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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS
Table of Contents

As filed with the Securities and Exchange Commission on March 23, 2011

Registration No. 333-171700

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

Amendment No. 2
to
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

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

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

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

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

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

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

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

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
 	 	 	 	 	 	 	
Large accelerated filer o	 	Accelerated filer o	 	Non-accelerated filer ý
(Do not check if a
smaller reporting company)	 	Smaller reporting company o	
         The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

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

SUBJECT TO COMPLETION, DATED MARCH 23, 2011

                    Shares

Kosmos Energy Ltd.

Common Shares

        This is an initial public offering of common shares of Kosmos Energy Ltd. Prior to this offering, there has been no public market for our common shares. The initial public offering price of the common shares is expected to be between $            and $            per share. We have applied for our common shares to be listed 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 17.

 	
 
	 	Price to Public
	 	Underwriting
Discounts and
Commissions
	 	Proceeds
to Us

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

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

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

Barclays Capital
	
The date of this prospectus is                    , 2011.

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TABLE OF CONTENTS

 
	 	Page	
PROSPECTUS SUMMARY	 	1	
RISK FACTORS	 	17	
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS	 	45	
DIVIDEND POLICY	 	47	
USE OF PROCEEDS	 	48	
CORPORATE REORGANIZATION	 	49	
CAPITALIZATION	 	50	
DILUTION	 	52	
SELECTED HISTORICAL AND PRO FORMA FINANCIAL INFORMATION	 	53	
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	 	56	
INDUSTRY	 	72	
BUSINESS	 	80	
MANAGEMENT	 	121	
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	 	137	
PRINCIPAL SHAREHOLDERS	 	138	
DESCRIPTION OF SHARE CAPITAL	 	141	
SHARES ELIGIBLE FOR FUTURE SALE	 	148	
CERTAIN TAX CONSIDERATIONS	 	150	
UNDERWRITING	 	153	
LEGAL MATTERS	 	160	
EXPERTS	 	160	
WHERE YOU CAN FIND ADDITIONAL INFORMATION	 	160	
GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS	 	161	
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 160.

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 six discoveries offshore Ghana; it was one of the largest oil discoveries worldwide in 2007 and the largest find offshore West Africa in the last decade. Oil production from the Jubilee Field offshore Ghana commenced on November 28, 2010, and we received our first oil revenues in early 2011. We expect gross oil production from the Jubilee Field to reach the design capacity of the floating, production, storage and offloading ("FPSO") facility used to produce from the field of 120,000 barrels of oil per day ("bopd") in mid 2011. At that rate, the share of this gross oil production net to us is expected to be 28,200 bopd.

        Since our inception, over two-thirds of our exploration and appraisal wells have encountered hydrocarbons in quantities that we believe will ultimately be commercially viable. These successes, all of which are offshore Ghana, include the Jubilee Field, Mahogany East (which includes the Mahogany Deep discovery) and four other discoveries in the appraisal and pre-development stage: Odum, Tweneboa, Enyenra (formerly known as Owo) and Teak. To date we have identified 48 undrilled prospects within our existing license areas, including 19 prospects across three play types offshore Ghana, 10 prospects across three play types in Cameroon and 19 prospects across three play types

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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)	 	 	15/16	 	 	12	 	 	30.875	%(4)	
 	 	 	 	 	 	Tano Basin	 	Odum (2008)	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Mahogany East (2009)	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Teak (2011)	 	 	 	 	 	 	 	 	 	 	
Deepwater Tano ("DT")	 	 	
205,345	 	Gulf of Guinea's	 	Jubilee (2007)(3)	 	 	
13/14	 	 	
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	 	Coastal strip of	 	—	 	 	
—	 	 	
4	 	 	
100.000	
%(7)	
 	 	 	 	 	Rio del Rey Basin	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	bordering the Gulf	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	of Guinea	 	 	 	 	 	 	 	 	 	 	 	 	
Morocco	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Boujdour Offshore(1)	 	 	10,869,654	(2)	Northwest Africa's	 	—	 	 	—	 	 	19	 	 	75.000	%(8)	
 	 	 	 	 	Aaiun Basin	 	 	 	 	 	 	 	 	 	 	 	 	

(1)
Kosmos is the operator under these licenses.

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

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

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

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

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

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

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

        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

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

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

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

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

Our Competitive Strengths

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

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

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

        Our asset portfolio consists of six discoveries including the Jubilee Field, which was one of the largest oil discoveries worldwide in 2007 and the largest find offshore West Africa in the last decade. Our other discoveries include Mahogany East, Odum, Tweneboa, Enyenra and Teak offshore Ghana, which have geologic characteristics similar to the Jubilee Field. In addition, we have identified 19 additional prospects offshore Ghana, 10 additional prospects in Cameroon and 19 additional prospects offshore Morocco. We expect to make new discoveries and to define additional prospects as our team continues to develop our current 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 120,000 bopd design capacity of the FPSO facility used to produce from the field, in mid 2011. Within the next few years, we intend to expand upon the Jubilee Field Phase 1 development with three

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additional phases that are designed to maintain production and cash flow from partially de-risked locations. A phased development program allows us to develop Jubilee Phase 1 on a faster timeline and allowed us to achieve first oil production at an earlier date than traditional development techniques. See "—Our Strategy—Focus on rapidly developing our discoveries to initial production." In addition to Jubilee, we are currently in the development planning stage for Mahogany East, the pre-development planning stage for the Odum discovery, and the appraisal stage for the Tweneboa, Enyenra and Teak discoveries. We believe these assets provide additional mid-term production and cash flow opportunities to supplement the phased Jubilee Field development.

Significant upside potential from exploratory assets

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

Oil-weighted asset portfolio in key strategic regions

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

New ventures group focused on expanding our 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 the work of our new ventures group, which is tasked with executing a high-impact 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 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 December 31, 2010, we had approximately $212 million of total cash on hand, including $112 million of restricted cash, and $205 million of committed undrawn capacity under our 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 received our first oil revenues in early 2011 from the Jubilee Field, and accordingly a portion of these revenues will be used to fund future exploration and development activities.

Our Strategy

        In the near-term, we are focused on maximizing production from the Jubilee Field Phase 1 development, as well as accelerating the development of our other discoveries. Longer term, we are focused on the 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, Enyenra and Teak. 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 appraisal and development plans based on experience gained in initial phases and by leveraging existing infrastructure as we implement subsequent phases of development. Other benefits include minimizing upfront capital costs, reducing execution risks through smaller initial infrastructure requirements, and enabling cash flow from the initial phase of production to fund a portion of capital costs for subsequent phases.

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

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.

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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.

Jubilee Phase 1 Reserve and Development Information

        Jubilee Field Phase 1 is the first of our discoveries to have been determined to have proved reserves. As of December 31, 2010, Netherland, Sewell & Associates, Inc. ("NSAI"), our independent reserve engineers, evaluated the Jubilee Field Phase 1 development to hold gross proved reserves of 250 Mmboe. We currently hold a 23.4913% unit participation interest in this development (subject to any redetermination among the unit partners in this field. See "Risk Factors—The unit partners' respective interests in the Jubilee Unit are subject to redetermination and our interests in such unit may decrease as a result" and "Business—Material Agreements—Exploration Agreements—Ghana—Jubilee Field Unitization"). NSAI estimated our net proved reserves to be approximately 60 Mmboe as of December 31, 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, Teak and other Jubilee Field phases, do not yet have approved plans of development ("PoDs") and therefore cannot be classified as proved reserves.

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

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

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Discovery Information

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

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

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

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

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

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

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

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

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Prospect Information

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

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

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

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

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

(5)
The N'gata-1 exploration well was spud in early 2011 and is currently being drilled.

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Recent Events

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

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

        In February 2011, we announced that Chris Tong has been appointed to the Kosmos board of directors, subject to certain corporate formalities.

        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.

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

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

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

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

Risks Associated with our Business

        There are a number of risks you should consider before buying our common shares. These risks are discussed more fully in the section entitled "Risk Factors" beginning on page 16 of this prospectus. These risks include, but are not limited to:

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

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

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

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

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

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

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

Corporate Information

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

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for newly issued common shares of Kosmos Energy Ltd. and as a result Kosmos Energy Holdings will become wholly-owned by Kosmos Energy Ltd.

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

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The Offering

Issuer	 	Kosmos Energy Ltd.	
Common shares offered by us	 	            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 have applied for our common shares to be listed on the New York Stock Exchange (the "NYSE") under the symbol "KOS." Shortly after the closing of this offering, we intend to apply to list our common shares on the Ghana Stock Exchange (the "GSE"), although there can be no assurance that this listing will be completed in a timely manner, or at all.	
        Except as otherwise indicated, all information in this prospectus assumes:

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

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

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

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

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

Consolidated Statements of Operations Information:

	 	 

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

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

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

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redeemable upon the consummation of a qualified public offering (as defined in the current operating agreement) into common shares of Kosmos Energy Ltd. based on the pre-offering equity value of such interests. Consequently, pro forma basic and diluted net loss per common share is presented above, giving effect to the additional shares of common stock issuable to the pro forma shareholders upon consummation of this offering.(2)
Any stock options, restricted share units and share appreciation rights that are out of the money will be excluded as they will be anti-dilutive.

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

Consolidated Balance Sheets Information:

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

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

Consolidated Statements of Cash Flows Information:

	 	 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•
the timing and amount of capital expenditures;

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•
the operator's expertise and financial resources;

•
approval of other block partners in drilling wells;

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

•
selection of technology; and

•
the rate of production of reserves, if any.

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

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

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

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

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

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

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

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

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

•
actual prices we receive for oil and natural gas;

•
actual cost of development and production expenditures;

•
derivative transactions;

•
the amount and timing of actual production; and

•
changes in governmental regulations or taxation.

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

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

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

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

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

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

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

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

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

•
oil and natural gas prices;

•
our ability to locate and acquire hydrocarbon reserves;

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

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

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

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

        We do not currently have any commitments for future external funding beyond the capacity of our commercial debt 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 would dilute our ownership interest subject to the farm-out and any potential value resulting therefrom, and may lose operating control or influence over such license areas.

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

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

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

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

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

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

•
global economic conditions;

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

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

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

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

•
weather conditions and natural disasters;

•
technological advances affecting energy consumption;

•
governmental regulations and taxation policies;

•
proximity and capacity of transportation facilities;

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

•
the price and availability of alternative fuels.

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

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas assets and this could result in reduced availability under our commercial debt 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 appraisal and development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas assets. A write-down constitutes a non-cash charge to earnings.

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

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

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

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

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

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

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

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

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

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

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

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

We are subject to drilling and other operational environmental hazards.

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

•
fires, blowouts, spills, cratering and explosions;

•
mechanical and equipment problems, including unforeseen engineering complications;

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

•
gas flaring operations;

•
marine hazards with respect to offshore operations;

•
formations with abnormal pressures;

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

•
weather conditions and natural disasters.

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

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

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

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

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

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

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

        All of our proved reserves and our discovered fields are located offshore Ghana. The WCTP Petroleum Agreement and the DT Petroleum Agreement cover the two blocks that form the basis of our exploration, development and production operations in Ghana. Pursuant to these petroleum agreements, most significant decisions, including our plans for development and annual work programs, must be approved by GNPC and/or Ghana's Ministry of Energy. We previously had disagreements with Ghana and GNPC regarding certain of our rights and responsibilities under these petroleum agreements 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.

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

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

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

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

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

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

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

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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 Act and a new Petroleum Revenue Management Act. There can be no assurance that the final laws will not seek to retroactively modify the terms of the agreements governing our license interests in Ghana, including the WCTP and DT Petroleum Agreements and the UUOA, require governmental approval for transactions that effect a direct or indirect change of control of our license interests or otherwise affect our current and future operations in Ghana. Any such changes may have a material adverse affect on our business. See "Business—Other Regulation of the Oil and Gas Industry—Ghana."

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

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

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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."

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

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

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

        MODEC, the contractor for the FPSO for the Jubilee Field Phase 1 development, is being investigated by its legal advisors, the Jubilee Unit partners and the syndicate of international banks who had committed to refinance the construction costs of the FPSO (a portion of such costs were originally loaned by the Jubilee Unit partners, including Kosmos) regarding matters which may give rise to

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certain FCPA violations. See "Risk Factors—The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results." While we had no prior knowledge of the matters under investigation, should the DOJ launch a formal investigation into these matters, there can be no assurance that the Jubilee Unit partners, including us, would not be subject to enforcement actions which may have a material adverse affect on our business.

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

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

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

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

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

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

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

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

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

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;

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•
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;

•
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,

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borrowings or equity financing may not be available to pay or refinance such indebtedness. Factors that will affect our ability to raise cash through an offering of our equity securities or a refinancing of our indebtedness include financial market conditions, the value of our assets and our performance at the time we need capital.

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

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

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

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

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

•
recoverable reserves;

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

•
development and operating costs; and

•
potential environmental and other liabilities.

        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;

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•
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 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;

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

•
establish an investor relations function.

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

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

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

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

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

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

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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 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

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our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. In addition, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Lastly, the Dodd-Frank Act requires, no later than 270 days after the enactment of the Act, the SEC to promulgate rules requiring SEC reporting companies that engage in the commercial development of oil, natural gas or minerals, to include in their annual reports filed with the SEC disclosure about all payments (including taxes, royalties, fees and other amounts) made by the issuer or an entity controlled by the issuer to the United States or to any non-U.S. government for the purpose of commercial development of oil, natural gas or minerals. As these rules are not yet effective, we are unable to predict what form these rules may take and whether we will be able to comply with them without adversely impacting our business, or at all. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

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

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

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

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

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•
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 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.

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

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

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

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

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

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

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

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

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

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

        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.

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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 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.

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        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 issued and outstanding shares entitled to vote. Under Bermuda law, in the event of an amalgamation of a Bermuda company with another company or corporation, a shareholder of the Bermuda company who is not satisfied that fair value has been offered for such shareholder's shares may, within one month of notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the fair value of those shares. Under Delaware law, with certain exceptions, a merger, consolidation or sale of all or substantially all the assets of a corporation must be approved by the board of directors and a majority of the issued and outstanding shares entitled to vote thereon. Under Delaware law, a shareholder of a corporation participating in certain major corporate transactions may, under certain circumstances, be entitled to appraisal rights pursuant to which such shareholder may receive cash in the amount of the fair value of the shares held by such shareholder (as determined by a court) in lieu of the consideration such shareholder would otherwise receive in the transaction.

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

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

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

•
environmental liabilities;

•
geological, technical, drilling and processing problems;

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•
military operations, terrorist acts, wars or embargoes;

•
the cost and availability of adequate insurance coverage;

•
our vulnerability to severe weather events; and

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

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

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DIVIDEND POLICY

        At the present time, we intend to retain all of our future earnings, if any, generated by our operations for the development and growth of our business. Additionally, we are subject to Bermuda legal constraints that may affect our ability to pay dividends on our common shares and make other payments. Under the Bermuda Companies Act, we may not declare or pay a dividend if there are reasonable grounds for believing that we are, or would after the payment be, unable to pay our liabilities as they become due or that the realizable value of our assets would thereafter be less than the aggregate of our liabilities, issued share capital and share premium accounts. Certain of our subsidiaries are also currently restricted in their ability to pay dividends to us pursuant to the terms of our commercial debt 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 (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 $                        (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 Share Capital" for additional information regarding the terms of our memorandum of association and bye-laws as will be in effect upon the closing of this offering.

        Upon the completion of the reorganization, Kosmos Energy Holdings' current operating agreement will be 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 December 31, 2010 on an actual basis, pro forma to give effect to our corporate reorganization and pro forma as adjusted for the effect of this offering.

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

	 	As of December 31, 2010	 	
 
	 	Actual	 	Pro Forma to
Give Effect to our
Corporate
Reorganization(1)	 	Pro Forma as
Adjusted for the
Effect of this
Offering(1)(2)	 	
 
	 	(In thousands, except per share data)
	 	
Cash and cash equivalents	 	$	100,415	 	$	    	 	$	    	 	
Restricted cash	 	 	112,000	 	 	    	 	 	    	 	
 	 	 	 	 	 	 	 	
 	Total cash	 	$	212,415	 	$	    	 	$	    	 	
 	 	 	 	 	 	 	 	
Current maturities of long-term debt	 	$	245,000	 	$	    	 	$	    	 	
Long-term debt	 	 	800,000	 	 	    	 	 	    	 	
 	 	 	 	 	 	 	 	
 	Total debt	 	 	1,045,000	 	 	    	 	 	    	 	
Series A Convertible Preferred Units; 30,000,000 units outstanding, actual	 	 	383,246	 	 	—	 	 	—	 	
Series B Convertible Preferred Units; 20,000,000 units outstanding, actual	 	 	568,163	 	 	—	 	 	—	 	
Series C Convertible Preferred Units; 884,956 units outstanding, actual	 	 	27,097	 	 	—	 	 	—	 	
 	 	 	 	 	 	 	 	
 	Total Convertible Preferred Units	 	 	978,506	 	 	—	 	 	—	 	
Common units; 19,069,662 units outstanding, actual	 	 	516	 	 	—	 	 	—	 	
Common shares, $0.01 par value per share;            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	 	 	—	 	 	    	 	 	    	 	
Deficit accumulated during development stage/Retained deficit	 	 	(615,515	)	 	    	 	 	    	 	
Accumulated other comprehensive income (loss)	 	 	588	 	 	    	 	 	    	 	
 	 	 	 	 	 	 	 	
 	Total unit holdings/shareholders' equity	 	 	(614,411	)	 	    	 	 	    	 	
 	 	 	 	 	 	 	 	
 	Total capitalization	 	$	1,409,095	 	$	    	 	$	    	 	

(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 public offering price range set forth on the cover page of this prospectus) less underwriting discounts and commissions and expenses payable by us. A $1.00 decrease or increase in the

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assumed initial public offering price would result in approximately a $            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 exchanged into common shares based on the pre-offering equity value of such interests. This results in the Series A, Series B, and Series C Preferred Units and the Common Units being exchanged into                 ;                ;                 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 December 31, 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 December 31, 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 December 31, 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 December 31, 2010, on a pro forma basis as described above, the difference between the number of common shares purchased from us, the total consideration paid to us and the average price paid per 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 December 31, 2010, after giving effect to our corporate reorganization. No material change has occurred to our equity capitalization since December 31, 2010, after giving effect to our corporate reorganization and this offering.

        Each $1.00 increase (decrease) in the assumed public offering price per common share would increase (decrease) the pro forma net tangible book value by $        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, 2006, 2007, 2008, 2009 and 2010 and for the period April 23, 2003 (Inception) through December 31, 2010, and the consolidated balance sheets as of December 31, 2006, 2007, 2008, 2009 and 2010 were derived from Kosmos Energy Holdings' audited consolidated financial statements. The unaudited pro forma information is derived from Kosmos Energy Holdings' audited consolidated financial statements appearing elsewhere in this prospectus and is based on assumptions and includes adjustments as explained in the notes to the table.

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

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Consolidated Statements of Operations Information:

	 	 

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

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

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

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Consolidated Balance Sheets Information:

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

	 	 

	 	 
	 	(Unaudited)

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

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

Consolidated Statements of Cash Flows Information:

	 	 

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

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

Overview

        We are an independent oil and gas exploration and production company focused on under-explored regions in Africa. Our current asset portfolio includes world-class discoveries and partially de-risked exploration prospects offshore Ghana, as well as exploration licenses with significant hydrocarbon potential onshore Cameroon and offshore from Morocco. This portfolio, assembled by our experienced management and technical teams, will provide investors with differentiated access to both 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 and in September 2010, we entered a memorandum of understanding with ONHYM to enter a new petroleum agreement covering the highest potential areas of this block under essentially the same terms as the original petroleum agreement. Kosmos has also entered numerous agreements ancillary to the operation of the above license agreements or otherwise necessary to conduct Kosmos' oil and natural gas exploration, development and production activities.

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Factors Affecting Comparability of Future Results

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

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

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

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

        General and Administrative.    We expect general and administrative expenses to increase as a result of commencing production from the Jubilee Field on November 28, 2010 and as a result of becoming a publicly traded company. Public company costs include expenses associated with our annual and quarterly reporting, investor relations, registrar and transfer agent fees, incremental insurance costs, and accounting and legal services. These differences in general and administrative expenses are not reflected in our historical financial statements.

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

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

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

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

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our deferred tax position and at such time may reduce the statutory rate applied to the deferred tax assets in Morocco to the extent those deferred tax assets are realized within the tax holiday period.

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

        We expect to earn income from:

•
oil and natural gas sales to international markets; and

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

        We expect that our expenses will include:

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

•
maintenance and repair of property and equipment;

•
depreciation of fixed assets;

•
depletion of oilfields and associated abandonment costs;

•
exploration and appraisal costs;

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

•
selling expenses and general and administrative expenses; and

•
financing expenses, interest expense and foreign exchange losses.

