2009   2010  
 
   
   
   
  (Unaudited)
  (Unaudited)
  (Unaudited)
 
 
  (In thousands)
 

Net cash provided by (used in):

                                     
 

Operating activities

  $ (17,386 ) $ (65,671 ) $ (27,591 ) $ (6,506 ) $ (133,180 ) $ (272,389 )
 

Investing activities

    (58,161 )   (156,882 )   (500,393 )   (309,801 )   (451,164 )   (1,190,215 )
 

Financing activities

    104,973     331,084     519,695     229,331     647,685     1,665,450  

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

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

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

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

        Financing activities.    Net cash provided by financing activities in 2009 was $519.7 million compared with net cash provided by financing activities of $331.1 million and $105.0 million in 2008 and 2007, respectively. The increase in cash provided in 2009 when compared to 2008 is due to borrowings of $285.0 million on the commercial debt facilities offset by a net decrease of $7.3 million of proceeds from issuances of Series B and Series C Convertible Preferred Units and an increase of $87.9 million in cash used for debt issue costs. The increase in 2008 cash flows when compared to 2007 is primarily due to $227.7 million of proceeds from issuances of Series A and Series B Convertible Preferred Units.

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

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Contractual Obligations

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

 
  Payments Due By Year  
 
  Total   2010(1)   2011   2012   2013   2014   Thereafter  
 
  (In thousands)
 

Drilling rig contract(2)

  $ 280,449   $ 23,462   $ 123,856   $ 133,131   $   $   $  

Operating leases

    6,863     402     1,615     1,636     1,660     1,168     382  

Commercial debt facilities(3)

    950,000         175,000     250,000     200,000     175,000     150,000  

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

(2)
Does not include any well commitments we may have under our oil and natural gas licenses.

(3)
The amounts included in the table above represent principal maturities only. Subsequent to September 30, 2010, the Company borrowed an additional $95 million under the senior and junior facilities. As of the date the financial statements are available to be issued, borrowings against the commercial debt facilities totaled $1.05 billion and the scheduled principal maturities during the next five years and thereafter are (in thousands): 2010—zero; 2011—$245,000; 2012—$250,000; 2013—$200,000; 2014—$175,000; and thereafter—$175,000.

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

 
  October 1
Through
December 31
2010
  Year Ending December 31   Liability Fair
Value at
September 30
2010
 
 
  2011   2012   2013   2014   Thereafter  
 
  (In thousands, except percentages)
 

Variable Rate Debt:

                                           
 

Credit facilities maturities

  $   $ 175,000   $ 250,000   $ 200,000   $ 175,000   $ 150,000   $ 950,000  
 

Weighted average interest rate

    7.25 %   7.08 %   7.33 %   6.92 %   8.30 %   10.69 %      

Interest Rate Swaps

                                           
 

Notional debt amount(1)

  $ 161,250   $ 161,250   $ 138,073   $ 91,683   $ 47,033   $ 13,333   $ 5,002  
   

Fixed rate payable

    2.22 %   2.22 %   2.22 %   2.22 %   2.22 %   2.22 %      
   

Variable rate receivable(2)

    0.75 %   0.60 %   1.06 %   1.73 %   2.50 %   3.38 %      
 

Notional debt amount(1)

  $ 161,250   $ 161,250   $ 138,073   $ 91,683   $ 47,033   $ 13,333   $ 5,424  
   

Fixed rate payable

    2.31 %   2.31 %   2.31 %   2.31 %   2.31 %   2.31 %      
   

Variable rate receivable(2)

    0.75 %   0.60 %   1.06 %   1.73 %   2.50 %   3.38 %      
 

Notional debt amount(1)

  $ 77,500   $ 77,500   $ 63,625   $ 19,057   $ 1,868   $   $ 349  
   

Fixed rate payable

    0.98 %   0.98 %   0.98 %   0.98 %   0.98 %            
   

Variable rate receivable(2)

    0.25 %   0.60 %   1.06 %   1.73 %   2.30 %            

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

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

Off-Balance Sheet Arrangements

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

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Critical Accounting Policies

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

        Revenue Recognition.    We will use the sales method of accounting for oil and gas revenues. Under this method, we will recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. As of September 30, 2010, no revenues have been recognized in our financial statements.

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

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

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

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

        Derivative Instruments and Hedging Activities.    We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative

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

        Estimates of Proved Oil and Natural Gas Reserves.    Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As of June 30, 2010, our net proved undeveloped reserves totaled 59 Mmboe. As additional proved reserves are found in the future, estimated reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the SEC and the FASB. The accuracy of these reserve estimates is a function of:

    the quality and quantity of available data and the engineering and geological interpretation of that data;

    estimates regarding the amount and timing of future operating cost, production taxes, development cost and workover cost, all of which may in fact vary considerably from actual results;

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

    the judgments of the persons preparing the estimates.

        Asset Retirement Obligations.    We have recently commenced oil and natural gas production and we expect to have significant obligations to remove our equipment and restore land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and natural gas facilities. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Pursuant to the FASB ASC 410—Assets Retirement Obligations, we will be required to record a separate liability in the fourth quarter of 2010 for the discounted present value of our asset retirement obligations, with an offsetting increase to the related oil and natural gas properties on our balance sheet.

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

        Impairment of Long-Lived Assets.    We review our long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. FASB ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying

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amount of a long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long-lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to us are recorded at the lower of carrying amount or fair value less cost to sell.

New Accounting Pronouncements

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

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

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

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

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

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

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

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

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

Qualitative and Quantitative Disclosures about Market Risk

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

        The following table reconciles the changes that occurred in fair values of our open derivative contracts during the nine months ending September 30, 2010:

 
  Derivative Contracts Assets (Liabilities)  
 
  Commodities   Interest Rates   Total  
 
  (In thousands)
 

Fair value of contracts outstanding as of December 31, 2009

  $   $   $  

Changes in contract fair value

    (15,310 )   (13,917 )   (29,227 )

Contract maturities

        3,142     3,142  
               

Fair value of contracts outstanding as of September 30, 2010

  $ (15,310 ) $ (10,775 ) $ (26,085 )
               

Commodity Derivative Instruments

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

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

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Commodity Price Sensitivity

        The following tables provide information about our oil derivative financial instruments that were sensitive to changes in oil prices as of September 30, 2010.

 
  Year Ending December 31   Liability Fair
Value at
September 30
2010
 
 
  2011   2012   2013  

Oil Derivatives:

                         
 

Deferred premium puts

                         
   

Average daily notional bbl volumes

    11,332     4,625     2,515   $ 12,221  
   

Weighted average floor price per bbl

  $ 72.01   $ 62.74   $ 61.73        
   

Weighted average deferred premium

  $ 8.90   $ 7.04   $ 7.32        
 

Compound options (calls on puts)(1)

                         
   

Average daily notional bbl volumes

        5,399     3,855   $ 3,089  
   

Weighted average floor price per bbl

  $   $ 66.48   $ 66.48        
   

Weighted average deferred premium

  $   $ 6.73   $ 7.10        

Average forward Dated Brent oil prices(2)

  $ 93.34   $ 93.47   $ 92.94        

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

(2)
The average forward Dated Brent oil prices are based on January 7, 2011 market quotes.

Interest Rate Risk

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

        As of September 30, 2010, the fair market value of our interest rate swaps was a net liability of approximately $10.8 million. If the LIBOR rate increased by 10%, we estimate the liability would decrease approximately $9.7 million, and if the LIBOR rate decreased by 10%, we estimate the liability would increase to approximately $11.9 million.

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INDUSTRY

Global Oil and Gas Industry

    Location of Kosmos' Assets in Africa and Related Market Accessibility

    GRAPHIC

        West African offshore oil production is strategically situated to supply the growth markets of non-OECD countries, including those in Asia, as well as North American and European markets. According to African Business Review, although Africa is estimated to only have approximately 10% of the world's proven oil reserves, by 2025 it will provide an estimated 25% of North America's oil imports. The compound annual growth rate of oil reserves from 1989 to 2009 in Africa was 1.4% and from 1999 to 2009 was 2.1%. The following pie charts depict global proved reserve growth rates by region over the last 20 years.