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

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

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

•
changes in fair value of derivative financial instruments;

•
our success in obtaining new licenses and other acquisitions;

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

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

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

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Results of Operations

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

Year Ended December 31, 2010 vs. 2009

	 	Years Ended
December 31	 	 

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

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

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

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

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

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

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

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

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

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

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

Year Ended December 31, 2009 vs. 2008

	 	Years Ended
December 31	 	 

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

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

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

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

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

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

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

Liquidity and Capital Resources

        As we have, until recently, been a development stage entity, we are actively engaged in an ongoing process to anticipate and meet our funding requirements related to exploring for and developing oil and natural gas resources in Africa. To meet our ongoing liquidity requirements, we have historically secured funding from equity commitments and from commercial debt facilities. We have a proven ability to raise capital, having secured commitments for approximately $2.3 billion of private equity funding and commercial debt funding in the last seven years. In addition, we received our first oil revenues in early 2011 from production from Jubilee Field Phase 1. Accordingly, the cash generated from our operating activities will provide an additional source of funding going forward. We believe that our available cash, together with the net proceeds from this offering and borrowings under our commercial debt 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 $900.0 million to be used in funding our share of Jubilee Field Phase 1 development. The facilities were amended in August 2010 to increase the total commercial debt facilities amount to $1.25 billion and to add additional lenders.

        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

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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 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. The "funding sufficiency ratio" is broadly defined, for each applicable calculation period, as the ratio of (x) available funding through the assumed completion date, being the sum of the total available commitments under our commercial debt facilities, the balance of certain accounts securing our commercial debt facilities and the amount of any additional indebtedness permitted under our commercial debt facilities, to (y) total costs through the assumed completion date, being the forecasted project costs, interests and principal payments on, and costs in connection with, our commercial debt facilities, hedging payments in connection with required hedges under our commercial debt facilities, taxes payable and any other costs, fees and expenses incurred in connection with carrying out the Jubilee Field Phase 1 development. The "debt service coverage ratio" is broadly defined, for each applicable forecast period, as the ratio of (x) net cash flow for that period, to (y) aggregate costs of financing the project under our commercial debt facilities, including interest, principal, fees and expenses payable for such period. The "field life cover ratio" is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of net cash flow through the depletion of the Jubilee Field plus the net present value of capital expenditures incurred in relation to the Jubilee Phase I development and funded under our commercial debt facilities, to (y) the aggregate loan amounts outstanding under the senior facility. The "loan life cover ratio" is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of net cash flow through the maturity date of the commercial debt facilities plus the net present value of capital expenditures incurred in relation to the Jubilee Phase I development and funded under our commercial debt facilities, to (y) the aggregate loan amounts outstanding under the senior facility.

        Kosmos has the right to cancel all the undrawn commitments under the facilities if such cancellation is simultaneous with the full repayment of all outstanding loans made under the facilities. The amount of funds available to be borrowed under the senior facilities, also known as the borrowing base amount, is determined on June 15 and December 15 of each year as part of a forecast that is prepared and agreed by Kosmos and the Technical and Modeling Banks. The formula to calculate the borrowing base amount is based, in part, on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages. As of December 31, 2010, borrowings

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against the commercial debt facilities totaled $1.05 billion, of which $970.0 million is senior debt and $75.0 million is junior debt. As of December 31, 2010, the availability under our commercial debt facilities was $203.0 million, with $205.0 million of committed undrawn capacity provided for in such facilities (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 received our first oil revenues in early 2011. We expect gross oil production from the Jubilee Field to reach the design capacity of the FPSO facility used to produce from the field of 120,000 bopd in mid 2011. At that rate, the share of this gross oil production net to us is expected to be 28,200 bopd.

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

        Furthermore, if MODEC, the contractor for the FPSO we are using to produce hydrocarbons from the Jubilee Field, is unable to secure long-term financing for the cost of such FPSO in order to repay amounts originally loaned by us and certain other Jubilee Unit partners under an Advance Payments Agreement (which we are not a signatory of, as Tullow entered such agreement as Unit Operator of the Jubilee Unit) and a construction loan from a third-party for the financing of the construction of such FPSO, the Jubilee Unit partners may need to directly purchase the FPSO or find an alternative funding source or buyer. MODEC is required to repay amounts advanced on the earlier of September 15, 2011 or the date of the first drawdown under MODEC's long-term financing. Tullow is required, based on the terms of the joint operating agreement for the Jubilee Unit, to reimburse us the amounts MODEC reimburses to Tullow within ten business days of repayment by MODEC. The Advance Payments Agreement grants to the Jubilee Unit partners the option to purchase the FPSO from MODEC on or before that same date, at a discount to the market value of the FPSO. We have a

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letter agreement with certain of our partners in which they agree that should they be required to purchase the vessel they will use all reasonable endeavors to lease it back to the Jubilee Unit partners on similar terms to the current lease governing the use of the vessel. Should we elect to participate in any purchase of the vessel, our share of the remaining balance of cost to make such purchase is an amount up to approximately $120.0 million. 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.

Cash Flows

	 	 

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

	 	 
	 	 
	 	(Unaudited)

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

        Investing activities.    Net cash used in investing activities in 2010 was $590.0 million compared with net cash used in investing activities of $500.4 million and $156.9 million in 2009 and 2008, respectively. The increase in cash used in 2010 when compared to 2009 is primarily attributable to increases in restricted cash of $29.0 million related to the commercial bank facilities and $23.0 million for the cash collateralized irrevocable letter of credit associated with the Eirik Raude drilling rig and increases of

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$32.8 million in expenditures for oil and gas assets primarily in Ghana for exploration and appraisal wells and development activities. The increase in cash used in 2009 when compared to 2008 is primarily attributed to increased expenditures in Ghana for exploration and appraisal wells and development activities.

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

Contractual Obligations

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

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

(1)
Does not include any well commitments we may have under our oil and natural gas licenses.

(2)
The amounts included in the table above represent principal maturities only. Pursuant to the terms in the commercial debt facilities, when any junior debt is outstanding, repayments may be required to be made under the agreement, whereby 75% of any funds remaining on any repayment date, after required payments are made, will be applied to prepay the junior facilities and the remaining 25% will be applied to prepay the senior facilities. The table of scheduled maturities assumes the outstanding borrowings under the junior facilities will be repaid on June 15, 2016. If repayments are required as noted above, amortization of the junior facilities will occur through such repayments. Subsequent to December 31, 2010 and prior to the date of the financial statements, we borrowed an additional $28.0 million under the senior facilities. As of the date of our audited financial statements, borrowings against the commercial debt facilities totaled $1.07 billion. Subsequent to the date of our audited financial statements, we borrowed an additional $65 million under the junior facilities. As of March 23, 2011, borrowings against the commercial debt facilities totaled $1.14 billion. The scheduled principal maturities during the next five years and thereafter are (in thousands): 2011—$273,000; 2012—$250,000; 2013—$200,000; 2014—$175,000; 2015—$100,000 and thereafter—$140,000.

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

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        The following table presents maturities by expected maturity dates under 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.

	 	 

	 	 

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

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

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

Off-Balance Sheet Arrangements

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

Critical Accounting Policies

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

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

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

        Receivables.    Our receivables consist of joint interest billings, notes and other receivables for which we generally do not require collateral security. Receivables from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor's ownership interest in oil and natural gas properties we operate, and the owner's ability to pay its obligation, among other things.

        Income Taxes.    We account for income taxes as required by the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 740—Income Taxes. We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal, state and international tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets. If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of December 31, 2010, we have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. If our estimates and judgments regarding our ability to utilize our deferred tax assets change, our tax provision may increase or decrease in the period our estimates and judgments change.

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

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

        Derivative Instruments and Hedging Activities.    We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of deferred premium puts and compound options (calls on puts). We also use interest rate swap contracts to mitigate our exposure to interest rate fluctuations related to our commercial debt facilities. Our derivative financial instruments are recorded on the balance sheet as either an asset

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or a liability measured at fair value. We do not apply hedge accounting to our oil derivative contracts and effective June 1, 2010 discontinued hedge accounting on our interest rate swap contracts and accordingly the changes in the fair value of the instruments are recognized in income in the period of change.

        Estimates of Proved Oil and Natural Gas Reserves.    Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As of December 31, 2010, our net proved reserves totaled 60 Mmboe. As additional proved reserves are found in the future, estimated reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the SEC and the FASB. The accuracy of these reserve estimates is a function of:

•
the engineering and geological interpretation of available data;

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

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

•
the judgments of the persons preparing the estimates.

        Asset Retirement Obligations.    We account for asset retirement obligations as required by the FASB ASC 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long-lived asset with an existing asset retirement obligation is acquired, a liability for that obligation shall be recognized at the asset's acquisition date as if that obligation were incurred on that date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long-lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time as accretion expense in the consolidated statement of operations. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Additionally, asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

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

        Impairment of Long-Lived Assets.    We review our long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. FASB ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to

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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 operations.

Qualitative and Quantitative Disclosures about Market Risk

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

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

	 	Derivative Contracts Assets (Liabilities)	 	
 
	 	Commodities	 	Interest Rates	 	Total	 	
 
	 	(In thousands)
	 	
Fair value of contracts outstanding as of December 31, 2009	 	$	—	 	$	—	 	$	—	 	
Changes in contract fair value	 	 	(28,319	)	 	(11,805	)	 	(40,124	)	
Contract maturities	 	 	—	 	 	6,167	 	 	6,167	 	
 	 	 	 	 	 	 	 	
Fair value of contracts outstanding as of December 31, 2010	 	$	(28,319	)	$	(5,638	)	$	(33,957	)	
 	 	 	 	 	 	 	 	
Commodity Derivative Instruments

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

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

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Commodity Price Sensitivity

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

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

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

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

Interest Rate Sensitivity

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

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

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INDUSTRY

Global Oil and Gas Industry

Location of Kosmos' Assets in Africa and Related Market Accessibility

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

Distribution of Proved Reserves in 1989, 1999 and 2009

        Source: BP Statistical Review.

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Brent Crude

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

West Africa

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

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

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

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

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

Ghana

Country Overview

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

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

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

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

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

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

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Oil and Gas Industry

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

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

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

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

Tano Basin

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

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

Exploration History

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

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

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

Cameroon

Country Overview

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

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

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

Oil and Gas Industry

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

        Kosmos has interests in two blocks in Cameroon, the Ndian River Block in the Rio del Rey Basin, in which it operates with a 100% equity interest and the Perenco operated, Kombe-N'sepe Block located in the Douala Basin, in which Kosmos maintains a 35% interest. These licenses, which together comprise an area covering approximately 1.2 million acres (4,800 square kilometers), represent the equivalent of 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 Company and Total S.A. ("Total"). During 2009, we estimate Cameroon produced approximately

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

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

Douala Basin

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

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

Rio del Rey Basin

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

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

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

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

Exploration History

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

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

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

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

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

Morocco

Country Overview

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

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

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

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

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Oil and Gas Industry

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

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

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

Aaiun Basin

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

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

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

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

Exploration History

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

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BUSINESS

Overview

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

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

Our Competitive Strengths

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

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

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

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

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Well-defined production and growth plan

        Our plan for developing the Jubilee Field provides 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 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 Jubilee Phase I on a faster timeline and allowed us to achieve first oil production at an earlier date than traditional development techniques. See "—Our Strategy—Focus on rapidly developing our discoveries to initial production." In addition to Jubilee, we are currently in the development planning stage for Mahogany East, the pre-development planning stage for the Odum discovery, and the appraisal stage for the Tweneboa, Enyenra and Teak discoveries. We believe these assets provide additional mid-term production and cash flow opportunities to supplement the phased Jubilee Field development.

Significant upside potential from exploratory assets

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

Oil-weighted asset portfolio in key strategic regions

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

New ventures group focused on expanding our 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 the work of our new ventures group, which is tasked with executing a high-impact acquisition program to replicate this success. We believe this will permit timely delivery of further oil and natural gas discoveries for continued long-term reserve and production growth. We aim to leverage our unique exploration approach to maintain our successful track record with these new ventures.

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

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

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

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

Strong financial position

        Since inception we have been backed by our Investors, namely Warburg Pincus and The Blackstone Group, each supporting our initial growth with substantial equity investments. Each Investor will retain a significant interest in Kosmos following this offering. With the proceeds from this offering, our cash on hand and our commercial debt commitments, we believe we will possess the necessary financial strength to implement our business strategy through early 2013. As of December 31, 2010, we had approximately $212 million of total cash on hand, including $112 million of restricted cash, and $205 million of committed undrawn capacity under our 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 received our first oil revenues in early 2011 from the Jubilee Field, and accordingly a portion of these revenues will be used to fund future exploration and development activities.

Our Strategy

        In the near-term, we are focused on maximizing production from the Jubilee Field Phase 1 development, as well as accelerating the development of our other discoveries. Longer term, we are focused on the 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

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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, Enyenra and Teak. Additionally, we plan to drill-out our portfolio of exploration prospects offshore Ghana, which have been partially de-risked by our successful drilling program to date. If successful, these prospects will deliver proved reserve and production growth in the medium term. In the longer term, we plan to drill-out our existing prospect inventory on our other licenses in West Africa and to replicate our exploratory success through new ventures in other regions of the African continent.

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

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

Focus on rapidly developing our discoveries to initial production

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

        The major benefit of a phased approach is that the initial production phase is achieved much earlier. Additionally, a phased approach provides dynamic reservoir performance information that allows the full-field development to be optimized. This approach also maximizes net asset value by refining appraisal and development plans based on experience gained in initial phases 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.

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

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

Identify, access and explore emerging exploratory regions and hydrocarbon plays

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

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.

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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 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 we believe hold approximately 1,700 Mmboe of reserves on a combined basis. The Ceiba and North Block G Complex, discovered between 1998 and 1999, we believe hold approximately 525 Mmboe of reserves. Triton's Malaysia—Thailand Joint Development Area discoveries, initially drilled between 1995 and 1997, we believe hold approximately 950 Mmboe of reserves.

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

        In addition to our current exploration portfolio, Kosmos continuously evaluates new opportunities to grow its portfolio of assets and its inventory of drillable prospects while simultaneously maintaining the high technical standards of our exploration approach. For instance, Kosmos' new venture group reviews the exploration potential of the West and East coast African margins in order to identify

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overlooked and underexplored plays which may be available for direct licensing or acreage opportunities for farm-ins. This involves studying areas adjacent to our current licenses in order to leverage our considerable knowledge base about these petroleum systems, extrapolating new petroleum play systems and concepts along the margins and, based on our exploration approach, identifying new, emerging or under explored petroleum systems. As part of this process, Kosmos has evaluated over 120 new venture opportunities along the West and East African margins and some African interior rift basins. While to date the work of our new venture group has not yet led to the acquisition of any licenses or acreage, we believe such group is essential in order for us to implement our strategy of acquiring additional exploration assets.

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

Our Discoveries and Prospects

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

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

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

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

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

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

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

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(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.

Ghana Well Information

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

	 	Operator	 	Spud Date(1)	 	Total
Depth
(feet)	 	Net
Hydrocarbon
Pay
(feet)	 	Status(2)	 	Comments	
Jubilee	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
J-09 (Mahogany-1)	 	Kosmos	 	05/30/07	 	 	12,553	 	 	321	 	Producing	 	Discovery well for Jubilee in WCTP Block. Drill stem tested at rates in excess of 20,500 bopd. Lower completion installed.	
Hyedua-1	 	Tullow	 	07/27/07	 	 	13,130	 	 	180	 	Plugged Back	 	Downdip confirmation well in DT Block.	
 	J-10 Water Injector ("WI") (Hyedua-1BP1)	 	Tullow	 	07/27/07	 	 	12,631	 	 	136	 	Completion Pending	 	Whole core obtained. Injectivity test conducted at rates in excess of 20,000 bwpd.	
J-16GI Gas Injectors ("GI") (Mahogany-2)	 	Tullow	 	03/06/08	 	 	11,296	 	 	164	 	Injection Ready	 	Updip confirmation well for Jubilee reservoirs. Whole core obtained. Two Drill Stem Tests ("DSTs") conducted.	
J-08 (Hyedua-2)	 	Tullow	 	10/09/08	 	 	12,018	 	 	180	 	Producing	 	Drill stem tested at rates in excess of 16,500 bopd. Whole core obtained.	
J-04	 	Tullow	 	01/17/09	 	 	15,121	 	 	90	 	Plugged Back	 	Tested the Southeastern edge of the Jubilee fairway.	
 	J-04 Sidetrack ("ST")	 	Tullow	 	01/17/09	 	 	13,803	 	 	199	 	Completion Pending	 	Observation well for interference testing.	
J-01	 	Tullow	 	03/18/09	 	 	12,411	 	 	140	 	Producing	 	 	
J-02	 	Tullow	 	03/25/09	 	 	13,829	 	 	186	 	Producing	 	Observation well for interference testing.	
J-11WI	 	Tullow	 	05/06/09	 	 	13,822	 	 	121	 	Completion Pending	 	Down structure water injector—net reservoir 281 feet.	
J-12WI	 	Tullow	 	05/11/09	 	 	14,081	 	 	188	 	Injecting	 	Down structure water injector—net reservoir 319 feet.	
J-15WI	 	Tullow	 	05/14/09	 	 	16,949	 	 	47	 	Completion Pending	 	Only drilled through Upper Mahogany—down structure water injector-net reservoir 87 feet.	
J-07	 	Tullow	 	05/19/09	 	 	13,599	 	 	121	 	Plugged Back	 	Whole core obtained.	
 	J-07ST	 	Tullow	 	05/19/09	 	 	13,701	 	 	116	 	Producing	 	 	
J-03	 	Tullow	 	09/29/09	 	 	12,507	 	 	173	 	Completion Pending	 	Lower completion installed.	
J-05	 	Tullow	 	07/08/09	 	 	13,753	 	 	193	 	Completion Pending	 	Lower completion installed.	
J-17	 	Tullow	 	10/07/09	 	 	19,390	 	 	174	 	Plugged Back	 	Only drilled through Upper Mahogany reservoirs.	
 	J-17STGI	 	Tullow	 	10/07/09	 	 	19,574	 	 	197	 	Completion Pending	 	 	
J-13WI	 	Tullow	 	10/10/09	 	 	13,058	 	 	143	 	Completion Pending	 	Down structure water injector—net reservoir 348 feet.	
J-14WI	 	Tullow	 	10/14/09	 	 	13,999	 	 	77	 	Injecting	 	Down structure water injector—net reservoir 334 feet.	
Mahogany East	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mahogany-3	 	Kosmos	 	11/27/08	 	 	14,262	 	 	108	 	Suspended	 	Discovery well for Mahogany Deep.	
Mahogany-4	 	Kosmos	 	08/28/09	 	 	12,074	 	 	141	 	Suspended	 	Updip confirmation well for the Mahogany East reservoirs.	
Mahogany Deep-2	 	Kosmos	 	09/29/09	 	 	14,193	 	 	49	 	Suspended	 	Drilled to delineate deep reservoirs—net reservoir of 384 feet.	
Mahogany-5	 	Kosmos	 	04/18/10	 	 	13,084	 	 	75	 	Suspended	 	Eastern confirmation of Mahogany East reservoirs.	
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	 	Operator	 	Spud Date(1)	 	Total
Depth
(feet)	 	Net
Hydrocarbon
Pay
(feet)	 	Status(2)	 	Comments	
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.	
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.	
Enyenra-2	 	Tullow	 	01/22/11	 	 	13,887	 	 	121	 	Suspended	 	Downdip confirmation well for Enyenra channels.	
Teak	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Teak-1	 	Kosmos	 	12/21/10	 	 	10,398	 	 	239	 	Suspended	 	Discovery well for Teak.	
Dahoma	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Dahoma-1	 	Kosmos	 	02/04/10	 	 	14,403	 	 	—	 	Abandoned	 	Dry hole.	

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

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

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

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

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

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

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

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

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

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

(3)
We have not yet made a decision as to whether or not to drill our Morocco prospects. We have entered a memorandum of understanding with ONHYM to enter a new license covering the highest potential areas of this block under essentially the same terms as the original license. If we decide to continue into the drilling

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

(5)
The N'gata-1 exploration well was spud in early 2011 and is currently being drilled.

Ghana

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

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

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

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

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

        The primary prospect types consist of well imaged Turonian and Campanian aged submarine fans situated along the steeply dipping shelf margin and trapped in an up dip direction by thinning of the reservoir and/or faults. The WCTP Block partners tested this play concept in June 2007 with the Mahogany-1 well, which discovered over 295 feet (90 meters) of high quality oil pay in a large structural-stratigraphic trap. All subsequent discoveries made have similar trap geometries. In addition, four-way and closures and three-way fault traps are also present within the WCTP Block. These discoveries and prospects are described in more detail below.

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Our Ghanaian Discoveries

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

Jubilee Discovery

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

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

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

Geology

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

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

Subsurface Engineering

        The initial phase of the development focuses on two of the six reservoirs in the Jubilee Field, the prolific UM3 and LM2 reservoirs. Kosmos constructed over 500 detailed geologic models utilizing the subsurface mapping and a range of petrophysical attributes from the exploration, appraisal, and development wells. Numerical simulation was used to evaluate and screen hundreds

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of potential development well plans and operational strategies. Based on these results, the Kosmos-led IPT developed an initial 17 well drainage plan, which consists of nine producing wells six water injection wells and two natural gas injection wells. We expect we will produce approximately 120,000 bopd from these two reservoirs. To validate the subsurface engineering and provide additional confidence in the start-up of the development, a series of interference tests were conducted within the LM2 reservoir. These interference tests significantly reduced uncertainty associated with inter-well communication on a production timescale for the LM2 reservoir, a key uncertainty in the performance of any deepwater field.