    Distribution of Proved Reserves in 1989, 1999 and 2009

    GRAPHIC

        Source: BP Statistical Review.

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    Brent Crude

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

West Africa

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

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

GRAPHIC

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

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

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

Ghana

    Country Overview

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

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

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

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

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

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

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    Oil and Gas Industry

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

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

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

        The oil industry in Ghana is still in its early stages. A large portion of the data available about industry and geological characteristics comes from exploration and development activity undertaken by us and our block partners. See "Risk Factors—We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects, so you should not place undue reliance on any of our measures."

    Tano Basin

        The Tano Basin is situated offshore Ghana. The main hydrocarbon prospects in the Tano Basin are located in the Late Cretaceous stratigraphic section. The Late Cretaceous is a geological time period consisting of sediments that are 65 to 100 million years old. In particular, sediments from two stages of the Late Cretaceous period have provided notable exploration success: the Turonian (89 to 94 million years old) and the Campanian (71 to 84 million years old). These reservoirs are part of large submarine fan and channel systems that were associated with a paleo-Volta River system. A number of these drainage systems exist along the ancient West African Transform Margin from Ghana to Sierra Leone. To date, the Turonian and Campanian reservoirs have proven to be of high quality with porosities in the 15% to 28% range and permeabilities typically in the 100 millidarcies to 2 darcies range.

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

    Exploration History

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

        Ghanaian deepwater exploration activity started in earnest in 2007 when Kosmos drilled its first exploration well, Mahogany-1, on the WCTP Block and made the Mahogany discovery. This was

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followed in August 2007 by the Hyedua-1 well on the DT Block, which encountered the same oil accumulation. The results of the Hyedua-1 well confirmed the Mahogany-Hyedua field was one continuous structure, extending across the two blocks. This new field was renamed the Jubilee Field. Jubilee was one of the largest oil discoveries worldwide in 2007 and the largest find offshore West Africa in the last decade. The reservoirs in the Jubilee Field are of a very high quality and, based on our drilling results to date, we estimate they have a mean hydrocarbon yield of 225 barrels of oil-equivalent per acre-foot.

        Between the first quarter of 2008 and end of 2009, the industry drilled several exploration wells offshore Ghana resulting in five further discoveries in the Tano Basin. The Odum and the Tweneboa Fields were discovered on the WCTP and the DT Blocks respectively. The Mahogany-3 well confirmed another similar aged accumulation adjacent to the Jubilee field while also discovering the Mahogany-Deep reservoir within the WCTP Block. In 2010, the Owo-1 discovery well was successfully completed by Kosmos and its block partners and the Onyina exploration well was drilled. The repeated success of our and our partners' exploration drilling to date has demonstrated that the northern part of the deepwater Tano Basin contains a world class petroleum system. Based on these results and industry analogues in the region, we estimate the Tano Basin has a mean hydrocarbon yield of 180 barrels of oil equivalent per acre-foot. In the block known as "Cape Three Points," Vitol discovered the Sankofa Field approximately 23 miles (38 kilometers) east of the Jubilee Field. The block known as "Cape Three Points Deepwater" also yielded a Cretaceous aged discovery when the Vanco-Lukoil partnership drilled the Dzata structure approximately 70 miles (112 kilometers) east of the Jubilee Field.

Cameroon

    Country Overview

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

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

        The U.S. State Department describes U.S. relations with Cameroon as close. While on the UN Security Council in 2002, Cameroon worked alongside the United States on a number of initiatives. The U.S. Government continues to provide substantial funding for international financial institutions, such as the World Bank, IMF, and African Development Bank, which provide financial and other assistance to Cameroon.

    Oil and Gas Industry

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

        Kosmos has interests in two blocks in Cameroon, the Ndian River Block in the Rio del Rey Basin, in which it operates with a 100% equity interest and the Perenco operated, Kombe-N'sepe Block located in the Douala Basin, in which Kosmos maintains a 35% interest. These licenses, which together comprise an area covering approximately 1.2 million acres (4,800 square kilometers), represent the equivalent of 238 standard deepwater U.S. Gulf of Mexico blocks.

        Oil and gas companies with interests in these basins include Bowleven PLC Oil and Gas Company, Hess, Noble Energy ("Noble"), Marathon Oil ("Marathon"), Sinopec Corp., Pecten Cameroon

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Company and Total S.A. ("Total"). According to Wood Mackenzie, during 2009, Cameroon produced 74,000 bopd, a reduction of 56% from its peak oil production of 167,600 bopd (which was achieved in 1986).

        Based on data from Cameroon's historical oil and gas production, we have made estimates about the geologic characteristics of Cameroon's basins. See "Risk Factors—We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects, so you should not place undue reliance on any of our measures."

    Douala Basin

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

        The Douala Basin lies southeast of the Cameroon volcanic trend, which forms the northern limit of the basin. The basin extends south into the neighboring country of Equatorial Guinea, where recoverable oil reserves of approximately 525 Mmbbl are being produced from the Late Cretaceous Ceiba and Northern Block G oil developments. Notably, the Northern Block G and Ceiba fields were discovered by Triton, which was led by current members of the Kosmos technical and management teams. More recently, the northern part of the Douala Basin has seen successful drilling in the Miocene, with several oil and natural gas discoveries by Noble. Miocene uplift has resulted in the present day onshore part of the basin containing deepwater, Late Cretaceous reservoirs and seals. Based on industry drilling results and production history, we estimate that reservoirs in this basin have a mean hydrocarbon yield of 390 barrels of oil equivalent per acre-foot. The onshore part of the basin is characterized by low-lying ground covered in forest, swamps and plantations.

    Rio del Rey Basin

        Adjacent to the Niger Delta, the Rio del Rey Basin is a predominantly Tertiary petroleum system with existing production from primarily Miocene aged, shelf and deepwater four-way and three-way structural closures. Discoveries in this region include the Kombo, Ekundu and Abana oil fields. It is estimated that 65% of Cameroon's 1.8 Bboe of commercial reserves lie in the offshore Rio del Rey Basin. Adjacent to the basin's oil province, the industry has also had access to the Rio Del Rey Basin's outboard natural gas condensate play, which contains Marathon's giant Alba field located in Equatotial Guinea.

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

        The Niger and Rio del Rey rivers provided sand to the basin throughout the Tertiary, and, as a result, the basin contains very good quality reservoirs. The reservoirs consist of individual channels and sand bodies. Porosities are as high as 35%, averaging 15% to 25%. Permeability is exceptional, commonly in the 0.1 to 2 darcy range. Based on industry drilling results and production history, we estimate that reservoirs in this basin have an average hydrocarbon yield of 325 barrels of oil equivalent per acre-foot.

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

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    Exploration History

        The first hydrocarbon exploration in Cameroon took place in the 1920s and was concentrated in the onshore area of the Douala Basin. Initial exploration was encouraged by naturally occurring oil and natural gas seeps in the region. Exploration drilling in the Douala Basin, both onshore and offshore, remained sporadic until 1979, when ExxonMobil discovered the Sanaga Sud natural gas field. This discovery resulted in an exploration focus in structural traps in Albian and Aptian aged reservoirs. A limited number of Tertiary exploration wells have been drilled and in most cases these have encountered oil, including the Coco Marine-1 well drilled by ConocoPhillips Company in 2002. Between 2005 and 2009, a number of oil and natural gas discoveries were made in 3D seismic defined, Micoene, deepwater stratigraphic traps adjacent to the Kosmos license area. These discoveries are currently the focus of development drilling and contain reserves of 800 Mmboe according to IHS Inc. ("IHS").