Facilities and wells

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

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

Mahogany East Discovery

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

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

Odum Discovery

        Odum is located in the eastern portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of 2,624 to 3,281 feet (800 to 1,000 meters). The

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

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

Teak Discovery

        Teak is located in the western portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 650 to 3,600 feet (200 to 1,100 meters). The field is covered by a 3D seismic survey and is a structural-stratigraphic trap with an element of four-way closure. Seismic data indicates the existence of multiple stacked reservoirs ranging in age from Turonian to Campanian. Teak is located updip and northeast of the Jubilee Field and is located within the same reservoir fairway penetrated by the Jubilee wells. The Teak-1 exploratory well penetrated net pay thickness of approximately 239 feet (73 meters) in five Campanian and Turonian zones of high-quality stacked reservoir sandstones consisting of 154 feet (47 meters) of gas and gas-condensate and (85 feet) 26 meters of oil. Oil samples recovered from the Teak-1 well indicate oil of approximately 40 degrees API gravity in Campanian reservoirs and 32 degrees API gravity in Turonian reservoirs. A follow-up appraisal well, Teak-2, commenced drilling on February 13, 2011.

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

Tweneboa Discovery

        Tweneboa is located in the central portion of the DT Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of 3,281 to 5,252 feet (1,000 to 1,500 meters). The field is a stratigraphic trap with reservoir intervals contained within a series of stacked Upper Cretaceous Turonian-aged, deepwater turbidite fan lobes and channel deposits. The Tweneboa-1, Tweneboa-2, and Tweneboa-3 wells have intersected multiple natural gas, condensate and oil bearing reservoirs in this Turonian turbidite sequence. Oil samples recovered from the Tweneboa-2 well indicate an oil gravity of approximately 31 degrees API, and condensate gravities between 41 and 47 degrees API. The natural gas is considered a "heavy" or "liquids rich" natural gas with condensate ratios ranging between 50 bbl/Mmcf to 100 bbl/Mmcf. We believe Tweneboa is a predominately liquid-rich gas condensate discovery.

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

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Enyenra Discovery (formerly known as Owo)

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

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

Our Ghanaian Prospects

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

Banda Campanian

        Banda Campanian is located in the eastern portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 2,600 to 4,000 feet (800 to 1,200 meters). It is approximately 3.7 miles (6 kilometers) east of the Odum discovery and characterized by a high resolution 3D seismic data survey as a combination structural-stratigraphic trap where a Campanian channel system is defined by a series of listric faults and encased in marine shale. Banda Campanian has similar geologic characteristics to the Odum discovery as detected through amplitude versus offset ("AVO") analysis, however it has been buried more deeply than Odum and this may result in improved fluid characteristics. The target interval is comprised of Upper Cretaceous Campanian aged stacked turbidite sequences interlayered with marine shale. The first well to drill Banda Campanian is anticipated to be spud in the first half of 2011.

Banda Cenomanian

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

Makore

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

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Odum East

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

Sapele

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

Funtum

        Funtum is located in the northern portion of the WCTP Block approximately 22 miles (35 kilometers) offshore Ghana in water depths of approximately 300 to 1,600 feet (100 to 500 meters). It targets an Upper Cretaceous Middle Campanian age confined channel system approximately 1.3 miles (2 kilometers) wide with associated channel margin facies extending the stratigraphic trap to approximately 3.1 miles (5 kilometers) wide. High resolution 3D seismic information indicates the presence of a prospective submarine fan. The first well to drill Funtum is anticipated to be spud in 2012.

Assin

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

Okoro

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

Late Cretaceous WCTP Play

        Four additional Late Cretaceous targets are present on the WCTP Block offshore Ghana in water depths from 600 to 4,300 feet (190 to 1,300 meters). These targets range in age from Cenomanian to Companian. They comprise four-way closures to stratiographic channel traps. If a

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target matures into a prospect, the first well to drill one of these targets is anticipated to be spud post 2012.

Tweneboa Deep

        Tweneboa Deep is located in the southern portion of the DT Block approximately 44 miles (70 kilometers) offshore Ghana in water depths of approximately 4,900 to 5,900 feet (1,500 to 1,800 meters). It comprises a north-south trending Upper Cretaceous Lower Turonian aged turbidite system with an updip thinning and is similar in age to the deeper reservoirs encountered in Mahogany East. The Enyenra-2A well also successfully tested a deeper Turonian fan where 16 feet (5 meters) of gas-condensate bearing sandstones were intersected. These results suggest the existence of hydrocarbons in the Tweneboa Deep prospect. The first well to drill Tweneboa Deep is anticipated to be spud in 2012.

Walnut

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

DT Sapele

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

Wassa

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

Adinkra

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

Oyoko

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

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Ananta

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

Cameroon

Overview

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

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

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

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

Geology

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

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

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

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

Our Cameroon Prospects

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

N'gata

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

N'donga

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

Disangue

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

Pongo Songo

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

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Bonongo

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

Coco East

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

Liwenyi

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

Liwenyi South

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

Meme

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

Bamusso

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

Morocco

        Kosmos is operator and has a 75% working interest in the Boujdour Offshore Block. This block is located within the Aaiun Basin, along the Atlantic passive margin. The block, as covered by the original Boujdour Offshore Petroleum Agreement, comprises an area of more than 10.87 million acres (44,000 square kilometers) (See "Risk Factors—Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and

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thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects."), an area similar in scale to nearly the entire the deepwater fold belt of the U.S. Gulf of Mexico, or approximately 1,900 standard deepwater U.S. Gulf of Mexico blocks. Detailed seismic sequence analysis suggests the existence of stacked deepwater turbidite systems throughout the region. Given the immense scale of the license area, multiple distinct exploration fairways have been identified on this block by Kosmos, each having independent play risks, providing substantial exploration opportunities.

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

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

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

Lower Cretaceous Play Concept

        The main play elements of the prospectivity within the Boujdour Offshore Block consist of a Late Jurassic source rock, charging Early to Mid Cretaceous deepwater sandstones trapped in a number of different structural trends. In the inboard area a number of three-way fault closures are present which contain Early to Mid Cretaceous sandstone sequences some of which have been penetrated in wells on the continental shelf. Outboard of these fault trap trends, large four-way closure and combination structural stratigraphic traps are present in discrete northeast to southwest trending structurally defined fairways.

Our Moroccan Prospects

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

Gargaa

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

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Argane

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

Safsaf

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

Aarar

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

Zitoune

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

Al Arz

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

Felline

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

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Nakhil

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

Barremian Tilted Fault Block Play

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

Our Reserves

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

 
	 	Net Proved Reserves	 	
 
	 	December 31, 2009	 	December 31, 2010	 	
Reserves Category	 	Natural Gas	 	Oil,
Condensate,
NGLs	 	Total	 	Natural Gas(1)	 	Oil,
Condensate,
NGLs	 	Total	 	
 
	 	(Bcf)
	 	(Mmbbl)
	 	(Mmboe)
	 	(Bcf)
	 	(Mmbbl)
	 	(Mmboe)
	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Jubilee Field Phase 1	 	 	—	 	 	55	 	 	55	 	 	23	 	 	56	 	 	60	 	

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

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

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

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

(2)
Standardized Measure represents the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, royalties and additional oil entitlements, discounted using an annual discount rate of 10% to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure often differs from PV-10 because Standardized Measure includes the effect of future income taxes on future net revenues. However, we do not have any income tax expenses related to proved reserves. Therefore, the year-end 2010 estimate of PV-10 is equivalent to the Standardized Measure.

(3)
The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months was $79.35/bbl for Dated Brent at December 31, 2010. The price was adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price expected to be received at the wellhead. Based on sales made to date and marketing surveys, the Jubilee oil is forecasted to ultimately sell for a $0.35/bbl premium relative to Dated Brent. The adjusted price utilized to derive the PV-10 is $79.70/bbl.

Estimated proved reserves

        Unless otherwise specifically identified in this prospectus, the summary data with respect to our estimated proved reserves presented above has been prepared by NSAI, our independent reserve engineering firm, in accordance with the rules and regulations of the SEC applicable to companies

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

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

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

Independent petroleum engineers

        NSAI was established in 1961 and has offices in Dallas and Houston, Texas. Over the past 49 years, NSAI has provided services to the worldwide petroleum industry that include the issuance of reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. NSAI professionals subscribe to a code of professional conduct and NSAI is a Registered Engineering Firm in the State of Texas.

        Our estimated reserves at December 31, 2009 and December 31, 2010 and related future net revenues and PV-10 at December 31, 2010 are taken directly from reports prepared by NSAI, our independent reserve engineers, in accordance with petroleum engineering and evaluation principles which NSAI believes are commonly used in the industry and definitions and current regulations established by the SEC. These reports were prepared at our request to estimate our reserves and related future net revenues and PV-10 for the periods indicated therein. The December 31, 2010 report was completed on March 21, 2011 and the December 31, 2009 report was completed on February 3, 2010. Copies of these reports have been filed as exhibits to the registration statement containing this prospectus. NSAI's reserves report for December 31, 2009 and December 31, 2010 included a detailed review of the Jubilee Field, which contains 100% of our total proved reserves.

        In connection with the December 31, 2009 and December 31, 2010 reserves reports, NSAI prepared its own estimates of our proved reserves. In the process of the reserves evaluation, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. NSAI independently prepared reserves

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estimates to conform to the guidelines of the SEC, including the criteria of "reasonable certainty," as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(2) of Regulation S-X. NSAI issued a report on our proved reserves at December 31, 2009 and December 31, 2010, based upon its evaluation. NSAI's primary economic assumptions in estimates included an ability to sell oil at a price of $79.70/bbl, a certain level of capital expenditures necessary to complete the Jubilee Field Phase 1 development program and the exercise of GNPC's back-in right on the Jubilee Field Phase 1 development. The assumptions, data, methods and precedents were appropriate for the purpose served by these reports, and NSAI used all methods and procedures as it considered necessary under the circumstances to prepare the reports.

Technology used to establish proved reserves

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

        In order to establish reasonable certainty with respect to our estimated proved reserves, NSAI employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, acoustic logs, whole core analysis, sidewall core analysis, downhole pressure and temperature measurements, reservoir fluid samples, geochemical information, geologic maps, seismic data, well test and interference pressure and rate data. Reserves attributable to undeveloped locations were estimated using performance from analogous wells with similar geologic depositional environments, rock quality, and appraisal and development plans to assess the estimated ultimate recoverable reserves as a function of the original oil in place. These qualitative measures are benchmarked and validated against sound petroleum reservoir engineering principles and equations to estimate the ultimate recoverable reserves volume. These techniques include, but are not limited to, nodal analysis, material balance, and numerical flow simulation.

Internal controls over reserves estimation process

        We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Our Reservoir Engineering Managers are primarily responsible for overseeing the preparation of our reserves estimates. Our Reservoir Engineering Managers have over 40 combined years of industry experience between them with positions of increasing responsibility in engineering and evaluations. Each holds a Bachelor of Science degree in petroleum engineering. Eric Hass, our Director of Subsurface, is the primary technical person responsible for overseeing our reserve audits. Mr. Haas received a Bachelor of Science Degree in Petroleum Engineering with honors from The New Mexico Institute of Mining and Technology in 1984 and has worked in the industry for more than twenty-eight years in various engineering and management roles. His experience includes working in the following areas: Algeria, Azerbaijan, Danish North Sea, Egypt, Equatorial Guinea, Gabon, Ghana, Libya, Norway, Russia, the U.K. North Sea, onshore the United States and in the Gulf of Mexico (both on the continental shelf

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and in the deepwater). He spent more than 24 years of his career at a mid-sized NYSE listed E&P corporation. Prior to coming to Kosmos, Mr. Haas spent six years working as a Technical Manager in four different geographic regions. In those roles, he had direct responsibility for the review and approval of internal reserve and resource estimates, interfacing with the corporation's third party reserve auditor and participating on a management team to audit the corporation's reserves on an annual basis.

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

Price history

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

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

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License Areas

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

	 	Developed
Area (Acres)	 	Undeveloped Area (Acres)	 	Total Area (Acres)	 	
 
	 	Gross	 	Net(1)	 	Gross	 	Net(1)	 	Gross	 	Net(1)	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	West Cape Three Points	 	 	11,840	 	 	2,781	 	 	358,077	 	 	110,556	 	 	369,917	 	 	113,338	 	
 	Deepwater Tano(2)	 	 	15,226	 	 	3,577	 	 	258,567	 	 	46,542	 	 	273,793	 	 	50,119	 	
Cameroon	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Kombe-N'sepe	 	 	0	 	 	0	 	 	747,741	 	 	261,709	 	 	747,741	 	 	261,709	 	
 	Ndian River	 	 	0	 	 	0	 	 	434,163	 	 	434,163	 	 	434,163	 	 	434,163	 	
Morocco	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Boujdour Offshore Block(3)	 	 	0	 	 	0	 	 	10,869,672	 	 	8,152,254	 	 	10,869,672	 	 	8,152,254	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	27,066	 	 	6,358	 	 	12,668,220	 	 	9,005,225	 	 	12,695,286	 	 	9,011,583	 	

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

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

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

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Drilling activity

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

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

 
	 	Productive	 	Dry	 	Total	 	Productive	 	Dry	 	Total	 	 

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

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

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

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

        The following table shows the number of wells that are in the process of being drilled or are in active completion stages, and the number of wells suspended or waiting on completion as of March 18, 2011:

	 	Wells in the Process
of Drilling or
in Active Completion	 	Wells Suspended or
Waiting on Completion	 	
 
	 	Exploration	 	Development	 	Exploration	 	Development	 	
 
	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	West Cape Three Points	 	 	1	 	 	0.31	 	 	1	 	 	0.23	 	 	7	 	 	2.16	 	 	4	 	 	0.94	 	
 	Deepwater Tano	 	 	1	 	 	0.18	 	 	—	 	 	—	 	 	6	 	 	1.13	 	 	3	 	 	0.70	 	
Cameroon	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Kombe-N'sepe	 	 	1	 	 	0.35	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
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Undeveloped license area expirations

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

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

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

Domestic Supply Requirements

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

Material Agreements

Exploration Agreements—Ghana

West Cape Three Points ("WCTP") Block

        Effective July 22, 2004, Kosmos Energy Ghana HC ("Kosmos Ghana"), a wholly owned subsidiary, the EO Group and GNPC entered into the WCTP Petroleum Agreement covering the WCTP Block offshore Ghana in the Tano Basin. Kosmos Ghana held an initial 86.5% working interest in the block.

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

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

Deepwater Tano ("DT") Block

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

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

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

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

Jubilee Field Unitization

        The Jubilee Field, discovered by the Mahogany-1 well in June 2007, covers an area within both the WCTP and DT Blocks. Consistent with the Ghanaian Petroleum Law, the WCTP and DT Petroleum Agreements and as required by Ghana's Ministry of Energy, it was agreed the Jubilee Field would be unitized for optimal resource recovery. In late February 2008, the contractors in the WCTP and DT Blocks agreed to an interim unit agreement (the "Pre Unit Agreement"). According to the Pre Unit Agreement, the initial Jubilee Field unit area, which boundary at the time was an approximation of the boundaries of the Jubilee Field, was deemed to consist of 35% of an area from the WCTP Block and 65% of an area from the DT Block. However, the tract participations were allocated 50% for the WCTP Block and 50% for the DT Block pending the results of the Mahogany-2 well. The Mahogany-2 well was announced as an oil discovery on May 5, 2008. Pursuant to the Pre Unit Agreement, the unit boundaries were modified to include the Mahogany-2 well and the tract participations remained 50% for each block.

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

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

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

Atwood Hunter drilling rig

        On June 23, 2008, Kosmos Ghana signed an offshore drilling contract with Alpha Offshore Drilling Services Company, a wholly-owned subsidiary of Atwood Oceanics, Inc., for the semi-submersible rig "Atwood Hunter." Noble Energy EG Ltd., an affiliate of Noble, also is a party to the contract. The contract, as amended, is for 1,152 days, with Kosmos Ghana and Noble allotted 797 days and 355 days, respectively. The initial rig rate is $537,097 per day and is subject to annual adjustments for cost increases. Effective July 27, 2010, the rig rate was $545,622 per day. Kosmos Ghana and Tullow Ghana Limited entered into a rig and services sharing agreement on October 18, 2009, for the use of the Atwood Hunter across the WCTP and DT Blocks during part of Kosmos Ghana's allocated time. In June 2010, the Atwood Hunter completed its first tranche of work for Kosmos Ghana and was assigned in accordance with the contract to Noble. In December 2010, the Atwood Hunter completed its first tranche of work for Noble and was returned to commence its second tranche of work for Kosmos Ghana. As of December 31, 2010, Kosmos has approximately 500 allocated days remaining for use of the Atwood Hunter drilling rig.

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Exploration Agreements—Other

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

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

        On December 19, 2006, Kosmos Energy Cameroon HC signed the Ndian River Production Sharing Contract covering the Ndian River Block located predominately onshore Cameroon. Kosmos has a 100% participating interest in the block and is the operator. SNH will be carried through the exploration and appraisal phases and has the option to back into the contract with an interest of up to

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

Sales and Marketing

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

Competition

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

        We are also affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Over the past three years, oil and natural gas companies have experienced higher drilling

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and operating costs. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill wells and conduct our operations.

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

Title to Property

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

Environmental Matters

General

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

•
require the acquisition of various permits before drilling commences;

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

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

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

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

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

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

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

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

Climate Change

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

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

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

Oil Spill Response

        Kosmos has developed and adopted an Oil Spill Contingency Plan ("OSCP") for the coordination of responses to oil spills arising from its operations in Ghana, including the WCTP Block. In addition, Tullow maintains an OSCP covering the Jubilee Field and DT Block. Under the OSCPs, emergency response teams may be activated to respond to oil spill incidents. We maintain a tiered response system for the mobilization of resources depending on the severity of an incident. Over 100 personnel (composed primarily of Tullow employees and Ghanaian Navy personnel) have been trained on the assembly and operation of Tier 1 and Tier 2 onshore, nearshore and harbor response equipment, and 30 additional personnel (comprised primarily of GNPC employees) and local contractors are expected

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to be trained in April 2011. In the case of a Tier 3 incident, we engage the services of Oil Spill Response Limited ("OSRL") of Southampton, United Kingdom, an oil spill response contractor.

        Our associate membership with OSRL entitles us to utilize its oil spill response services comprising technical expertise and assistance, including access to response equipment and dispersant spraying systems. Kosmos does not own any oil spill response equipment. Instead, Kosmos and Tullow each maintain separate lease agreements with OSRL for Tier 1 and Tier 2 packages of oil spill response equipment. Tier 1 equipment, which is stored in "ready to go trailers" for effective mobilization and rapid deployment, includes booms and ancillaries, recovery systems, pumps and delivery systems, oil storage containers, personal protection equipment, sorbent materials, hand tools, containers and first aid equipment. Tier 2 equipment consists of larger boom and oil recovery systems, pump and delivery systems and auxiliary equipment such as generators and lighting sets, and is also containerized and pre-packed in trailers and ready for quick mobilization.

        As Unit Operator for the Jubilee Field, Tullow has additional response capability to handle an offshore Tier 1 response. Further, our membership in the West and Central Africa Aerial Surveillance and Dispersant Spraying Service gives us access to aircraft for surveillance and spraying of dispersant, which is administered by OSRL for a Tier 2 offshore response. The aircraft is based at the Kotoka International Airport in Accra, Ghana with a contractual response time, fully loaded with dispersant, of six hours. Additional stockpiles of dispersant are maintained in Takoradi.

        In the case of a Tier 3 event, our associate membership in OSRL provides us with access to the large stockpile of equipment in Southampton, United Kingdom along with access to additional dispersant spraying aircraft. Kosmos would hire additional resources such as boats, earth moving equipment and personnel as necessary to respond to such an event.

        Per common industry practice, under the agreements currently in place governing the terms of use of the drilling rigs used by us or our block partners, the drilling rig contractors indemnify us and our block partners in respect of pollution and environmental damage arising out of operations which originate above the surface of the water and from a drilling rig contractor's property, including, but not limited to, their drilling rig and other related equipment. Furthermore, pursuant to the terms of the operating agreements covering the blocks in which we or our block partners are currently drilling, except in certain circumstances, each block partner is responsible for the share of liabilities in proportion to its respective working interest in the block incurred as a result of pollution and environmental damage, containment and clean-up activities, loss or damage to any well, loss of oil or natural gas resulting from a blowout, crater, fire, or uncontrolled well, loss of stored oil and natural gas, and liabilities incurred in connection with plugging or bringing under control any well. Kosmos maintains insurance coverage for an incident concerning a well that results in pollution and environmental damage. The amount of annual insurance coverage maintained is proportional to our interest in a given well; with our current annual well control coverage being $300 million per incident multiplied by our working interest in a well for well control, re-drilling, pollution, clean up and containment, less a deductible of $5 million multiplied by our working interest. In addition we maintain annual third party liability coverage of $300 million multiplied by our working interest in a well for third party liabilities including pollution coverage, environmental damages liabilities and/or claims made by or on behalf of third party individuals in the event of such party's bodily injury or death. For example, if there were a well blowout in the Jubilee Unit (in which we have a 23.4913% working interest) our limit of well control, redrill and pollution clean up and containment coverage would be 23.4913% of $300 million (being $70.4 million) less a deductible of 23.4913% of $5 million (being $1.1 million), and our limit of liability coverage including pollution liability would be 23.4913% of $300 million (being $70.4 million).