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

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

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

Morocco

    Country Overview

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

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

        Kosmos' interests are geographically located offshore Western Sahara. The sovereignty of this territory has been in dispute since 1975. See "Risk Factors—A portion of our asset portfolio is in Western Sahara, and we could be adversely affected by the political, economic, and military conditions

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

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

    Oil and Gas Industry

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

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

        Oil and gas companies with interests in Morocco have included Dana, Mærsk Olie og Gas As, Petroliam Nasional Berhad ("Petronas"), Repsol YPF S.A., San Leon Energy plc, Statoil ASA and Suncor Energy Inc. According to Wood Mackenzie, during 2009, Morocco produced less than 100 boepd.

    Aaiun Basin

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

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

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

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

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    Exploration History

        The first oil fields were discovered and developed in Morocco in the 1930s in the onshore Rharb Basin. In the 1960s and 1970s a number of wells were drilled to test features offshore in the southern part of Morocco and Western Sahara. These wells encountered evidence of oil and natural gas but did not test valid structures as they were located utilizing very poor geologic and geophysical seismic databases. Drilling by ExxonMobil immediately to the north of the Boujdour Offshore Block in the early 1970s resulted in the discovery of oil in Jurassic carbonates. Recent drilling onshore, adjacent to the Boujdour Offshore Block, by ONHYM has resulted in the recovery of heavy oil from Late Cretaceous silts and shales. Although there is limited hydrocarbon production in Morocco, we estimate the average hydrocarbon yield for this basin to be of 150 barrels of oil equivalent per acre-foot, based on industry analogues in depositional environments similar to those we expect to encounter in our Boujdour Offshore Block prospects.

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BUSINESS

Overview

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

        After our formation in 2003, we acquired our current portfolio of exploration licenses and established a new, major oil province in West Africa with the discovery of the Jubilee Field in 2007. This was the first of our five discoveries offshore Ghana; it was one of the largest oil discoveries worldwide in 2007 and the largest find offshore West Africa during the last decade. Oil production from the Jubilee Field offshore Ghana commenced on November 28, 2010, and we anticipate receiving our first oil revenues in early 2011. We expect gross oil production from the Jubilee Field to reach its design capacity of 120,000 bopd in mid 2011.

Our Competitive Strengths

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

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

        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 62nd out of 178 countries in Transparency International's 2010 Corruption Perceptions Index, vastly ahead of each of its peers according to a peer group selected by Standard & Poor's. Ghana is also the highest ranked among such peer group in the World Bank's Doing Business 2011 report, at fifth out of 46 sub-Sahara African countries included in such report.

        Our asset portfolio consists of five discoveries including the Jubilee Field, which is one of the largest oil discoveries worldwide in 2007 and the largest find offshore West Africa in the last decade. Our other discoveries include, Mahogany East, Odum, Tweneboa and Enyenra offshore Ghana, which have geologic characteristics similar to the Jubilee Field. In addition, we have identified 20 additional prospects offshore Ghana, 10 additional prospects in Cameroon and 19 additional prospects offshore Morocco. We expect to make new discoveries and to define additional prospects as our team continues to develop our current portfolio and identify and pursue new high-potential assets.

    Well-defined production and growth plan

        Our plan for developing the Jubilee Field provides highly visible, near-term cash generation and long-term growth opportunities. We estimate Jubilee Field Phase 1 daily gross production to reach the 120,000 bopd design capacity of the floating production, storage and offloading ("FPSO") facility used at the field, in mid 2011. Within the next few years, we intend to expand upon the Jubilee Field Phase 1 development with three additional phases that are designed to maintain production and cash flow from partially de-risked locations. A phased drilling program allows us to develop the Jubilee Field on a faster timeline and allowed us to achieve first oil production at an earlier date than

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traditional development techniques. In addition to Jubilee, we are currently in the development planning stage for Mahogany East, the pre-development planning stage for the Odum discovery, and the appraisal stage for the Tweneboa and Enyenra discoveries. We believe these assets provide additional mid-term production and cash flow opportunities to supplement the phased Jubilee Field development.