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Other Regulation of the Oil and Gas Industry

Ghana

        The Ghanaian Petroleum Law currently governs the upstream Ghanaian oil and natural gas regulatory regime and sets out the policy and framework for industry participants. All petroleum found in its natural state within Ghana is deemed to be national property and is to be developed on behalf of the people of Ghana. GNPC is empowered to carry out exploration and development work either on its own or in partnership with local or foreign partners. Companies who wish to gain rights to explore and produce in Ghana can only do so by entering into a petroleum agreement with Ghana and GNPC. The law requires for the terms of the petroleum agreement to be negotiated and agreed between GNPC and oil and gas companies. The Parliament of Ghana has final approval rights over the negotiated petroleum agreement. Ghana's Ministry of Energy represents the state in its regulatory capacity. GNPC has rights to undertake petroleum operations in any acreage declared open by Ghana's Ministry of Energy and has a carried interest in each petroleum agreement and is typically increased by a certain agreed upon amount at the option of GNPC following the declaration of any commercial discovery. Petroleum agreements are required to include certain domestic supply requirements, including the sale to Ghana of oil for consumption in Ghana at international market prices.

        The Ghanaian Petroleum Law and Ghanaian petroleum agreements contain provisions restricting the direct or indirect assignment of such petroleum agreements without the prior written consent of GNPC and Ghana's Ministry of Energy. The Petroleum Law also imposes certain restrictions on the direct or indirect transfer by a contractor of shares of its incorporated company in Ghana to a third party without the prior written consent of Ghana's Minister of Energy.

        Ghana's Parliament is considering the enactment of a new Petroleum Act and a new Petroleum Revenue Management Act. Industry participant commentary has been sought and submitted and these laws are currently in their draft stages. We currently believe that such laws will only have prospective application, and as such will not modify the terms of or interests under the agreements governing our license interests in Ghana, including the WCTP and DT Petroleum Agreements (which include stabilization clauses) and the UUOA, and will not impose restrictions on the direct or indirect transfer of our license interests, including upon a change of control. See "Risk Factors—Participants in the oil and gas industry are subject to numerous laws that can affect the cost, manner or feasibility of doing business."

Cameroon

        In 1999/2000, the government of Cameroon approved the Petroleum Code (the "Cameroon Petroleum Code") and Petroleum Regulations that were designed to rationalize regulation of the upstream local oil and gas industry. The Cameroon Petroleum Code applies to all license awards granted post 2000, which include thirteen production sharing contracts and three concession contracts. Arrangements entered into prior to 2000 are grandfathered under the former law. Companies who wish to gain rights to explore and produce in Cameroon can only do so by entering into a petroleum contract with Cameroon, represented by SNH, the Cameroon national oil company, and assignments of such contracts require the consent of the government. SNH, established in March 1980, participates in the form of joint ventures with the "contractors."

Morocco

        The two main legislative acts in Morocco relevant to petroleum exploration and production are (i) the Law 21-90 (1 April 1992) as amended and completed by the Law 27-99 (15 February 2000) and (ii) the Decree 2-93-786 (3 November 1993) as amended and completed by decree 2-99-210 (16 March 2000) (together, "Morocco's Petroleum Laws"). The regulatory authority in Morocco is the Ministry of Energy, Mines, Water and Environment and the national oil company acting on his behalf

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is theOffice National des Hydrocarbures et des Mines generally referred to as "ONHYM." ONHYM is a public establishment (établissement public ) with the legal personality and financial autonomy created pursuant to the Law 33-01 (11 November 2003) which was further completed by the Decree 2-04-372 (29 December 2004).

        Pursuant to the Law 21-90, it is provided that the granting of an exploration permit is subject to the conclusion of a petroleum agreement with the Moroccan State. Therefore, companies who wish to gain rights to explore and produce in Morocco can only do so by entering into a petroleum agreement with ONHYM acting on behalf of the State. It is further provided that the State of Morocco (via ONHYM) shall retain a participation in exploration permits or exploitation concessions which shall not be in excess of 25%. More generally, ONHYM is representing the State of Morocco for licensing, exploration and exploitation matters within the limit of its prerogatives set out pursuant to the Law 33-01. Assignments of percentage interests in field developments also require the consent of the administration pursuant to the Law 21-90.

        The SADR has claimed sovereignty over the Western Sahara territory and has issued exploration licenses which conflict with those issued by Morocco, including certain licenses which conflict with the Boujdour Offshore license issued to Kosmos. See "Risk Factors—A portion of our asset portfolio is in Western Sahara, and we could be adversely affected by the political, economic, and military conditions in that region. Our exploration licenses in this region conflict with exploration licenses issued by the Sahrawai Arab Democratic Republic and "Industry—Morocco—Country Overview."

Certain Bermuda Law Considerations

        As a Bermuda exempted company, we are subject to regulation in Bermuda. Among other things, we must comply with the provisions of the Bermuda Companies Act regulating the payment of dividends and making of distributions from contributed surplus. See "Description of Share Capital" and "Dividend Policy."

        We have been designated by the Bermuda Monetary Authority as a non-resident for Bermuda exchange control purposes. This designation allows us to engage in transactions in currencies other than the Bermuda dollar, and there are no restrictions on our ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda or to pay dividends to United States residents who are holders of our common shares.

        Under Bermuda law, "exempted" companies are companies formed for the purpose of conducting business outside Bermuda from a principal place of business in Bermuda. As an exempted company, we may not, without a license or consent granted by the Minister of Finance, participate in certain business transactions, including transactions involving Bermuda landholding rights and the carrying on of business of any kind for which we are not licensed in Bermuda.

Employees

        As of December 31, 2010, we had approximately 130 employees. All employees are currently located in the United States, Ghana, Cameroon or Morocco. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are satisfactory.

Legal Proceedings

        We are not currently party to any material legal proceedings. However, from time to time we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, environmental, safety and health matters. It is not presently

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possible to determine whether any such matters will have a material adverse effect on our consolidated financial position, results of operations, or liquidity.

Corporate Information

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

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

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MANAGEMENT

        The following table sets forth certain information concerning our board of directors, executive officers and key employees:
 	 	 	 	 	 	
Name	 	Age	 	Position	
John R. Kemp III	 	 	65	 	Chairman of the Board of Directors	
Brian F. Maxted	 	 	53	 	Director and Chief Executive Officer	
David I. Foley	 	 	43	 	Director	
Jeffrey A. Harris	 	 	55	 	Director	
David B. Krieger	 	 	37	 	Director	
Prakash A. Melwani	 	 	52	 	Director	
Adebayo ("Bayo") O. Ogunlesi	 	 	57	 	Director	
Chris Tong	 	 	54	 	Director	
Christopher A. Wright	 	 	63	 	Director	
W. Greg Dunlevy	 	 	55	 	Executive Vice President and Chief Financial Officer	
Paul Dailly	 	 	47	 	Senior Vice President, Exploration	
Marvin M. Garrett	 	 	54	 	Senior Vice President, Production and Operations	
William S. Hayes	 	 	56	 	Senior Vice President and General Counsel	
Dennis C. McLaughlin	 	 	59	 	Senior Vice President, Development	
Biographical information

        John R. Kemp III has served as a Director since 2005 and Chairman of our board of directors since January 2011. Mr. Kemp has nearly 15 years of experience in the oil and gas industry's international arena. Mr. Kemp has served on the board of Newfield Exploration Company since 2003. He is currently Chairman of Newfield Exploration's Compensation & Management Development Committee and a member of the Nominating & Corporate Governance Committee. From 1998 to 1999 he served in the role of President of Exploration and Production for the Americas at Conoco (now ConocoPhillips), where he managed the company's upstream operations and led growth efforts in North, South and Central America. Mr. Kemp joined Conoco in 1966 as an Engineer and went on to serve in various key engineering and management positions around the world throughout his career there. Mr. Kemp holds a Bachelor of Science in Petroleum and Natural Gas Engineering from Pennsylvania State University. He was named a Centennial Fellow and Alumni Fellow in 1996 and 1999, respectively, of Pennsylvania State's College of Earth and Mineral Sciences.

        Brian F. Maxted is one of the founding partners of Kosmos and has been our Chief Executive Officer since January 2011. Prior to this he served as our Senior Vice President, Exploration from 2003 to 2008 and our Chief Operating Officer between 2008 and 2011. He has also served as a Director of Broad Oak Energy since February 2008. Prior to co-founding Kosmos in April 2003, Mr. Maxted was the Senior Vice President of Triton where he led a series of discoveries offshore Equatorial Guinea, several of which are currently producing. Mr. Maxted holds a Master of Organic Geochemistry from the University of Newcastle-upon-Tyne and a Bachelor of Science in Geology from the University of Sheffield.

        David I. Foley has served as a Director since 2004. Mr. Foley is a Senior Managing Director in the Private Equity Group at Blackstone and is based in New York. Mr. Foley currently leads Blackstone's investment activities in the energy and natural resource sector. Since joining Blackstone in 1995, Mr. Foley has been responsible for the execution of virtually all of Blackstone's energy and natural resources investments, including: Premcor, Kosmos Energy, Foundation Coal, Texas Genco, Sithe Global Power, American Petroleum Tankers, OSUM, PBF Energy, Meerwind, Moser Baer and Monnet.

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Before joining Blackstone, Mr. Foley worked with AEA Investors in that firm's private equity business, and prior to that served as a consultant for the Monitor Company. Mr. Foley received a Bachelor of Arts and a Masters of Arts in Economics from Northwestern University and received a Master of Business Administration with distinction from Harvard Business School.

        Jeffrey A. Harris has served as a Director since 2005. Mr. Harris is a Managing Director at Warburg Pincus and has been with the firm since 1983. During his career, he has worked extensively in the industrial and technology sectors. Currently, he co-leads the firm's investment activities in the energy sector. Mr. Harris worked in Warburg Pincus' London office from 1991 to 1994 to help develop the firm's European investment activities. He is a director of Competitive Power Ventures Holdings, LLC, ElectroMagnetic GeoServices AS (emgs), Gulf Coast Energy Resources, Inc., Knoll, Inc., Laredo Petroleum, Inc., Osum Oil Sands Corp., Sheridan Production Partners and Spectraseis AG. Mr. Harris served previously on the boards of Bill Barrett Corporation, Comcast UK Cable, Newfield Exploration Company, and Spinnaker Exploration Company. He is past Chairman of the National Venture Capital Association. Currently he is Vice Chairman of the Board of Trustees for the Cranbrook Educational Community, and a member of the Board of Trustees of New York-Presbyterian Hospital. In addition, Mr. Harris is an adjunct professor at the Columbia University Graduate School of Business where he teaches courses on venture capital and innovation. Mr. Harris holds a Bachelor of Science from The Wharton School, University of Pennsylvania and a Master of Business Administration from Harvard Business School.

        David B. Krieger has served as a Director since 2004. Mr. Krieger is a Managing Director of Warburg Pincus and has been with the firm since 2000. Mr. Krieger is involved primarily with the firm's investment activities in the energy sector. Mr. Krieger is currently a Director of MEG Energy Corp. and several private companies. He received a Bachelor of Science in Economics from The Wharton School at the University of Pennsylvania, a Master of Science from the Georgia Institute of Technology, and a Master of Business Administration from Harvard Business School.

        Prakash A. Melwani has served as a Director since 2004. Mr. Melwani is a Senior Managing Director in the Private Equity group at Blackstone. Since joining Blackstone in 2003, Mr. Melwani has led Blackstone's investments in Ariel Re, Foundation Coal Holdings, Inc., Performance Food Group Company, Pinnacle Foods Group Inc., RGIS Inventory Specialists, and Texas Genco Holdings, Inc. Prior to joining Blackstone, Mr. Melwani was a founding partner of Vestar Capital Partners and served as its Chief Investment Officer. Previous to that, he was with the management buyout group at The First Boston Corporation and with N.M. Rothschild & Sons in Hong Kong and London. Mr. Melwani is currently a Director of Ariel Re, Performance Food Group, Pinnacle Foods and RGIS Inventory Specialists. He is also President and a Director of the India Fund and The Asia Tigers Fund. Mr. Melwani graduated with a First Class Honors degree in Economics from Cambridge University. He received a Master of Business Administration with High Distinction from the Harvard Business School and graduated as a Baker Scholar and a Loeb Rhoades Fellow.

        Adebayo ("Bayo") O. Ogunlesi has been a Director since 2004. Mr. Ogunlesi has been Chairman and Managing Partner of Global Infrastructure Partners ("GIP") since 2006, a private equity firm that invests in infrastructure assets in the energy, transport and water sectors, in both OECD and select emerging markets countries. Mr. Ogunlesi previously served as Executive Vice Chairman and Chief Client Officer of Credit Suisse's Investment Banking Division with senior responsibility for Credit Suisse's corporate and sovereign investment banking clients. From 2002 to 2004, he was Head of Credit Suisse's Global Investment Banking Department. Mr. Ogunlesi holds a Bachelor of Arts in Politics, Philosophy and Economics with first class honours from Oxford University, a Juris Doctor (magna cum laude) from Harvard Law School and a Master of Business Administration from Harvard Business School. From 1980 to 1981, he served as a Law Clerk to the Honorable Thurgood Marshall, Associate Justice of the United States Supreme Court.

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        Chris Tong has served as a Director since February 2011. Mr. Tong also serves as a director and Chairman of the Audit Committee of Targa Resources Corp. and Cloud Peak Energy Inc. He served as Senior Vice President and Chief Financial Officer of Noble Energy, Inc. from January 2005 until August 2009. He also served as Senior Vice President and Chief Financial Officer for Magnum Hunter Resources, Inc. from August 1997 until December 2004. Prior thereto, he was Senior Vice President of Finance of Tejas Acadian Holding Company and its subsidiaries, including Tejas Gas Corp., Acadian Gas Corporation and Transok, Inc., all of which were wholly-owned subsidiaries of Tejas Gas Corporation. Mr. Tong held these positions from August 1996 until August 1997, and had served in other treasury positions with Tejas since August 1989. Mr. Tong holds a Bachelor of Arts in Economics from the University of Louisiana Lafayette (formerly the University of Southwestern Louisiana).

        Christopher A. Wright has served as a Director since June 2004. From November 2005 to December 2010, Dr. Wright was the Executive Chairman of Fairfield Energy Limited before being appointed Chief Executive Officer in January 2011. From July 2004 to June 2010, he was a Director of ElectroMagnetic GeoServices AS (emgs). From 2001 to 2004, Dr. Wright was Senior Vice President, Global Exploration and Technology, for Unocal based in Houston. Before joining Unocal, between 1997 and 1999 he was first Director, New Business and then Chief Operating Officer for Lasmo plc in London. Prior to Lasmo plc, from 1996 to 1997 Dr. Wright led the Asia-Pacific and Middle East new business development efforts for the Mobil Oil Corporation, based out of Dallas and London. The major part of his career was with British Petroleum plc where he spent over 20 years in various technical and managerial roles of increasing seniority in locations both in the U.S. and the U.K. His final position with the company was Chief Executive, Frontier and International, which he held from 1991 to 1995. Dr. Wright holds both a Bachelor of Science and a Doctor of Philosophy in Geology from Bristol University and has also completed the Advanced Management Program at Harvard University.

        W. Greg Dunlevy is one of the founding partners of Kosmos and has served as our Executive Vice President and Chief Financial Officer since 2003. Prior to co-founding Kosmos in April 2003, Mr. Dunlevy was the Chief Executive Officer of Moncrief Oil International Incorporated between 2002 and 2003 and was also previously the Senior Vice President, Chief Financial Officer and treasurer of Triton Energy Limited. Mr. Dunlevy has extensive experience and expertise in oil and gas finance, planning, treasury and banking and has worked with major and mid-cap U.S. independents for more than 25 years. Mr. Dunlevy holds a Bachelor of Science from the College of William and Mary and a Masters of Business Administration from Harvard Business School.

        Paul Dailly is one of the founding partners of Kosmos and has served as Senior Vice President, Exploration since 2003. Mr. Dailly worked for British Petroleum plc between 1989 and 1994 and Triton Energy Limited between 1994 and 2001. While at Triton, Mr. Dailly was the geologist and technical team leader responsible for exploration and appraisal of that company's eight oil field discoveries offshore Equatorial Guinea. Mr. Dailly holds a Bachelor of Science (Honors) from Edinburgh University and a Doctor of Philosophy in Geology from the University of Oxford.

        Marvin M. Garrett has served as our Senior Vice President, Production and Operations since 2010, prior to which he served as our Senior Vice President of Operations and Development from January 2006. Before joining Kosmos in January 2006, Mr. Garrett was the Vice President of Operations for Triton where he led the development of the deepwater Ceiba oil field discovery offshore Equatorial Guinea and managed that company's drilling program in Argentina, China, Ecuador, Greece, Guatemala and Italy. Mr. Garrett has nearly three decades of experience managing oil and gas drilling, production and development activities worldwide. Mr. Garrett holds a Bachelor of Science degree in Petroleum Engineering from the University of Louisiana—Lafayette.

        William S. Hayes has served as our General Counsel since 2007. Prior to joining Kosmos, Mr. Hayes was Senior Vice President and General Counsel for Urals Energy PLC in 2007 and Cardinal Resources PLC from 2004 until 2007. Mr. Hayes has worked for or represented public and private, major and independent exploration and production companies in some 30 countries. Mr. Hayes holds a

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Juris Doctor from St. Mary's University School of Law and a Bachelor of Journalism from the University of Texas. He is a member of the State Bar of Texas, the International Bar Association and the Association of International Petroleum Negotiators.

        Dennis C. McLaughlin served as our Senior Vice President, Development since 2010, prior to which he served as our Vice President and Jubilee Project Director since 2008. Prior to joining Kosmos, Mr. McLaughlin worked for BHP Billiton Petroleum from 2000 to 2008 where he led the development of two large oil fields in the Gulf of Mexico. Mr. McLaughlin holds a Bachelor of Science in Mechanical Engineering with honors from Michigan State University.

Board of Directors

Board Composition

        Our bye-laws provide that the board of directors shall consist of not less than five directors and not more than 15 directors, and the number of directors may be changed only by resolution adopted by the affirmative vote of a majority of the entire board of directors. Upon the conclusion of this offering, we will have nine directors: Messrs. Kemp, Maxted, Foley, Harris, Krieger, Melwani, Ogunlesi, Tong and Wright.

        Initially, our board of directors will consist of a single class of directors each serving one year terms. Once the Investors, in the aggregate, no longer beneficially own more than 50% of the issued and outstanding common shares, our board of directors will be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms (other than directors which may be elected by holders of preferred shares, if any).

Director Independence

        We intend to avail ourselves of the "controlled company" exception under the NYSE rules, which exempts us from the requirements that a listed company must have a majority of independent directors on its board of directors and that its compensation and nominating and corporate governance committees be composed entirely of independent directors.

        In any event, our board of directors has reviewed the materiality of any relationship that each of our directors has with us, either directly or indirectly. Based on this review, the board has determined that each of Messrs. Wright, Ogunlesi and Tong is an "independent director" as defined by the NYSE rules and Rule 10A-3 of the Exchange Act.

Committees of the Board of Directors

        We are a "controlled company" as that term is set forth in Section 303A of the NYSE Listed Company Manual because more than 50% of our voting power is held by funds affiliated with our Investors, acting as a group. Under the NYSE rules, a "controlled company" may elect not to comply with certain NYSE corporate governance requirements, including (1) the requirement that a majority of the board of directors consist of independent directors, (2) the requirement that the nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities, (3) the requirement that the compensation committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities and (4) the requirement for an annual performance evaluation of the nominating and corporate governance and compensation committees. After completion of this offering more than 50% of our voting power will continue to be held by the Investors, and we intend to elect to be treated as a controlled company and thus avail ourselves of these exemptions. As a result, although we have adopted charters for our audit, nominating and corporate governance and compensation committees and intend to conduct annual performance evaluations of these committees, our board of directors does not consist of a majority of independent directors nor do our nominating

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and corporate governance and compensation committees consist of independent directors. Accordingly, so long as we are a "controlled company," you will not have the same protections afforded to shareholders of companies that are subject to all of the corporate governance requirements of the NYSE.

        Our board of directors has an audit committee, compensation committee and nominating and governance committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors has the composition and responsibilities described below.

        Audit committee.    The members of our audit committee are Messrs. Foley, Krieger, Ogunlesi and Tong, each of whom our board of directors has determined is financially literate. Mr. Tong is the Chairman of this committee. Our board of directors has determined that Mr. is an audit committee financial expert. We will rely on the phase-in rules of the SEC and NYSE with respect to the independence of our audit committee. These rules permit us to have an audit committee that has one member that is independent upon the effectiveness of the registration statement of which this prospectus forms a part, a majority of members that are independent within 90 days thereafter and all members that are independent within one year thereafter. Our audit committee is authorized to:

•
recommend, through the Board, to the shareholders on their appointment and termination (subject to Bermuda law) of our independent auditors;

•
review the proposed scope and results of the audit;

•
review and pre-approve the independent auditors' audit and non-audit services rendered;

•
approve the audit fees to be paid (subject to authorization by our shareholders to do so);

•
review accounting and financial controls with the independent auditors and our financial and accounting staff;

•
review and approve transactions between us and our directors, officers and affiliates;

•
recognize and prevent prohibited non-audit services;

•
establish procedures for complaints received by us regarding accounting matters;

•
oversee internal audit functions; and

•
prepare the report of the audit committee that SEC rules require to be included in our annual meeting proxy statement.

        Compensation committee.    The members of our compensation committee are Messrs. Harris, Kemp and Melwani. Mr. Melwani is the Chairman of this committee. Our compensation committee is authorized to:

•
review and recommend the compensation arrangements for management, including the compensation for our Chairman and Chief Executive Officer;

•
establish and review general compensation policies with the objective to attract and retain superior talent, to reward individual performance and to achieve our financial goals;

•
administer our equity based incentive plan; and

•
prepare the report of the compensation committee that SEC rules require to be included in our annual meeting proxy statement.

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        Nominating and corporate governance committee.    The members of our nominating and corporate governance committee are Messrs. Harris, Kemp, Melwani and Ogunlesi. Mr. Ogunlesi is the Chairman of this committee. Our nominating and corporate governance committee is authorized to:

•
identify and nominate members for election to the board of directors;

•
develop and recommend to the board of directors a set of corporate governance principles applicable to our company; and

•
oversee the evaluation of the board of directors and management.

Compensation Committee Interlocks and Insider Participation

        No member of our compensation committee has been at any time an employee of ours. None of our executive officers will serve as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving as a member of our board of directors or compensation committee.

        To the extent any members of our compensation committee and affiliates of theirs have participated in transactions with us, a description of those transactions is described in "Certain Relationships and Related Person Transactions."

Code of Business Conduct and Ethics

        Our board of directors has adopted a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Corporate Governance Guidelines

        Our board of directors has adopted corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

Shareholders Agreement

        Prior to the consummation of this offering, we will enter into a shareholders agreement with affiliates of the Investors pursuant to which the Investors, collectively, will have the right to designate four members of our board of directors. Upon the consummation of this offering, each Investor will have the right to designate: (i) two directors (or, if the size of the board is increased, 25% of the board) if it owns 20% or more of the issued and outstanding common shares and 50% or more of the common shares owned by such Investor immediately prior to the consummation of this offering, and (ii) one director (or, if the size of the board is increased, 12.5% of the board) if it owns 7.5% or more of the issued and outstanding common shares. Under the shareholders agreement, subject to the corporate governance requirements of the NYSE, each Investor entitled to designate a director shall have the right to nominate one of its director designees to each committee of the board (other than the audit committee, which will include Investor-designated directors on a transition basis to the extent consistent with the corporate governance requirements of the NYSE).

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Compensation Discussion and Analysis

        This section describes and explains our compensation program for 2010 for our named executive officers, who are listed as follows:

•
James Musselman, who served as our Chief Executive Officer during 2010, and who retired from his employment with Kosmos effective as of December 31, 2010;

•
Brian Maxted, who served as our Chief Operating Officer during 2010 and who became our Chief Executive Officer effective as of January 1, 2011;

•
Greg Dunlevy, Executive Vice President and Chief Financial Officer;

•
William Hayes, Senior Vice President and General Counsel; and

•
Dennis McLaughlin, Senior Vice President, Development.

This section also explains how the compensation that our named executive officers received prior to this offering will be treated in this offering and describes how we expect our compensation program for our named executive officers will change following this offering.

Objectives

        As a private company, our executive compensation program has been designed to meet the following objectives:

•
attract and retain highly talented and experienced executives who may have attractive opportunities with more well-established companies;

•
incentivize these executives to successfully grow our business and prepare us for this offering; and

•
maintain a strong ownership culture and align our executives' interests with those of our Investors by providing a substantial portion of the executives' compensation in the form of long-term equity-based incentives.

        Following this offering, we expect that, although the design of our compensation program will more closely resemble that of other public companies in our industry, the program will continue to be aimed at building long-term shareholder value by attracting, retaining and incentivizing talented, experienced executives.

Elements of Compensation

        To date, we have provided our executive officers with base salaries, annual cash bonuses, long-term equity-based incentive awards and retirement and health and welfare benefits. Following this offering, we expect that these elements will remain the same, although there may be changes in the relative amounts of compensation provided through each element and the design of each element. In particular, the design of our equity-based incentive awards will change, as we will be a public company with common shares rather than a private company with partnership interests.

Base Salary

        Each of our named executive officers receives a base salary that comprises a relatively modest portion of his compensation. In determining our named executive officers' base salaries, we consider factors such as the executive's experience and responsibilities and the salaries paid to our other executives and employees. We review their salaries annually for possible increases. In December 2010, each of our named executives (other than Mr. Musselman, who retired effective December 31, 2010) received a salary increase as follows: Mr. Maxted from $533,000 to $600,000, Mr. Dunlevy from

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$427,000 to $450,000, Mr. Hayes from $337,050 to $350,000 and Mr. McLaughlin from $331,700 to $350,000. For the amounts of base salary that the executives received in 2010, see "Summary Compensation Table—Salary".

Annual Bonus

        Each of our named executive officers is eligible for a discretionary annual cash bonus in an amount determined based on one or more of the following performance factors as related to his responsibilities: financial performance, operating performance, significant strategic initiatives, resolution of unforeseen events and organizational leadership. Although our compensation committee considers the level of achievement of each of these factors, other factors may be considered, and the bonuses are not calculated formulaically. The table below summarizes our named executive officers' achievement of the performance factors for 2010 (other than for Mr. Musselman, who, due to his retirement, was not eligible for a bonus for 2010). For the amounts of the bonuses paid to the executives for 2010, see "Summary Compensation Table—Bonus".

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Executive
	 	Performance Factor
	 	Achievement of Factor
	
Mr. Maxted	 	Significant strategic initiatives	 	•       Pursued consummation of a commercial agreement to sell our Ghanaian assets to ExxonMobil	
 	 	 	 	•       Positioned Kosmos to pursue this offering	
 	 	Resolution of unforeseen events	 	•       Strengthened relationships with U.S. and Ghanaian governmental agencies	
 	 	Organizational leadership	 	•       Managed and expanded business and maintained employee morale during challenging period	
Messrs. Dunlevy and Hayes	 	Financial performance	 	•       Secured increase in project finance commercial bank facilities from $900 million to $1.25 billion to support Kosmos' share of Jubilee Field Phase 1 development expenditure	
 	 	Significant strategic initiatives	 	•       Initiated accelerated public offering and private placement funding processes	
 	 	Resolution of unforeseen events	 	•       Received DOJ letter of declination regarding closure of inquiry into alleged FCPA violations in connection with the WCTP Petroleum Agreement	
 	 	 	 	•       Managed ongoing FCPA review	
 	 	Organizational leadership	 	•       Engaged in ongoing corporate development in support of this offering and business growth	
 	 	 	 	•       Developed and enhanced existing internal controls to ensure compliance with laws applicable to public companies (e.g., Sarbanes-Oxley Act and NYSE listing requirements)	
Mr. McLaughlin	 	Operating performance	 	•       Actual total recordable incident rate and lost time incident rate of 1.38 and 0.46, respectively, substantially exceeded goals of 2.5 and 0.6, respectively	
 	 	Resolution of unforeseen events	 	•       Implemented recovery plans from potential delay-causing events with no material impact on first oil production	
 	 	Organizational leadership	 	•       Integrated project activities with internal functions and external unit operator, achieving seamless transition to production asset	
 	 	 	 	•       Assumed interim team leader role for Mahogany East	
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        Following this offering, we expect that our named executive officers will continue to be eligible for annual cash bonuses on terms to be determined by our compensation committee.

Equity-based incentive awards

        Each of our named executive officers has received grants of partnership profit units in Kosmos Energy Holdings, which are governed by Kosmos Energy Holdings' current operating agreement and individual certificates. The profit units provide the executives with the potential to receive a distribution on a sale of the assets of the partnership and a distribution of the proceeds in liquidation of the partnership. In connection with this offering, the executives' profit units will be converted into common shares and awards on common shares. The grants align our executives' interests with those of our Investors by tying a substantial portion of their compensation to the long-term success of the company.

        The profit units granted to Messrs. Musselman, Dunlevy and Maxted were granted with 20% vested on the grant date and an additional 20% scheduled to vest on each of the first four anniversaries of the grant date. The profit units granted to Messrs. Hayes and McLaughlin are scheduled to vest 50% on each of the second and fourth anniversaries of the grant date. Vesting of the unvested profit units held by Messrs. Dunlevy, Maxted, Hayes and McLaughlin would fully accelerate on termination of their employment due to their death or disability or on a change in control. See "—Potential Payments Upon Termination or Change in Control—Messrs. Maxted, Dunlevy, Hayes and McLaughlin." Mr. Musselman's unvested profit units became fully vested on his retirement effective December 31, 2010. See "—Potential Payments Upon Termination or Change in Control—Mr. Musselman."

        In 2010, we granted profit units to Messrs. Hayes and McLaughlin in light of their outstanding performance and to bring their equity compensation more in line with other executive officers of the company and did not grant profit units to any of our other named executive officers. See "—Summary Compensation Table—Option Awards" and "—Grants of Plan-Based Awards."

        We have adopted an omnibus long-term incentive plan that will become effective on the closing of this offering. The plan will provide for grants of equity-based awards such as share options, restricted shares, restricted share units and share appreciation rights. We believe that this omnibus plan will provide us with significant flexibility as a public company to create equity-based incentives for our executive officers, employees and directors.

Retirement and Health and Welfare Benefits

        Our named executive officers are eligible to participate in our 401(k) savings plan on the same basis as our employees generally. We currently provide a 100% match of the first 6% of eligible compensation deferred by participants under the plan. We do not maintain any pension or nonqualified deferred compensation plans.

        Our named executive officers are eligible for health and welfare benefits on the same basis as our employees generally, including medical and dental coverage and life and disability insurance.

Severance and Change in Control Benefits

        Our named executive officers are not entitled to payments or benefits on termination of their employment or a change in control, other than the accelerated vesting of their unvested profit units on termination due to their death or disability or a change in control, as described above and under "—Potential Payments Upon Termination or Change in Control."

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Compensation Process

        For most of the period since our formation in 2003, our board of directors reviewed the recommendations of the compensation committee and determined our named executive officers' compensation. Following this offering, our compensation committee, in consultation with our Chief Executive Officer as to executives other than himself, will determine the compensation of our named executive officers. See "—Committees of the Board of Directors—Compensation committee."

Summary Compensation Table

        The following table summarizes the compensation of our named executive officers for 2010: our Chief Executive Officer, our Chief Financial Officer and our three other most highly compensated executive officers as determined by their total compensation set forth in the table. Mr. Musselman, who served as our Chief Executive Officer during 2010, retired from his employment with Kosmos effective as of December 31, 2010. Mr. Maxted, who served as our Chief Operating Officer during 2010, became our Chief Executive Officer effective as of January 1, 2011.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Name and
Principal Position	 	Year	 	Salary
($)(1)	 	Bonus
($)	 	Stock
Awards
($)	 	Option
Awards
($)(2)	 	Non-Equity
Incentive Plan
Compensation
($)	 	Change in
Pension
Value and
Non-qualified
Deferred
Compensation
Earnings
($)	 	All Other
Compensation
($)(3)	 	Total
($)	 	
James C. Musselman
Chairman and Chief Executive Officer	 	 	2010	 	 	593,000	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	
W. Greg Dunlevy
Executive Vice President and Chief Financial Officer	 	 	
2010	 	 	
428,917	 	 	
469,700	 	 	
—	 	 	
—	 	 	
—	 	 	
—	 	 	
14,785	 	 	
913,402	 	
Brian F. Maxted
Executive Vice President and Chief Operating Officer	 	 	
2010	 	 	
538,583	 	 	
900,000	 	 	
—	 	 	
—	 	 	
—	 	 	
—	 	 	
85	 	 	
1,438,668	 	
William S. Hayes
Senior Vice President and General Counsel	 	 	
2010	 	 	
338,130	 	 	
337,050	 	 	
—	 	 	
782,550	 	 	
—	 	 	
—	 	 	
26,900	 	 	
1,484,630	 	
Dennis C. McLaughlin
Senior Vice President of Development	 	 	
2010	 	 	
333,225	 	 	
406,700	 	 	
—	 	 	
782,550	 	 	
—	 	 	
—	 	 	
28,247	 	 	
1,550,722	 	

(1)
The amounts in this column are the actual amounts of salary paid to our named executive officers in 2010. Effective December 1, 2010, the annual salary rates of Messrs. Dunlevy, Maxted, Hayes and McLaughlin were increased to the following: Mr. Dunlevy ($450,000), Mr. Maxted ($600,000), Mr. Hayes ($350,000) and Mr. McLaughlin ($350,000).

(2)
The amounts in this column reflect the aggregate grant date fair values of profit units in Kosmos Energy Holdings that were granted to Messrs. Hayes and McLaughlin in 2010. These amounts are calculated in accordance with FASB ASC Topic 718, excluding the effect of estimated forfeitures. For the assumptions made in calculating these amounts, see footnote 18 to the unaudited consolidated financial statements of Kosmos Energy Holdings included in this prospectus. For additional information on these profit units, see "—Grants of Plan-Based Awards".

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(3)
The following items are reported in this column:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Name	 	401(k) Matching
Contributions
($)(4)	 	Vacation
Payments
($)(5)	 	Life
Insurance
($)(6)	 	Retirement
Payments
($)(7)	 	Total
($)	 	
James C. Musselman	 	 	—	 	 	—	 	 	85	 	 	 	 	 	 	 	
W. Greg Dunlevy	 	 	14,700	 	 	—	 	 	85	 	 	—	 	 	14,785	 	
Brian F. Maxted	 	 	—	 	 	—	 	 	85	 	 	—	 	 	85	 	
William S. Hayes	 	 	14,700	 	 	12,115	 	 	85	 	 	—	 	 	26,900	 	
Dennis C. McLaughlin	 	 	14,700	 	 	13,462	 	 	85	 	 	—	 	 	28,247	 	

(4)
Our named executive officers are eligible to participate in our 401(k) savings plan on the same basis as our employees generally. We provide a 100% match of the first 6% of eligible compensation deferred by participants under the plan.

(5)
Payments for accrued unused vacation time. We generally provide our employees, other than our Chief Executive Officer and our Chief Financial Officer, with annual payments for their accrued unused vacation time.

(6)
Employer portion of premiums paid with respect to life insurance for the benefit of our named executive officers on the same basis as our employees generally.

(7)
Includes severance, accelerated vesting of unvested profit units and payment of legal fees provided to Mr. Musselman under his retirement agreement. The value of such accelerated vesting is based on an assumed initial offering price of $      per common share, the midpoint of the estimated public offering price on the cover page of this prospectus. See "—Potential Payments on Termination or Change in Control—Mr. Musselman."

Grants of Plan-Based Awards

        The following table provides information on grants of plan-based awards made to our named executive officers during 2010. The awards were granted in the form of profit units in Kosmos Energy Holdings and will be exchanged into awards on common shares in connection with this offering. The share numbers set forth in the table assume solely for this purpose that this exchange had occurred as of the grant date of these units (based on an assumed initial public offering price of $            per common share, the midpoint of the estimated public offering price range set forth on the cover page of this prospectus).

	 	 

	 	 

	 	 
	 	All Other
Stock
Awards:
Number of
Shares of
Stock or
Units
(#)	 	All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#)	 	 

 
	 	 
	 	Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards	 	Estimated Future Payouts
Under Equity
Incentive Plan Awards	 	 	 	 	 	 
	 	Grant Date
Fair Value of
Stock and
Option
Awards
($)	 	 	 	 	 	 	 	 	

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

(1)
These profit units are scheduled to vest 50% on December 9 of each of 2012 and 2014. See "—Summary Compensation Table—Option Awards".

Outstanding Equity Awards at Fiscal Year End

        The following table provides information on the outstanding equity awards held by our named executive officers as of December 31, 2010. These awards were granted in the form of profit units in Kosmos Energy Holdings and will be exchanged into common shares and awards on common shares in connection with this offering. The amounts set forth in the table assume solely for this purpose that this exchange had occurred as of December 31, 2010 (based on an assumed initial public offering price

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of $            per common share, the midpoint of the estimated public offering price range set forth on the cover page of this prospectus).

	 	 
	 	Option Awards	 	Stock Awards	 	
Name	 	Grant
Date	 	Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable	 	Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable	 	Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexercised
Unearned
Options
(#)	 	Option
Exercise
Price
($)	 	Option
Expiration
Date	 	Number of
Shares or
Units of
Stock
That Have
Not
Vested
(#)(1)	 	Market
Value of
Shares or
Units of
Stock
That Have
Not
Vested
($)	 	Equity
Incentive
Plan
Awards:
Number of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested
(#)	 	Equity
Incentive
Plan
Awards:
Market or
Payout
Value of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested
($)	 	
James C. Musselman	 	6/13/2007	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
W. Greg Dunlevy	 	6/13/2007	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
Brian F. Maxted	 	6/13/2007	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
William S. Hayes	 	10/11/2007	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
 	 	12/10/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
 	 	12/9/2010	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
Dennis C. McLaughlin	 	2/6/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
 	 	12/10/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	
 	 	12/9/2010	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	—	 	 	—	 	

(1)
The profit units granted to Messrs. Musselman, Dunlevy and Maxted were granted 20% vested on the grant date, with an additional 20% scheduled to vest on each of the first four anniversaries of the grant date. The profit units granted to Messrs. Hayes and McLaughlin are scheduled to vest 50% on each of the second and fourth anniversaries of the grant date.

Option Exercises and Stock Vested

        The following table provides information on our named executive officers' equity awards that vested in 2010. These awards were granted in the form of profit units in Kosmos Energy Holdings and will be exchanged into common shares in connection with this offering. The number of shares and value realized in the table assume solely for this purpose that this exchange had occurred as of the vesting date of the interests (based on an assumed initial public offering price of $            per common share, the midpoint of the estimated public offering price on the cover page of this prospectus).

	 	Option Awards	 	Stock Awards	 	
Name	 	Number of Shares
Acquired on Exercise
(#)	 	Value Realized
on Exercise
($)	 	Number of Shares
Acquired on Vesting
(#)	 	Value Realized
on Vesting
($)	 	
James C. Musselman	 	 	—	 	 	—	 	 	 	 	 	 	 	
W. Greg Dunlevy	 	 	—	 	 	—	 	 	 	 	 	 	 	
Brian F. Maxted	 	 	—	 	 	—	 	 	 	 	 	 	 	
William S. Hayes	 	 	—	 	 	—	 	 	 	 	 	 	 	
Dennis C. McLaughlin	 	 	—	 	 	—	 	 	 	 	 	 	 	
Pension Benefits

        We do not maintain any defined benefit pension plans.

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Nonqualified Deferred Compensation

        We do not maintain any nonqualified deferred compensation plans.

Potential Payments Upon Termination or Change in Control

        This section describes and quantifies the payments and benefits that each of Messrs. Dunlevy, Maxted, Hayes and McLaughlin would have received had his employment terminated under specified circumstances or had we undergone a change in control, in each case on December 31, 2010, and the payments and benefits that Mr. Musselman received on his retirement from his employment with Kosmos effective as of December 31, 2010.

Messrs. Dunlevy, Maxted, Hayes and McLaughlin

        Each of Messrs. Dunlevy, Maxted, Hayes and McLaughlin holds profit units in Kosmos Energy Holdings that were unvested as of December 31, 2010 (see "—Outstanding Equity Awards at Fiscal Year End"). Under Kosmos Energy Holdings' current operating agreement, these profit units would have become fully vested on December 31, 2010 if on such date the executives' employment had terminated due to their death or "disability" (as defined below) or had we undergone a "change in control" (as defined below). The estimated aggregate values of these units (based on an assumed initial public offering price of $            per common share, the midpoint of the estimated public offering price on the cover page of this prospectus) are as follows: Mr. Dunlevy ($      ), Mr. Maxted ($      ), Mr. Hayes ($      ) and Mr. McLaughlin ($      ).

        Messrs. Dunlevy, Maxted, Hayes and McLaughlin would not have been entitled to any other payments or benefits had their employment terminated due to their death or disability or had we undergone a change in control on December 31, 2010. In addition, the executives would not have been entitled to any payments or benefits of any kind had their employment terminated on December 31, 2010 for any reason other than due to their death or disability.

        "Disability" generally means the executive's incapacitation by accident, sickness or other circumstance that renders him mentally or physically incapable of performing his duties on a full-time basis for at least 180 days during any 12 month period.

        "Change in control" generally means:

•
a consolidation, conversion or merger involving Kosmos Energy Holdings in which the owners of the equity interests in Kosmos Energy Holdings immediately prior to such transaction do not, immediately after such transaction, own equity securities representing a majority of the outstanding voting power of the surviving entity; or

•
the sale, lease or transfer of all or substantially all of the assets of Kosmos Energy Holdings;

in either case, other than any such transaction that is approved by the holders of specified equity interests in Kosmos Energy Holdings.