    Significant upside potential from exploratory assets

        Since our inception we have focused on acquiring exploratory licenses in emerging petroleum basins in West Africa. This led to the assembly of a hydrocarbon asset portfolio of five licenses with significant upside potential and attractive fiscal terms. In Ghana, we believe our existing licenses offer substantial opportunities for significant growth in shareholder value as a result of numerous high value exploration prospects that are partially de-risked due to their similarity and proximity to our existing discoveries. For instance, we are currently drilling the Teak-1 exploration well north of the Jubilee Field. We plan to drill two exploratory wells in Cameroon, one on our Kombe-N'sepe Block in early 2011 and the other on our Ndian River Block in early 2012.

    Oil-weighted asset portfolio in key strategic regions

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

    New ventures group focused on expanding our high-quality asset portfolio

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

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

        We are led by an experienced management team with a track record of successful exploration and development and public shareholder value creation. Our management team's average experience in the energy industry is over 20 years. Members of the senior management team successfully worked together both at and since their tenure at Triton, where they contributed to transforming Triton into one of the largest internationally focused independent oil and gas companies headquartered in the United States, prior to the sale of Triton to Hess Corporation ("Hess") for approximately $3.2 billion in 2001. Members of our management and senior technical team participated in discovering and developing multiple large scale upstream projects around the world, including the deepwater Ceiba Field, which

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was developed on budget and in record time offshore Equatorial Guinea, in West Africa in 2000. In the course of this work, the team acquired a track record for successful identification, acquisition and development of large offshore oil fields, and has been involved in discovering and developing over five Bboe. We believe our unique experience, industry relationships, and technical expertise have been critical to our success and are core competitive strengths.

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

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

    Strong financial position

        Since inception we have been backed by our Investors, namely Warburg Pincus and The Blackstone Group, each supporting our initial growth with substantial equity investments. Each Investor will retain a significant interest in Kosmos following this offering. With the proceeds from this offering, our cash on hand and our commercial debt commitments, we believe we will possess the necessary financial strength to implement our business strategy through early 2013. As of September 30, 2010, we had approximately $292 million of total cash on hand, including $89 million of restricted cash, and $300 million of committed undrawn capacity under our commercial debt facilities. In addition, we have demonstrated the ability to raise capital, having secured commitments for approximately $1.1 billion of private equity funding and $1.25 billion of commercial debt commitments in the last seven years. Furthermore, we anticipate receiving our first oil revenues in early 2011 from the Jubilee Field, after which time a portion of these revenues will be used to fund future exploration and development activities.

Our Strategy

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

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

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

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

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

    Focus on rapidly developing our discoveries to initial production

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

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

    Identify, access and explore emerging exploratory regions and hydrocarbon plays

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

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

    Acquire additional exploration assets

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

Kosmos Exploration Approach

        The Kosmos exploration philosophy is deeply rooted in a fundamental, geologically based approach geared towards the identification of misunderstood, under-explored or overlooked petroleum systems. This process begins with detailed geologic studies that methodically assess a particular region's subsurface, with particular consideration to those attributes that lead to working petroleum systems. The process includes basin modeling to predict oil charge and fluid migration, as well as stratigraphic and structural analysis to identify reservoir/seal pair development and trap definition. This analysis integrates data from previously drilled wells and seismic data available to Kosmos. Importantly, this approach also takes into account a detailed analysis of geological timing to ensure that we have appropriate understanding of whether the sequencing of geological events would support and preserve hydrocarbon accumulation. Once an area is high-graded based on this play/fairway analysis, detailed geophysical analysis is conducted to identify prospective traps of interest. We also work with NSAI in assessing our prospects.

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

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

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

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exploration concept options, prospect dependency to enhance the chance of replicating success and sufficiently attractive fiscal terms to maximize the commercial viability of discovered hydrocarbons.