Mr. Musselman

        On December 17, 2010, we entered into a retirement agreement with our then chief executive officer Mr. Musselman, which sets forth the terms of his retirement from his employment with Kosmos effective as of December 31, 2010. Pursuant to the retirement agreement, in consideration of Mr. Musselman's release of claims against us and our affiliates and his agreement to the restrictions described below, we provided him with the following payments and benefits:

•
Severance in an aggregate amount equal to his annual base salary of $593,000, paid in monthly installments through December 31, 2011. However, these payments will cease on the completion

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of the lock-up period under agreements to be entered with the underwriters of this offering (but in no event earlier than March 31, 2011);•
1,176,961 profit units in Kosmos Energy Holdings that were unvested as of his retirement date became fully vested as of such date. The estimated aggregate value of such interests is $            (based on an assumed initial public offering price of $            per common share, the midpoint of the estimated public offering price on the cover page of this prospectus);

•
We paid his legal fees of $92,500 in connection with the negotiation of the retirement agreement;

•
We agreed not to exercise our right to repurchase his units in Kosmos Energy Holdings or to cause his units to be forfeited; and

•
We agreed to waive our right of first refusal under his employment agreement with respect to business opportunities referenced in the agreement and that the restrictions on competition and solicitation in the agreement would not apply to him after his retirement.

        In connection with this offering, all of Mr. Musselman's equity interests in Kosmos Energy Holdings (including those held in a family limited partnerhip), will be exchanged into common shares of Kosmos Energy Ltd. on the same basis as other equity holders, and such shares will be subject to the same restrictions on transfer as apply to our officers and directors and certain of our shareholders (see "Underwriting"). We also agreed that, after the expiration of these restrictions, he will not be subject to any future transfer restrictions or entitled to any registration rights with respect to his shares.

Director Compensation

        The following table lists the individuals who served as our non-employee directors in 2010 and summarizes their 2010 compensation. Neither our Investor directors nor our executive directors received compensation for their service as directors in 2010. Mr. Kemp, who served as a director in 2010, became Chairman effective January 1, 2011.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Name	 	Fees Earned or
Paid in Cash
($)(1)	 	Stock
Awards
($)	 	Option
Awards
($)(2)	 	Non-Equity
Incentive Plan
Compensation
($)	 	Change in Pension
Value and
Nonqualified
Deferred
Compensation
Earnings
($)	 	All Other
Compensation
($)	 	Total
($)	 	
John R. Kemp III	 	 	147,097	 	 	—	 	 	31,302	 	 	—	 	 	—	 	 	1,501	 	 	179,900	 	
David I. Foley	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
Jeffrey A. Harris	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
David B. Krieger	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
Prakash A. Melwani	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
Adebayo O. Ogunlesi	 	 	40,000	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	40,000	 	
Christopher A. Wright	 	 	40,000	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	40,000	 	

(1)
The amounts in this column reflect the annual cash retainer that was paid quarterly to each of Messrs. Kemp, Ogunlesi and Wright for his service as a director in 2010. Effective January 1, 2011, these retainers were increased to $50,000. For Mr. Kemp, the amount in this column also reflects a monthly fee of $40,000 provided under his consulting agreement for the period from October 11, 2010 through December 31, 2010 in anticipation of his becoming Chairman effective January 1, 2011.

(2)
The amount in this column reflects the aggregate grant date fair value of the profit units in Kosmos Energy Holdings granted to Mr. Kemp on November 17, 2010 under his consulting agreement in anticipation of his becoming Chairman effective January 1, 2011. This amount is calculated in accordance with FASB ASC Topic 718, excluding the effect of estimated forfeitures. For the assumptions made in calculating this amount, see footnote 17 to the unaudited consolidated financial statements of Kosmos Energy Holdings included in this prospectus.

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Consulting Agreement with Mr. Kemp

        Effective October 11, 2010, we entered into a consulting agreement with Mr. Kemp pursuant to which he receives compensation for services as our Chairman and such other non-director services as we may reasonably request from time to time. Under the agreement, we provide Mr. Kemp with a monthly fee of $40,000. In addition, beginning April 11, 2011, Mr. Kemp will receive profit units in Kosmos Energy Holdings (issued at three-month intervals) with values determined by our compensation committee. In connection with this offering, these profit units will be exchanged into common shares. The consulting agreement also provides that we will reimburse Mr. Kemp for his reasonable expenses incurred in connection with his providing the services under the agreement, including travel expenses incurred by him and travel expenses incurred by his wife for travelling from Houston to Dallas to accompany him in the performance of his services.

        Either we or Mr. Kemp may terminate the consulting agreement on 30 days' prior written notice. In addition, either we or he may request at any time that the monthly fee and the grants of profit units cease to be provided to him. The agreement contains a customary covenant restricting Mr. Kemp from disclosing our confidential information.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

        The following is a description of the transactions we have engaged in since January 1, 2010 with our directors and officers and beneficial owners of more than five percent of our voting securities and their affiliates.

        The operating agreement governing our predecessor, Kosmos Energy Holdings, was initially entered into on March 9, 2004 and amended on each of February 20, 2005, June 13, 2007, September 18, 2007, June 18, 2008, December 18, 2008, October 9, 2009 and December 16, 2010 (as amended and restated, the "OA"), among our Investors and certain members of our management and employees. Pursuant to the OA and related contribution agreements, such Investors, members of our management and employees purchased Series A, B and C Convertible Preferred Units and were issued C1 Common Units since our inception. None of these units were purchased in the fiscal year ended December 31, 2010. Additionally, the OA contemplated the issuance of management and profit units as compensation for members of our management and our employees. See "Management." The OA also provided that the holders of the Series A, B and C Convertible Preferred Units receive distributions, if any, equal to the "Accreted Value" of the units, prior to any distributions to the common unit holders. The accumulated preferred return amounts for the Convertible Preferred Units totaled approximately $153.5 million at December 31, 2010. In addition, as a result of the issuance of Series C Convertible Preferred Units and the associated C1 Common Units, a discount existed on the Series C Convertible Preferred Units of approximately $11.8 million. The accumulated preferred return on the Convertible Preferred Units and the discount on the Series C Convertible Preferred Units has been recorded as of December 31, 2010 the date at which a determination was made that it was probable that an exchange of securities for common shares would occur.

        Pursuant to the terms of the corporate reorganization that will occur prior to or concurrently with the closing of the offering described in this prospectus, all of the interests in Kosmos Energy Holdings will be exchanged for common shares of Kosmos Energy Ltd., and the OA will be amended to remove the various classes of units, the rights of our Investors and management to appoint directors to the board of Kosmos Energy Holdings and the rights of Kosmos Energy Holdings to make any additional capital calls. See "Corporate Reorganization." We have agreed to reimburse our Investors for their fees and expenses incurred in connection with this offering and the related corporate reorganization.

        Prior to the closing of this offering we will adopt a set of related party transaction policies designed to minimize potential conflicts of interest arising from any dealings we may have with our affiliates and to provide appropriate procedures for the disclosure, approval and resolution of any real or potential conflicts of interest which may exist from time to time. Such policies will provide, among other things, that all related party transactions, including any loans between us, our principal shareholders and our affiliates, will be approved by our nominating and corporate governance committee of the board of directors, after considering all relevant facts and circumstances, including without limitation the commercial reasonableness of the terms, the benefit and perceived benefit, or lack thereof, to us, opportunity costs of alternative transactions, the materiality and character of the related party's direct or indirect interest, and the actual or apparent conflict of interest of the related party, and after determining that the transaction is in, or not inconsistent with, our and our shareholders' best interests.

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PRINCIPAL SHAREHOLDERS

        The following table sets forth certain information with respect to the beneficial ownership of our common shares, on a fully-diluted basis, as of December 31, 2010, and after giving effect to our corporate reorganization, for:

•
each of our current executive officers;

•
each of our current directors;

•
all our current executive officers and directors as a group; and

•
each shareholder known by us to be the beneficial owner of more than 5% of our issued and outstanding common shares.

        Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Common shares that may be acquired by an individual or group within 60 days of December 31, 2010, pursuant to the exercise of options or warrants, are deemed to be outstanding for the purpose of computing the percentage ownership of such individual or group, but are not deemed to be outstanding for the purpose of computing the percentage ownership of any other person shown in the table. Percentage of ownership is based on                    common shares issued and outstanding on December 31, 2010, after giving effect to our corporate reorganization, plus                    common shares that we are selling in this offering. The underwriters have an option to purchase up to                    additional common shares from us to cover over-allotments.

        Except as indicated in footnotes to this table, we believe that the shareholders named in this table have sole voting and investment power with respect to all common shares shown to be beneficially owned by them, based on information provided to us by such shareholders. Unless otherwise indicated, the address for each director and executive officer listed is: 8176 Park Lane, Suite 500, Dallas, Texas, 75231.

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	 	Percentage of Shares
Beneficially Owned(1)(2)	
Name and Address of Beneficial Owner	 	Number of Shares
Beneficially
Owned(1)	 	Before the Offering	 	After the Offering	
Directors and Executive Officers	 	 	 	 	 	 	
John R. Kemp III	 	 	 	 	 	 	
David I. Foley(5)	 	 	 	 	 	 	
Jeffrey A. Harris(3)	 	 	 	 	 	 	
David Krieger(3)	 	 	 	 	 	 	
Prakash A. Melwani(5)	 	 	 	 	 	 	
Adebayo O. Ogunlesi	 	 	 	 	 	 	
Chris Tong	 	 	 	 	 	 	
Christopher A. Wright	 	 	 	 	 	 	
Brian F. Maxted	 	 	 	 	 	 	
W. Greg Dunlevy	 	 	 	 	 	 	
Paul Dailly	 	 	 	 	 	 	
Marvin M. Garrett	 	 	 	 	 	 	
William S. Hayes	 	 	 	 	 	 	
Dennis C. McLaughlin	 	 	 	 	 	 	
All directors and executive officers as a group (14 individuals)	 	 	 	 	 	 	
Five Percent Shareholders	 	 	 	 	 	 	
Warburg Pincus International Partners, L.P.(4)	 	 	 	 	 	 	
Warburg Pincus Private Equity VIII, L.P.(4)	 	 	 	 	 	 	
Blackstone Funds(5)	 	 	 	 	 	 	

(1)
Assumes the completion of our corporate reorganization prior to or concurrently with the closing of this offering. See "Corporate Reorganization."

(2)
Assumes no exercise of the underwriters' option to purchase additional shares. The number of shares held by our principal shareholders will depend on the initial public offering price of a common share and the date upon which this offering is completed.

(3)
Messrs. Harris and Krieger, directors of the Company, are Partners of Warburg Pincus & Co. ("WP"), a New York general partnership, and Managing Directors and Members of Warburg Pincus LLC ("WPLLC"), a New York limited liability company. All shares indicated as owned by Messrs. Harris and Krieger are included because of their affiliation with the Warburg Pincus entities. Messrs. Harris and Krieger disclaim beneficial ownership of all shares owned by the Warburg Pincus entities. Charles R. Kaye and Joseph P. Landy are Managing General Partners of WP and Managing Members and Co-Presidents of WP LLC and may be deemed to control the Warburg Pincus entities. Messrs. Kaye and Landy disclaim beneficial ownership of all shares held by the Warburg Pincus entities. The address of Messrs. Harris, Krieger, Kaye and Landy, WP, WP LLC and the other Warburg Pincus entities listed in this footnote is 450 Lexington Avenue, New York, New York 10017.

(4)
The shareholders are Warburg Pincus International Partners, L.P., and two affiliated partnership ("WPIP") and Warburg Pincus Private Equity VIII, L.P., and two affiliated partnerships ("WP VIII"). Warburg Pincus Partners LLC ("WP Partners"), a New York limited liability company, a direct subsidiary of Warburg Pincus & Co. ("WP"), is the sole general partner of WPIP and WP VIII. WP is the managing member of WP Partners. WPIP and WP VIII are managed by Warburg Pincus LLC ("WP LLC"). The address of the Warburg Pincus entities is 450 Lexington Avenue, New York, New York 10017.

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(5)
The Blackstone Funds (as hereinafter defined) are comprised of the following entities: Blackstone Capital Partners (Cayman) IV L.P. ("BCP IV"), Blackstone Capital Partners (Cayman) IV-A L.P. ("BCP IV-A"), Blackstone Family Investment Partnership (Cayman) IV-A L.P ("Family"), Blackstone Participation Partnership (Cayman) IV L.P. ("Participation") and Blackstone Family Investment Partnership (Cayman) IV-A SMD L.P. ("Family SMD", and together with BCP IV, BCP IV-A, Family and Participation, the "Blackstone Funds"). The Blackstone Funds beneficially own (i)             shares, which are held by BCP IV, (ii)             shares, which are held by BCP IV-A, (iii)             shares, which are held by Family, (iv)             shares, which are held by Participation, and (v)             shares, which are held by Family SMD. Blackstone Management Associates (Cayman) IV L.P. ("BMA") is a general partner of each of BCP IV and BCP IV-A. Blackstone LR Associates (Cayman) IV Ltd. ("BLRA") and BCP IV GP L.L.C. are general partners of each of BMA, Family and Participation. Blackstone Holdings III L.P. is the sole member of BCP IV GP L.L.C. and a shareholder of BLRA. Blackstone Holdings III L.P. is indirectly controlled by The Blackstone Group L.P. and is owned, directly or indirectly, by Blackstone professionals and The Blackstone Group L.P. The Blackstone Group L.P. is controlled by its general partner, Blackstone Group Management L.L.C., which is in turn, wholly owned by Blackstone's senior managing directors and controlled by its founder, Stephen A. Schwarzman. In addition, Mr. Schwarzman is a director and controlling person of BLRA. Family SMD is controlled by its general partner, Blackstone Family GP L.L.C., which is in turn wholly owned by Blackstone's senior managing directors and controlled by its founder, Mr. Schwarzman. Each of such Blackstone entities and Mr. Schwarzman may be deemed to beneficially own the shares beneficially owned by the Blackstone Funds directly or indirectly controlled by it or him, but each disclaims beneficial ownership of such shares except to the extent of its or his indirect pecuniary interest therein. Mr. Foley and Mr. Melwani are senior managing directors of Blackstone Group Management L.L.C. and neither is deemed to beneficially own the shares beneficially owned by the Blackstone Funds. The address of each of the Blackstone Funds, BMA and BLRA is c/o Walkers Corporate Services Limited, 87 Mary Street, George Town, Grand Cayman KY1-9005, Cayman Islands and the address for Mr. Schwarzman and each of the other entities listed in this footnote is c/o The Blackstone Group, L.P., 345 Park Avenue, New York, New York 10154.

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DESCRIPTION OF SHARE CAPITAL

        The following description of certain provisions of our memorandum of association and bye-laws does not purport to be complete and is subject to, and qualified by reference to, all of the provisions of our memorandum of association and bye-laws.

General

        We are an exempted company organized under the Bermuda Companies Act. The rights of our shareholders will be governed by Bermuda law and our memorandum of association and bye-laws. The Bermuda Companies Act differs in some material respects from laws generally applicable to Delaware corporations, which differences have been highlighted in the discussion below.

Share Capital

        Our authorized share capital consists of common shares, par value $0.01 per share, and preference shares, par value $0.01 per share. Upon completion of this offering, there will be common shares and no preference shares issued and outstanding. All of our issued and outstanding common shares will be fully paid and non-assessable.

        Pursuant to our bye-laws, subject to the requirements of the New York Stock Exchange, our board of directors is authorized to issue any of our authorized but unissued shares.

Common Shares

        Holders of common shares are entitled to one vote per share on all matters submitted to a vote of holders of common shares. Subject to preferences that may be applicable to any issued and outstanding preference shares, holders of common shares are entitled to receive such dividends, if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. Holders of common shares have no redemption, sinking fund, conversion, exchange, pre-emption or other subscription rights. In the event of our liquidation, dissolution or winding up, the holders of common shares are entitled to share equally and ratably in our assets, if any, remaining after the payment of all of our debts and liabilities, subject to any liquidation preference on any outstanding preference shares.

Preference Shares

        Pursuant to Bermuda law and our bye-laws, our board of directors is authorized to provide for the issuance of one or more series of preference shares having such number of shares, designations, dividend rates, voting rights, conversion or exchange rights, redemption rights, liquidation rights and other powers, preferences and rights as may be determined by the board without any further shareholder approval. Preference shares, if issued, would have priority over common shares with respect to dividends and other distributions, including the distribution of our assets upon liquidation. Although we have no present plans to issue any preference shares, the issuance of preference shares could decrease the amount of earnings and assets available for distribution to the holders of common shares, could adversely affect the rights and powers, including voting rights, of common shares and could have the effect of delaying, deterring or preventing a change in control of us or an unsolicited acquisition proposal.

Board Composition

        Our bye-laws provides that our board of directors will determine the size of the board, provided that it shall be at least five and no more than 15. Our board of directors will initially consist of nine directors.

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        Pursuant to a shareholders agreement entered into by us and affiliates of the Investors, each Investor shall have the right to designate two nominees (or if the size of the board of directors is increased, 25% of the board, rounded to the nearest whole number) if it owns (A) 20% or more of the issued and outstanding common shares and (B) 50% or more of the common shares owned by such Investor immediately prior to this offering and one nominee (or if the size of the board of directors is increased, 12.5% of the board, rounded to the nearest whole number) if it owns 7.5% or more of the issued and outstanding common shares. See "Management—Board of Directors—Board Composition."

Election and Removal of Directors

        Our bye-laws provide that, prior to the first date on which the Investors no longer beneficially own more than 50% of the issued and outstanding shares entitled to vote, all directors will be up for election each year at our annual general meeting of shareholders. On or after such date, our board of directors will be a classified board divided into 3 classes, with one class coming up for election each year. The election of our directors will be determined by a plurality of the votes cast at the general meeting of shareholders at which the relevant directors are to be elected. Our shareholders do not have cumulative voting rights and accordingly the holders of a plurality of the shares voted can elect all of the directors then standing for election. Our bye-laws require advance notice for shareholders to nominate a director or present proposals for shareholder action at an annual general meeting of shareholders. See "—Meetings of Shareholders."

        Under our bye-laws, prior to the first date on which the Investors no longer beneficially own more than 50% of the issued and outstanding shares entitled to vote, directors may be removed with or without cause by the affirmative vote of a majority of the issued and outstanding shares entitled to vote. On and after such date, a director may be removed only for cause by the affirmative vote of a majority of the issued and outstanding shares entitled to vote. Any vacancy created by the removal of a director at a special general meeting may be filled at that meeting by the election of another director in his or her place or, in the absence of any such election, by the board of directors. Any other vacancy, including newly created directorships, may be filled by our board of directors.

Proceedings of Board of Directors

        Our bye-laws provide that our business shall be managed by or under the direction of our board of directors. Our board of directors may act by the affirmative vote of a majority of the directors present at a meeting at which a quorum is present. A majority of the total number of directors then in office shall constitute a quorum; provided that if at least one director designated by each Investor then entitled to designate a director is not present at a meeting, such meeting will be postponed for up to 48 hours, after which it may be held as long as a quorum consisting of a majority of the total number of directors is present. The board may also act by unanimous written consent.

Duties of Directors

        Under Bermuda common law, members of a board of directors owe a fiduciary duty to the company to act in good faith in their dealings with or on behalf of the company, and to exercise their powers and fulfill the duties of their office honestly. This duty has the following essential elements: (1) a duty to act in good faith in the best interests of the company; (2) a duty not to make a personal profit from opportunities that arise from the office of director; (3) a duty to avoid conflicts of interest; and (4) a duty to exercise powers for the purpose for which such powers were intended. The Bermuda Companies Act also imposes a duty on directors of a Bermuda company, to act honestly and in good faith, with a view to the best interests of the company, and to exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. In addition, the Bermuda Companies Act imposes various duties on directors with respect to certain matters of management and administration of the company.

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        The Bermuda Companies Act provides that in any proceedings for negligence, default, breach of duty or breach of trust against any director, if it appears to a court that such officer is or may be liable in respect of the negligence, default, breach of duty or breach of trust, but that he has acted honestly and reasonably, and that, having regard to all the circumstances of the case, including those connected with his appointment, he ought fairly to be excused for the negligence, default, breach of duty or breach of trust, that court may relieve him, either wholly or partly, from any liability on such terms as the court may think fit. This provision has been interpreted to apply only to actions brought by or on behalf of the company against the directors.

        Under Delaware law, the business and affairs of a corporation are managed by or under the direction of its board of directors. In exercising their powers, directors are charged with a duty of care and a duty of loyalty. The duty of care requires that directors act in an informed and deliberate manner and to inform themselves, prior to making a business decision, of all relevant material information reasonably available to them. The duty of care also requires that directors exercise care in overseeing the conduct of corporate employees. The duty of loyalty is the duty to act in good faith, not out of self-interest, and in a manner which the director reasonably believes to be in the best interests of the shareholders. A party challenging the propriety of a decision of a board of directors bears the burden of rebutting the presumptions afforded to directors by the "business judgment rule." If the presumption is not rebutted, the business judgment rule attaches to protect the directors and their decisions. Where, however, the presumption is rebutted, the directors bear the burden of demonstrating the fairness of the relevant transaction. Notwithstanding the foregoing, Delaware courts subject directors' conduct to enhanced scrutiny in respect of defensive actions taken in response to a threat to corporate control and approval of a transaction resulting in a sale of control of the corporation.

Interested Directors

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

Indemnification of Directors and Officers

        Bermuda law provides generally that a Bermuda company may indemnify its directors and officers against any loss arising from or liability which by virtue of any rule of law would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust except in cases where such liability arises from fraud or dishonesty of which such director or officer may be guilty in relation to the company.

        Our bye-laws provide that we shall indemnify our officers and directors in respect of their actions and omissions, except in respect of their fraud or dishonesty, and that we shall advance funds to our officers and directors for expenses incurred in their defense upon receipt of an undertaking to repay the funds if any allegation of fraud or dishonesty is proved. Our bye-laws provide that the company and the shareholders waive all claims or rights of action that they might have, individually or in right of the

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company, against any of the company's directors or officers for any act or failure to act in the performance of such director's or officer's duties, except in respect of any fraud or dishonesty.

Meetings of Shareholders

        Under Bermuda law, a company is required to convene at least one general meeting of shareholders each calendar year. Under Bermuda law and our bye-laws, a special general meeting of shareholders may be called by the board of directors or the chairman and must be called upon the request of shareholders holding not less than 10% of the paid-up capital of the company carrying the right to vote at general meetings of shareholders.

        Unless otherwise provided in our bye-laws, at any general meeting of shareholders the presence in person or by proxy of shareholders representing a majority of the issued and outstanding shares entitled to vote shall constitute a quorum for the transaction of business. Unless otherwise required by law or our bye-laws, shareholder action requires the affirmative vote of a majority of the issued and outstanding shares voting at a meeting at which a quorum is present.

Shareholder Proposals

        Under Bermuda law, shareholders holding at least 5% of the total voting rights of all the shareholders having at the date of the requisition a right to vote at the meeting to which the requisition relates or any group comprised of at least 100 or more shareholders may require a proposal to be submitted to an annual general meeting of shareholders. Under our bye-laws, any shareholders wishing to nominate a person for election as a director or propose business to be transacted at a meeting of shareholders must provide advance notice.

Shareholder Action by Written Consent

        Our bye-laws will provide that, until the first date on which the Investors no longer beneficially own more than 50% of the issued and outstanding shares entitled to vote, shareholders can act by written consent. Thereafter, shareholders can only act at a meeting of shareholders.

Amendment of Memorandum of Association and Bye-laws

        Our memorandum of association and bye-laws provide that our memorandum of association and bye-laws may not be rescinded, altered or amended except with the approval of our board of directors and shareholders owning a majority of the issued and outstanding shares entitled to vote.

Business Combinations

        A Bermuda company may engage in a business combination pursuant to a tender offer, amalgamation or sale of assets.

        The amalgamation of a Bermuda company with another company requires the amalgamation agreement to be approved by the company's board of directors and by its shareholders. Unless the company's bye-laws provide otherwise, the approval of 75% of the shareholders voting at a meeting is required to approve the amalgamation agreement, and the quorum for such meeting must be two persons holding or representing more than one-third of the issued shares of the company. Our bye-laws provide that an amalgamation must be approved by our board of directors and by shareholders owning a majority of the issued and outstanding shares entitled to vote. Shareholders who did not vote in favor of the amalgamation may apply to court for an appraisal within one month of notice of the shareholders meeting.

        Under the Bermuda Companies Act, we are not required to seek the approval of our shareholders for the sale of all or substantially all of our assets. However, our bye-laws provide that any sale, lease

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or exchange by us of all or substantially all of our assets will require the approval of our board of directors and of shareholders owning a majority of the outstanding shares entitled to vote.

        Under Bermuda law, where an offer is made for shares of a company and, within four months of the offer, the holders of not less than 90% of the shares not owned by the offeror, its subsidiaries or their nominees accept such offer, the offeror may by notice require the non-tendering shareholders to transfer their shares on the terms of the offer. Dissenting shareholders do not have express appraisal rights but are entitled to seek relief (within one month of the compulsory acquisition notice) from the court, which has power to make such orders as it thinks fit. Additionally, where one or more parties hold not less than 95% of the shares of a company, such parties may, pursuant to a notice given to the remaining shareholders, acquire the shares of such remaining shareholders. Dissenting shareholders have a right to apply to the court for appraisal of the value of their shares within one month of the compulsory acquisition notice. If a dissenting shareholder is successful in obtaining a higher valuation, that valuation must be paid to all shareholders being squeezed out.

Dividends and Repurchase of Shares

        Pursuant to our bye-laws, our board of directors has the authority to declare dividends and authorize the repurchase of shares subject to applicable law.

        Under Bermuda law, a company may not declare or pay a dividend if there are reasonable grounds for believing that the company is, or would after the payment be, unable to pay its liabilities as they become due or the realizable value of its assets would thereby be less than the aggregate of its liabilities and its issued share capital and its share premium accounts. Issued share capital is the aggregate par value of the company's issued and outstanding shares, and the share premium account is the aggregate amount paid for issued and outstanding shares over and above their par value. Share premium accounts may be reduced in certain limited circumstances. Under Bermuda law, a company cannot purchase its own shares if there are reasonable grounds for believing that the company is, or after the repurchase would be, unable to pay its liabilities as they become due.

Transactions with Significant Shareholders

        The Bermuda Companies Act does not have, and our bye-laws do not provide for, the equivalent of the "business combination" provisions of Section 203 of the Delaware General Corporate Law.

Corporate Opportunities

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

Shareholder Suits

        Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an

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action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company's memorandum of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of the company's shareholders than that which actually approved it.

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

        Our bye-laws contain a provision by virtue of which we and our shareholders waive any claim or right of action that they have, both individually and on our behalf, against any director or officer in relation to any action or failure to take action by such director or officer, except in respect of any fraud or dishonesty of such director or officer. We have been advised by the SEC that in the opinion of the SEC, the operation of this provision as a waiver of the right to sue for violations of federal securities laws would likely be unenforceable in U.S. courts.

Access to Books and Records and Dissemination of Information

        Members of the general public have a right to inspect the public documents of a company available at the office of the Registrar of Companies in Bermuda. These documents include the company's memorandum of association and any amendments thereto. The shareholders have the additional right to inspect the bye-laws of the company, minutes of general meetings of shareholders and the company's audited financial statements. The company's audited financial statements must be presented at the annual general meeting of shareholders. The company's share register is open to inspection by shareholders and by members of the general public without charge. A company is required to maintain its share register in Bermuda but may, subject to the provisions of the Bermuda Companies Act, establish a branch register outside of Bermuda. Bermuda law does not, however, provide a general right for shareholders to inspect or obtain copies of any other corporate records.

Registrar or Transfer Agent

        A register of holders of the common shares will be maintained by Codan Services Limited in Bermuda, and a branch register will be maintained in the United States by        , who will serve as branch registrar and transfer agent.

Listing

        We have applied to list our common shares on the NYSE under the symbol "KOS." Settlement will take place through The Depository Trust Company in U.S. dollars. Shortly after the closing of this offering we intend to apply to list our common shares on the GSE, although there can be no assurance that this listing will be completed in a timely manner, or at all.

Certain Provisions of Bermuda Law

        We have been designated by the Bermuda Monetary Authority as a non-resident for Bermuda exchange control purposes. This designation allows us to engage in transactions in currencies other than the Bermuda dollar, and there are no restrictions on our ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda or to pay dividends to United States residents who are holders of our common shares.

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        The Bermuda Monetary Authority has given its consent for the issue and free transferability of all of the common shares that are the subject of this offering to and between non-residents of Bermuda for exchange control purposes, provided our shares remain listed on an appointed stock exchange, which includes the NYSE. Approvals or permissions given by the Bermuda Monetary Authority do not constitute a guarantee by the Bermuda Monetary Authority as to our performance or our creditworthiness. Accordingly, in giving such consent or permissions, the Bermuda Monetary Authority shall not be liable for the financial soundness, performance or default of our business or for the correctness of any opinions or statements expressed in this prospectus. Certain issues and transfers of common shares involving persons deemed resident in Bermuda for exchange control purposes require the specific consent of the Bermuda Monetary Authority.

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

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

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SHARES ELIGIBLE FOR FUTURE SALE

        Prior to this offering, there has been no market for our common shares, and a liquid trading market for our common shares may not develop or be sustained after this offering. Future sales of substantial amounts of our common shares in the public market could adversely affect market prices prevailing from time to time. Furthermore, because only a limited number of common shares will be available for sale shortly after this offering due to existing contractual and legal restrictions on resale as described below, there may be sales of substantial amounts of our common shares in the public market after the restrictions lapse. This may adversely affect the prevailing market price and our ability to raise equity capital in the future. We have applied to have our common shares listed on the NYSE under the symbol "KOS." Shortly after the closing of this offering we intend to apply to list our common shares on the GSE, although there can be no assurance that this listing will be completed in a timely manner, or at all.

        Based on the number of common shares issued and outstanding as of December 31, 2010 after giving effect to our reorganization, upon completion of this offering,             common shares will be issued and outstanding, assuming no exercise of the underwriters' over-allotment option. Of the common shares to be issued and outstanding immediately after the closing of this offering, the            common shares to be sold in this offering will be freely tradable without restriction under the Securities Act unless purchased by our "affiliates," as that term is defined in Rule 144 under the Securities Act. The remaining common shares are "restricted securities" under Rule 144. Substantially all of these restricted securities will be subject to the provisions of the lock-up agreements referred to below.

        After the expiration of any lock-up period, these restricted securities may be sold in the public market only if registered or if they qualify for an exemption from registration under Rule 144 or 701 under the Securities Act, which exemptions are summarized below.

Rule 144

        In general, under Rule 144 under the Securities Act, as in effect on the date of this prospectus, a person who is not one of our affiliates at any time during the three months preceding a sale, and who has beneficially owned our common shares to be sold for at least six months, would be entitled to sell an unlimited number of our common shares, provided current public information about us is available. In addition, under Rule 144, a person who is not one of our affiliates at any time during the three months preceding a sale, and who has beneficially owned our common shares to be sold for at least one year, would be entitled to sell an unlimited number of common shares beginning one year after this offering without regard to whether current public information about us is available. Our affiliates who have beneficially owned our common shares for at least six months are entitled to sell within any three month period a number of common shares that does not exceed the greater of:

•
1% of the number of our common shares then issued and outstanding, which will equal approximately            common shares immediately after this offering, and

•
the average weekly trading volume in our common shares on the NYSE during the four calendar weeks preceding the date of filing of a Notice of Proposed Sale of Securities Pursuant to Rule 144 with respect to the sale.

        Sales by affiliates under Rule 144 are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us. Rule 144 also provides that affiliates relying on Rule 144 to sell our common shares that are not restricted common shares must nonetheless comply with the same restrictions applicable to restricted common shares, other than the holding period requirement.

        Upon expiration of any lock-up period and the six-month holding period, approximately            of our common shares will be eligible for sale under Rule 144 by our affiliates, subject to the above

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restrictions. Upon the expiration of any lock-up period and the six-month holding period, approximately            of our common shares will be eligible for sale by non-affiliates under Rule 144. We cannot estimate the number of common shares that our existing shareholders will elect to sell under Rule 144.

Rule 701

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

Lock-up Agreements

        In connection with this offering, we, our officers and directors, and certain shareholders have each entered into a lock-up agreement with the underwriters of this offering that restricts the sale of our common shares for a period of 180 days after the date of this prospectus, subject to extension in certain circumstances. The Representatives (as defined in "Underwriting"), on behalf of the underwriters, may, in their sole discretion, choose to release any or all of our common shares subject to these lock-up agreements at any time prior to the expiration of the lock-up period without notice. For more information, see "Underwriting."

Registration Rights

        Prior to the consummation of this offering, we will enter into a registration rights agreement with certain of our shareholders pursuant to which we will grant certain of our shareholders and their affiliates certain registration rights with respect to our common shares owned by them. Pursuant to the lock-up agreements described above, certain of our shareholders have agreed not to exercise those rights during the lock-up period without the prior written consent of the Representatives of the underwriters of this offering.

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CERTAIN TAX CONSIDERATIONS

Bermuda Tax Considerations

        At the present time, there is no Bermuda income or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance tax payable by us or by our shareholders in respect of our shares. We have obtained an assurance from the Bermuda Minister of Finance under the Exempted Undertakings Tax Protection Act 1966 that, in the event that any legislation is enacted in Bermuda imposing any tax computed on profits or income, or computed on any capital asset, gain or appreciation or any tax in the nature of estate duty or inheritance tax, such tax shall not, until March 28, 2016, be applicable to us or to any of our operations or to our shares, debentures or other obligations except insofar as such tax applies to persons ordinarily resident in Bermuda or is payable by us in respect of real property owned or leased by us in Bermuda.

U.S. Federal Income Tax Considerations

        The following is a description of the material U.S. federal income tax consequences to the U.S. Holders described below of owning and disposing of our common shares, but it does not purport to be a comprehensive description of all tax considerations that may be relevant to a particular person's decision to acquire our common shares. This discussion does not discuss any state, local or foreign tax considerations. This discussion applies only to a U.S. Holder that acquires our common shares pursuant to this offering and holds them as capital assets for tax purposes. In addition, it does not describe all of the tax consequences that may be relevant in light of the U.S. Holder's particular circumstances, including alternative minimum tax consequences and tax consequences applicable to U.S. Holders subject to special rules, such as:

•
certain financial institutions;

•
dealers or traders in securities who use a mark-to-market method of tax accounting;

•
persons holding our common shares as part of a hedging transaction, straddle, wash sale, conversion transaction or integrated transaction or persons entering into a constructive sale with respect to our common shares;

•
persons whose functional currency for U.S. federal income tax purposes is not the U.S. dollar;

•
entities classified as partnerships for U.S. federal income tax purposes;

•
tax-exempt entities, including "individual retirement accounts"; or

•
persons that own or are deemed to own ten percent or more of our voting shares.

        If an entity that is classified as a partnership for U.S. federal income tax purposes holds our common shares, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the activities of the partnership. Partnerships holding our common shares and partners in such partnerships should consult their tax advisers as to the particular U.S. federal income tax consequences of holding and disposing of our common shares.

        This discussion is based on the Internal Revenue Code of 1986, as amended (the "Code"), administrative pronouncements, judicial decisions, and final, temporary and proposed Treasury regulations, all as of the date of this prospectus, any of which is subject to change, possibly with retroactive effect. U.S. Holders should consult their tax advisers concerning the U.S. federal, state, local and foreign tax consequences of owning and disposing of our common shares in their particular circumstances.

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        A "U.S. Holder" is a holder who, for U.S. federal income tax purposes, is a beneficial owner of our common shares and is:

•
a citizen or individual resident of the United States;

•
a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States, any state therein or the District of Columbia; or

•
an estate or trust the income of which is subject to U.S. federal income taxation regardless of its source.

        This discussion assumes that we are not, and will not become, a passive foreign investment company, as described below.

Taxation of Distributions

        As discussed above under "Dividend Policy," we do not currently intend to pay dividends. In the event that we do pay dividends, subject to the passive foreign investment company rules described below, distributions paid on our common shares, other than certain pro rata  distributions of common shares, will be treated as dividends to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). The amount of the dividend will be treated as foreign-source dividend income to U.S. Holders and will not be eligible for the dividends-received deduction generally available to U.S. corporations under the Code.

Sale or Other Disposition of Common Shares

        Subject to the passive foreign investment company rules described below, for U.S. federal income tax purposes, gain or loss realized on the sale or other disposition of our common shares will be capital gain or loss, and generally will be long-term capital gain or loss if the U.S. Holder held our common shares for more than one year. The amount of the gain or loss will equal the difference between the U.S. Holder's tax basis in the common shares disposed of and the amount realized on the disposition, in each case as determined in U.S. dollars. This gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes.

Passive Foreign Investment Company Rules

        Based on management estimates and projections of future operations and revenue, we do not believe we will be a passive foreign investment company (a "PFIC") for U.S. federal income tax purposes for our current taxable year and we do not expect to become one in the foreseeable future. In general, a non-U.S. corporation is a PFIC for any taxable year in which (i) 75% or more of its gross income consists of passive income (such as dividends, interest, rents and royalties) or (ii) 50% or more of the average quarterly value of its assets consists of assets that produce, or are held for the production of, passive income. Because our PFIC status is a factual determination that is made annually and depends on the composition of our income (which in turn depends on our oil revenues from production) and the composition and market value of our assets from time to time, there can be no assurance that we will not be a PFIC for any taxable year. In particular, if we do not generate a significant amount of oil revenues from production, we may be a PFIC for the current taxable year and for one or more future taxable years.

        If we were a PFIC for any taxable year during which a U.S. Holder held our common shares, gain recognized by a U.S. Holder on a sale or other disposition (including certain pledges) of our common shares would be allocated ratably over the U.S. Holder's holding period for the common shares. The amounts allocated to the taxable year of the sale or other disposition and to any year before we became a PFIC would be taxed as ordinary income. The amount allocated to each other taxable year would be subject to tax at the highest rate in effect for individuals or corporations, as appropriate, for

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that taxable year, and an interest charge would be imposed on the amount allocated to that taxable year. Similar rules would apply to the extent that any distribution received by a U.S. Holder on its common shares exceeds 125% of the average of the annual distributions on the common shares received during the preceding three years or the U.S. Holder's holding period, whichever is shorter. Certain elections may be available that would result in alternative treatments (such as mark-to-market treatment) of the common shares. U.S. Holders should consult their tax advisers to determine whether any of these elections would be available and, if so, what the consequences of the alternative treatments would be in their particular circumstances. If we were a PFIC for any year during which a U.S. Holder holds our common shares, we generally would continue to be treated on a PFIC with respect to the holder for all succeeding years during which the U.S. Holder holds our common shares, even if we subsequently ceased to meet the requirements for PFIC Status. U.S. Holders should consult their tax advisers regarding the potential availability of a "deemed sale" election that would allow them to eliminate the continuation of PFIC status under these circumstances.

        If a U.S. Holder owns our common shares during any year in which we are a PFIC, the holder may be required to file Internal Revenue Service ("IRS") Form 8621 reporting certain distributions it receives from us, as well as any disposition of all or any portion of its common shares. In addition, pursuant to a recent amendment to the Code, a U.S. Holder who owns our common shares during any year in which we are a PFIC may be required to file an annual report with the IRS with respect to us containing such information as the U.S. Treasury Department may require.

Information Reporting and Backup Withholding

        Payments of dividends and sales proceeds that are made within the United States or through certain U.S. related financial intermediaries generally are subject to information reporting, and may be subject to backup withholding, unless (i) the U.S. Holder is a corporation or other exempt recipient or (ii) in the case of backup withholding, the U.S. Holder provides a correct taxpayer identification number and certifies that it is not subject to backup withholding. The amount of any backup withholding from a payment to a U.S. Holder will be allowed as a credit against the holder's U.S. federal income tax liability and may entitle it to a refund, provided that the required information is timely furnished to the IRS.

Certain Reporting Obligations

        If a U.S. Holder acquires shares in this offering for a price in excess of $100,000, the Holder must file IRS Form 926 for the holder's taxable year in which the registration occurs. Failure by a U.S. Holder to timely comply with such reporting requirements may result in substantial penalties.

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UNDERWRITING

        Under the terms and subject to the conditions contained in an underwriting agreement dated            , 2011, we have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc. are acting as representatives (the "Representatives"), the following respective numbers of common shares:
 	 	 	 	 	 	
Underwriter	 	Number of
Common Shares	 	
Credit Suisse Securities (USA) LLC	 	 	            	 	
Citigroup Global Markets Inc. 	 	 	            	 	
Barclays Capital Inc. 	 	 	            	 	
 	Total	 	 	            	 	
 	 	 	 	
        The underwriting agreement provides that the underwriters are obligated to purchase all the common shares in the offering if any are purchased, other than those shares covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated.

        We have granted to the underwriters a 30-day option to purchase on a pro rata basis up to            additional common shares from us at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common shares.

        The underwriters propose to offer the common shares initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $    per common share. The underwriters and selling group members may allow a discount of $        per common share on sales to other broker/dealers. After the initial public offering the Representatives may change the public offering price and concession and discount to broker/dealers. The offering of the common shares by the underwriters is subject to receipt and acceptance and subject to the underwriters' right to reject any order in whole or in part.

        The following table summarizes the compensation and estimated expenses we will pay:

	 	Per Common Share	 	Total	 	
 
	 	Without
Over-allotment	 	With
Over-allotment	 	Without
Over-allotment	 	With
Over-allotment	 	
Underwriting discounts and commissions paid by us	 	$	            	 	$	            	 	$	            	 	$	            	 	
Expenses payable by us	 	$	            	 	$	            	 	$	            	 	$	            	 	
        The Representatives have informed us that the underwriters do not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the common shares being offered.

        We have agreed, subject to certain exceptions, that we will not offer, sell, issue, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the SEC a registration statement under the Securities Act relating to, any of our common shares or securities convertible into or exchangeable or exercisable for any of our common shares, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of the Representatives for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the "lock-up" period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the "lock-up" period, we announce that we will release earnings results during the 16-day period beginning on the last day of the "lock-up" period, then in either case the expiration of the "lock-up" will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless the Representatives waive, in writing, such an extension.

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        Our officers, directors and certain shareholders have agreed, subject to certain exceptions, that they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any of our common shares or securities convertible into or exchangeable or exercisable for any of our common shares, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common shares, whether any of these transactions are to be settled by delivery of our common shares or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of the Representatives for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the "lock-up" period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the "lock-up" period, we announce that we will release earnings results during the 16-day period beginning on the last day of the "lock-up" period, then in either case the expiration of the "lock-up" will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless the Representatives waive, in writing, such an extension.