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

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

Our Discoveries and Prospects

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

Discoveries
  License   Aerial Extent
(acres)
  Kosmos
Working
Interest
  Block Operator(s)   Stage   Type   Expected
Year of PoD
Submission

Ghana

                               
 

Jubilee Field Phase 1(1)(2)

  WCTP/DT(3)     8,300     23.4913 %(5) Tullow/Kosmos(6)   Production   Deepwater   2008(2)
 

Jubilee Field subsequent phases(2)

  WCTP/DT(3)     4,600     23.4913 %(5) Tullow/Kosmos(6)   Development   Deepwater   2011
 

Mahogany East

  WCTP(4)     6,600     30.8750 % Kosmos   Development planning   Deepwater   2011
 

Odum

  WCTP(4)     1,900     30.8750 % Kosmos   Development planning   Deepwater   2011
 

Tweneboa

  DT(4)     19,200     18.0000 % Tullow   Appraisal   Deepwater   2012(7)
 

Enyenra

  DT(4)     28,100     18.0000 % Tullow   Appraisal   Deepwater   2013

(1)
For information concerning our estimated proved reserves in the Jubilee Field as of June 30, 2010, see "—Our Reserves."

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

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

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

(5)
These interest percentages are subject to redetermination of the working interests in the Jubilee Field pursuant to the terms of the UUOA. See "Risk Factors—The unit partners' respective interests in the Jubilee Unit are subject to redetermination and our interests in such unit

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    may decrease as a result" and "—Material Agreements—Exploration Agreements—Ghana—Jubilee Field Unitization." GNPC has exercised its WCTP and DT PA options, with respect to the Jubilee Unit, to acquire an additional unitized paying interest of 3.75% in the Jubilee Field. The Jubilee Field interest percentages give effect to the exercise of such option.

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

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

Prospect Information

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

Prospect
  License   Aerial
Extent
(acres)
  Kosmos
Working
Interest (%)
  Block
Operator
  Type   Projected
Spud Year(3)

Ghana(1)

                           
 

Teak

  WCTP     21,800     30.875   Kosmos   Deepwater   2010
 

Banda Campanian

  WCTP     8,800     30.875   Kosmos   Deepwater   2011
 

Banda Cenomanian

  WCTP     15,000     30.875   Kosmos   Deepwater   2011
 

Makore

  WCTP     12,300     30.875   Kosmos   Deepwater   2011
 

Odum East

  WCTP     3,100     30.875   Kosmos   Deepwater   2011
 

Sapele

  WCTP     19,100     30.875   Kosmos   Deepwater   2012
 

Funtum

  WCTP     6,700     30.875   Kosmos   Deepwater   2012
 

Assin

  WCTP     2,600     30.875   Kosmos   Deepwater   2012
 

Okoro

  WCTP     4,600     30.875   Kosmos   Deepwater   Post 2012
 

Late Cretaceous WCTP Play (4 identified targets)

  WCTP     8,100     30.875   Kosmos   Deepwater   Post 2012
 

Tweneboa Deep

  DT     20,100     18.000   Tullow   Deepwater   2012
 

Walnut

  DT     2,900     18.000   Tullow   Deepwater   2012
 

DT Sapele

  DT     4,600     18.000   Tullow   Deepwater   2012
 

Wassa

  DT     8,900     18.000   Tullow   Deepwater   Post 2012
 

Adinkra

  DT     1,300     18.000   Tullow   Deepwater   Post 2012
 

Oyoko

  DT     1,900     18.000   Tullow   Deepwater   Post 2012
 

Ananta

  DT     1,600     18.000   Tullow   Deepwater   Post 2012

Cameroon(2)

                           
 

N'gata

  Kombe-N'sepe     6,100     35.000   Perenco   Onshore   2011
 

N'donga

  Kombe-N'sepe     6,400     35.000   Perenco   Onshore   Post 2012
 

Disangue

  Kombe-N'sepe     5,200     35.000   Perenco   Onshore   Post 2012
 

Pongo Songo

  Kombe-N'sepe     2,400     35.000   Perenco   Onshore   Post 2012
 

Bonongo

  Kombe-N'sepe     3,100     35.000   Perenco   Onshore   Post 2012
 

Coco East

  Kombe-N'sepe     2,800     35.000   Perenco   Onshore   Post 2012
 

Liwenyi

  Ndian River     12,100     100.000   Kosmos   Onshore   2012
 

Liwenyi South

  Ndian River     4,000     100.000   Kosmos   Onshore   Post 2012
 

Meme

  Ndian River     1,600     100.000   Kosmos   Onshore   Post 2012
 

Bamusso

  Ndian River     3,800