        We have agreed to indemnify the underwriters against liabilities under the Securities Act or contribute to payments that the underwriters may be required to make in that respect.

        The underwriters have reserved for sale at the initial public offering price up to            common shares for employees, directors and other persons associated with us who have expressed an interest in purchasing common shares in the offering. The number of common shares available for sale to the general public in the offering will be reduced to the extent these persons purchase the reserved common shares. Any reserved common shares not so purchased will be offered by the underwriters to the general public on the same terms as the other common shares.

        We have applied to list our common shares on the NYSE under the symbol "KOS." Shortly after the closing of this offering we intend to apply to list our common shares on the GSE, although there can be no assurance that this listing will be completed in a timely manner, or at all.

        In connection with the listing of the common shares on the NYSE, the underwriters will undertake to sell round lots of 100 shares or more to a minimum of 400 beneficial owners.

        Prior to this offering, there has been no public market for our common shares. The initial public offering price has been determined by a negotiation among us and the Representatives and will not necessarily reflect the market price of our common shares following the offering. The principal factors that were considered in determining the public offering price included:

•
the information presented in this prospectus;

•
the history of and prospects for the industry in which we will compete;

•
the ability of our management;

•
the prospects for our future earnings;

•
the present state of our development and current financial condition;

•
the recent market prices of, and the demand for, publicly traded shares of generally comparable companies; and

•
the general condition of the securities markets at the time of this offering.

        We offer no assurances that the initial public offering price will correspond to the price at which the common shares will trade in the public market subsequent to the offering or that an active trading market for our common shares will develop and continue after the offering.

        In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act.

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•
Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

•
Over-allotment involves sales by the underwriters of common shares in excess of the number of common shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of common shares over-allotted by the underwriters is not greater than the number of common shares that they may purchase in the over-allotment option. In a naked short position, the number of common shares involved is greater than the number of common shares in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing common shares in the open market.

•
Syndicate covering transactions involve purchases of the common shares in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of common shares to close out the short position, the underwriters will consider, among other things, the price of common shares available for purchase in the open market as compared to the price at which they may purchase common shares through the over-allotment option. If the underwriters sell more common shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying common shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common shares in the open market after pricing that could adversely affect investors who purchase in the offering.

•
Penalty bids permit the Representatives to reclaim a selling concession from a syndicate member when the common shares originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

        These stabilizing transactions, syndicate covering transactions and penalty bids, as well as purchases by the underwriters for their own accounts, may have the effect of raising or maintaining the market price of our common shares or preventing or retarding a decline in the market price of the common shares. As a result the price of our common shares may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

        Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory, lending and investment banking services for us and our affiliates, for which they received or will receive customary fees and expenses. An affiliate of Credit Suisse Securities (USA) LLC has extended a $50.0 million commitment to an affiliate of Kosmos in conjunction with Kosmos' commercial debt facilities. An affiliate of Credit Suisse Securities (USA) LLC also acted as a project finance advisor for a portion of such facilities. Affiliates of Citigroup Global Markets Inc. and Barclays Capital Inc. have also extended commitments to an affiliate of Kosmos in conjunction with Kosmos' commercial debt facilities, in amounts of $120.0 million and $26.0 million, respectively.

        The common shares are offered for sale in those jurisdictions in the United States, Europe, Asia and elsewhere where it is lawful to make such offers.

        Each of the underwriters has represented and agreed that it has not offered, sold or delivered and will not offer, sell or deliver any of the common shares directly or indirectly, or distribute this prospectus or any other offering material relating to the common shares, in or from any jurisdiction except under circumstances that will result in compliance with the applicable laws and regulations thereof and that will not impose any obligations on us except as set forth in the underwriting agreement.

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        In relation to each member state of the European Economic Area which has implemented the Prospectus Directive (each, a "Relevant Member State"), including each Relevant Member State that has implemented amendments to Article 3(2) of the Prospectus Directive with regard to persons to whom an offer of securities is addressed and the denomination per unit of the offer of securities (each, an "Early Implementing Member State"), with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the "Relevant Implementation Date"), no offer of common shares will be made to the public in that Relevant Member State (other than offers (the "Permitted Public Offers") where a prospectus will be published in relation to the common shares that has been approved by the competent authority in a Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive), except that with effect from and including that Relevant Implementation Date, offers of common shares may be made to the public in that Relevant Member State at any time:

(a)
to "qualified investors" as defined in the Prospectus Directive, including:

(A)
(in the case of Relevant Member States other than Early Implementing Member States), legal entities which are authorised or regulated to operate in the financial markets or, if not so authorised or regulated, whose corporate purpose is solely to invest in securities, or any legal entity which has two or more of (i) an average of at least 250 employees during the last financial year; (ii) a total balance sheet of more than €43.0 million and (iii) an annual turnover of more than €50.0 million as shown in its last annual or consolidated accounts; or

(B)
(in the case of Early Implementing Member States), persons or entities that are described in points (1) to (4) of Section I of Annex II to Directive 2004/39/EC, and those who are treated on request as professional clients in accordance with Annex II to Directive 2004/39/EC, or recognised as eligible counterparties in accordance with Article 24 of Directive 2004/39/EC unless they have requested that they be treated as non-professional clients; or

(b)
to fewer than 100 (or, in the case of Early Implementing Member States, 150) natural or legal persons (other than "qualified investors" as defined in the Prospectus Directive) subject to obtaining the prior consent of the Subscribers; or

(c)
in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of common shares shall result in a requirement for the publication of a prospectus pursuant to Article 3 of the Prospectus Directive or of a supplement to a prospectus pursuant to Article 16 of the Prospectus Directive.

        Each person in a Relevant Member State (other than a Relevant Member State where there is a Permitted Public Offer) who initially acquires any common shares or to whom any offer is made will be deemed to have represented, acknowledged and agreed that (A) it is a "qualified investor", and (B) in the case of any common shares acquired by it as a financial intermediary, as that term is used in Article 3(2) of the Prospectus Directive, (x) the common shares acquired by it have not been acquired on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than "qualified investors" as defined in the Prospectus Directive, or in circumstances in which the prior consent of the Representatives has been given to the offer or resale, or (y) where common shares have been acquired by it on behalf of persons in any Relevant Member State other than "qualified investors" as defined in the Prospectus Directive, the offer of those common shares to it or not treated under the Prospectus Directive as having been made to such persons.

        For the purpose of the above provisions, the expression "an offer to the public" in relation to any common shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer of any common shares to be offered so as to

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enable an investor to decide to purchase any common shares, as the same may be varied in the Relevant Member State by any measure implementing the Prospectus Directive in the Relevant Member State and the expression "Prospectus Directive" means Directive 2003/71 EC (including that Directive as amended, in the case of Early Implementing Member States) and includes any relevant implementing measure in each Relevant Member State.

        Each of the underwriters has severally represented, warranted and agreed as follows:

(a)
it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of section 21 of FSMA) to persons who have professional experience in matters relating to investments falling with Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 or in circumstances in which section 21 of FSMA does not apply to the company; and

(b)
it has complied with, and will comply with all applicable provisions of FSMA with respect to anything done by it in relation to the common shares in, from or otherwise involving the United Kingdom.

        Neither this prospectus nor any other offering material relating to the common shares described in this prospectus has been submitted to the clearance procedures of the Autorité des Marchés Financiers  or of the competent authority of another member state of the European Economic Area and notified to the Autorité des Marchés Financiers . The common shares have not been offered or sold and will not be offered or sold, directly or indirectly, to the public in France. Neither this prospectus nor any other offering material relating to the common shares has been or will be:

•
released, issued, distributed or caused to be released, issued or distributed to the public in France; or

•
used in connection with any offer for subscription or sale of the shares to the public in France.

        Such offers, sales and distributions will be made in France only:

•
to qualified investors (investisseurs qualifiés) and/or to a restricted circle of investors (cercle restreint d'investisseurs), in each case investing for their own account, all as defined in, and in accordance with articles L.411-2, D.411-1, D.411-2, D.734-1, D.744-1, D.754-1 and D.764-1 of the French Code monétaire et financier ;

•
to investment services providers authorized to engage in portfolio management on behalf of third parties; or

•
in a transaction that, in accordance with article L.411-2-II-1°-or-2°-or 3° of the FrenchCode monétaire et financier  and article 211-2 of the General Regulations ( Règlement Général ) of the Autorité des Marchés Financiers , does not constitute a public offer (appel public à l'épargne ).

        The common shares may be resold directly or indirectly, only in compliance with articles L.411-1, L.411-2, L.412-1 and L.621-8 through L.621-8-3 of the French Code monétaire et financier .

        The common shares may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to "professional investors" within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a "prospectus" within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), and no advertisement, invitation or document relating to the common shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to "professional

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investors" within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

        This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the "SFA"), (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA. Where the common shares are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries' rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the common shares under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.

        The common shares have not been and will not be registered under the Financial Instruments and Exchange Law of Japan (the Financial Instruments and Exchange Law) and each underwriter has agreed that it will not offer or sell any common shares, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

        This prospectus as well as any other material relating to the common shares does not constitute an issue prospectus pursuant Articles 652a or 1156 of the Swiss Code of Obligations. The common shares will not be listed on the SWX Swiss Exchange and, therefore, the documents relating to the common shares, including, but not limited to, this prospectus, do not claim to comply with the disclosure standards of the listing rules of SWX Swiss Exchange and corresponding prospectus schemes annexed to the listing rules of the SWX Swiss Exchange. None of this offering and the common shares has been or will be approved by any Swiss regulatory authority. The common shares are being offered by way of a private placement to a limited and selected circle of investors in Switzerland without any public offering and only to investors who do not subscribe for the common shares with the intention to distribute them to the public. The investors will be individually approached by the Issuer from time to time. This prospectus as well as any other material relating to the common shares is personal and confidential to each offeree and do not constitute an offer to any other person. This prospectus may only be used by those investors to whom it has been handed out in connection with the offer described herein and may neither directly nor indirectly be distributed or made available to other persons without express consent of the Issuer. It may not be used in connection with any other offer and shall in particular not be copied and/or distributed to the public in Switzerland or from Switzerland.

        The common shares described in this prospectus may not be, are not and will not be offered, distributed, sold, transferred or delivered, directly or indirectly, to any person in the Dubai International Financial Centre other than in accordance with the Offered Securities Rules of the Dubai Financial Services Authority.

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        This offering is restricted in the Kingdom of Bahrain to banks, financial institutions and professional investors and any person receiving this prospectus in the Kingdom of Bahrain and not falling within those categories is ineligible to purchase our common shares.

        This prospectus does not constitute a public offer of securities in the Kingdom of Saudi Arabia and is not intended to be a public offer. No action has been or will be taken in the Kingdom of Saudi Arabia that would permit a public offering or private placement of our common shares in the Kingdom of Saudi Arabia, or possession or distribution of any offering materials in relation thereto. Our common shares may only be offered or sold in the Kingdom of Saudi Arabia in accordance with Part 5 (Exempt Offers) of the Offers of Securities Regulations dated 20/8/1425 AH (corresponding to 4/10/2004) (the "Regulations") and, in accordance with Part 5 (Exempt Offers) Article 1716(a)(3) of the Regulations, common shares will be offered to no more than 60 offerees in the Kingdom of Saudi Arabia with each such offeree paying an amount not less than Saudi Riyals one million or its equivalent. Investors are informed that Article 19 of the Regulations places restrictions on secondary market activity with respect to our common shares. Any resale or other transfer, or attempted resale or other transfer, made other than in compliance with the above-stated restrictions shall not be recognized by us. Prospective purchasers of the common shares offered hereby should conduct their own due diligence on the accuracy of the information relating to the securities. If you do not understand the contents of this document you should consult an authorized financial adviser.

        This prospectus does not constitute an invitation or public offer of securities in the State of Qatar and should not be construed as such. This prospectus is intended only for the original recipient and must not be provided to any other person. It is not for general circulation in the State of Qatar and may not be reproduced or used for any other purpose.

        No marketing or sale of the common shares may take place in Kuwait unless the same has been duly authorized by the Kuwait Ministry of Commerce and Industry pursuant to the provisions of Law No. 31/1990 and the various ministerial regulations issued thereunder. Persons into whose possession this offering memorandum comes are required to inform themselves about and to observe such restrictions. Investors in Kuwait who approach us or obtain copies of this offering memorandum are required to keep such prospectus confidential and not to make copies thereof or distribute the same to any other person and are also required to observe the restrictions provided for in all jurisdictions with respect to offering, marketing and the sale of common shares.

        This prospectus is not intended to constitute an offer, sale or delivery of common shares or other securities under the laws of the United Arab Emirates. The common shares have not been and will not be registered under Federal Law No. 4 of 2000 concerning the Emirates Securities and Commodities Authority and the Emirates Security and Commodity Exchange, or with the UAE Central Bank, the Dubai Financial Market, the Abu Dhabi Securities Market or with any other United Arab Emirates exchange. The offering of the common shares and interests therein have not been approved or licensed by the UAE Central Bank or any other licensing authorities in the United Arab Emirates. The common shares may not be, have not been and are not being offered, sold or publicly promoted or advertised in the United Arab Emirates, other than in compliance with laws applicable in the United Arab Emirates governing the issue, offering and sale of securities. Furthermore, the information contained in this prospectus does not constitute a public offer of securities in the United Arab Emirates in accordance with the Commercial Companies Law (Federal Law No. 8 of 1984 (as amended)) or otherwise, and is not intended to be a public offer. The information contained in this prospectus is not intended to lead to the conclusion of any contract of whatsoever nature within the territory of the United Arab Emirates. In relation to its use in the United Arab Emirates, this prospectus is strictly private and confidential, is being distributed to a limited number of investors and must not be provided to any person other than the original recipient, and may not be reproduced or used for any other purpose. The common shares may not be offered or sold directly or indirectly to the public in the United Arab Emirates.

        A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representatives may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

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LEGAL MATTERS

        The validity of the common shares offered in this prospectus is being passed upon for us by Conyers Dill & Pearman Limited, our special Bermuda counsel. Some legal matters as to U.S. law in connection with this offering are being passed upon for us by Davis Polk & Wardwell LLP, New York, New York. Shearman & Sterling LLP, New York, New York is acting as counsel for the underwriters in this offering.
EXPERTS

        The consolidated financial statements of Kosmos Energy Holdings at December 31, 2009 and 2010, and for each of the three years in the period ended December 31, 2010 and for the period April 23, 2003 (Inception) through December 31, 2010 and the schedules of Kosmos Energy Holdings as of December 31, 2009 and 2010 and for each of the three years in the period ended December 31, 2010, appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

        The information included in this prospectus regarding estimated quantities of proved reserves, the future net revenues from those reserves and their present value is based, in part, on estimates of the proved reserves and present values of proved reserves as of December 31, 2010. The reserve estimates at December 31, 2010 and December 31, 2009 are based on reports prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers. These estimates are included in this prospectus in reliance upon the authority of such firm as experts in these matters.
WHERE YOU CAN FIND ADDITIONAL INFORMATION

        We have filed with the SEC a registration statement on Form S-1, which includes exhibits, schedules and amendments, under the Securities Act with respect to this offering of our securities. Although this prospectus, which forms a part of the registration statement, contains all material information included in the registration statement, parts of the registration statement have been omitted as permitted by rules and regulations of the SEC. We refer you to the registration statement and its exhibits for further information about us, our securities and this offering. The registration statement and its exhibits, as well as any other documents that we have filed with the SEC, can be inspected and copied at the SEC's public reference room at 100 F Street, N.E., Washington, D.C. 20549-1004. The public may obtain information about the operation of the public reference room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website at http://www.sec.gov  that contains the registration statement and other reports, proxy and information statements and information that we file electronically with the SEC.

        After we have completed this offering, we will file annual, quarterly and current reports, proxy statements and other information with the SEC. We intend to make these filings available on our website once the offering is completed. You may read and copy any reports, statements or other information on file at the public reference rooms. You can also request copies of these documents, for a copying fee, by writing to the SEC, or you can review these documents on the SEC's website, as described above. In addition, we will provide electronic or paper copies of our filings free of charge upon request.

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GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS

        Unless listed below, all defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings.
 	 	 	
"2D seismic data"	 	Two-dimensional seismic data, serving as interpretive data that allows a view of a vertical cross-section beneath a prospective area.	

"3D seismic data"	
 	
Three-dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.	

"Aerial extent"	
 	
The area of the reservoir surface boundaries represented on a map.	

"Albian"	
 	
A geological time period ranging between 112 million and 99.6 million years ago.	

"API"	
 	
A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones.	

"Anticline"	
 	
When layers of rock are folded to create a dome, the resulting geometry is called an anticline. An anticline is thus created by way of four-way closure. Because oil is lighter than water, the oil tends to float to the top of the anticline. If an impermeable seal, such as a shale bed, caps the dome, then a pool of oil may form at the crest.	

"Appraisal well"	
 	
A well drilled after an exploratory well to gain more information on the drilled reservoirs.	

"AVO"	
 	
AVO, or amplitude versus offset, is a measure of the variation in seismic waves that occurs as the distance between the shotpoint and receiver changes during seismic testing. Variations in AVO indicate differences in lithology and fluid content in rocks above and below the reflector. The most important application of AVO is the detection of hydrocarbon reservoirs. AVO analysis refers to a technique by which geophysicists attempt to determine thickness, porosity, density, velocity, lithology and fluid content of rocks.	

"Barrel" or "bbl"	
 	
A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.	

"Barrels of oil-equivalent per acre-foot"	
 	
A unit of measurement for petroleum describing the number of recoverable equivalent barrels of oil and gas in one foot by one acre.	

"Basin"	
 	
A depression in the crust of the Earth, caused by plate tectonic activity and subsidence, in which sediments accumulate. If hydrocarbon rich source rocks occur in combination with appropriate depth and duration of burial, then a petroleum system can develop within the basin.	
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"Bbbl"	 	Billion barrels of oil.	

"Bboe"	
 	
Billion barrels of oil equivalent.	

"Bcf"	
 	
Billion cubic feet.	

"Blowout"	
 	
The uncontrolled release of formation fluids from a well. This may occur when a combination of well control safety systems fails during drilling or production operations.	

"boe"	
 	
Barrels of oil equivalent, with volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.	

"boepd"	
 	
Barrels of oil equivalent per day.	

"bopd"	
 	
Barrels of oil per day.	

"bwpd"	
 	
Barrels of water per day.	

"Campanian"	
 	
A geological time period ranging between 83.5 and 70.6 million years ago.	

"Channel"	
 	
A channel is a linear, commonly concave-based depression through which water and sediment flow and into which sediment can be deposited. The force of gravity and the movement of water in a channel creates a system of sedimentary transport known as a channel system.	

"Closure"	
 	
The vertical distance from the apex of a structure to the lowest structural contour that contains the structure. Measurements of both the areal closure and the distance from the apex to the lowest closing contour are typically incorporated in calculations of the estimated hydrocarbon content of a trap.	

"Completion"	
 	
The procedure used in finishing and equipping an oil or natural gas well for production.	

"Condensate"	
 	
Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure; however, when produced, is in the liquid phase at surface pressure and temperature.	

"Cretaceous"	
 	
A geologic period ranging from approximately 145 to 65 million years ago.	

"Dated Brent"	
 	
Refers to a cargo of blended North Sea Brent crude oil that has been assigned a date for loading onto a tanker. Physically, Brent is light but still heavier than West Texas Intermediate.	

"Depocenter"	
 	
The area of thickest deposition in a basin.	
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"Deposition"	 	Deposition is a geological process through which rock is formed by either mechanical or chemical processes. Mechanical depositional processes include the buildup of organic material, or the physical transport and depositing of sediment on top of an exposed underlying rock layer. Deposition can also occur as a result of chemical processes involving the buildup of organic material (such as the development of plant matter into coal) or the chemical alteration of a substance to form rock (such as the development of salts through the evaporation of water).	

"Depositional system"	
 	
A depositional system is the process through which a depositional environment is created. A depositional environment is a location where accumulations of sediment have been deposited and through which stratigraphic sequences develop.	

"Developed acreage"	
 	
The number of acres that are allocated or assignable to productive wells or wells capable of production.	

"Development"	
 	
The phase in which an oil field is brought into production by drilling development wells and installing appropriate production systems.	

"Development costs"	
 	
The costs incurred in the preparation of discovered reserves for production such as those incurred in connection with the fabrication and installation of processing equipment, as well as costs related to drilling and completion activities of production and injection wells.	

"Development well"	
 	
A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.	

"Dip"	
 	
The angle between the strata, sequence or fault relative to a horizontal plane.	

"Distal"	
 	
Distal refers to the location of a depositional environment sited at the furthest position from the sediment source, and is generally characterized by fine-grained sediments or shales.	

"Downdip"	
 	
This term refers to a relative location down the slope of a dipping surface or formation.	

"Downthrown"	
 	
With reference to the relative movement of geologic features present on either side of the fault plane, "downthrown" describes a layer of rock that is lower than the fault plane.	
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"Drilling and completion costs"	 	All costs, excluding operating costs, of drilling, completing, testing, equipping and bringing a well into production or plugging and abandoning it, including all costs associated with labor and other construction and installation, location and surface damages, cementing, drilling mud and chemicals, drillstem tests and core analysis, engineering and well site geological expenses, electric logs, plugging back, deepening, rework operations, repairing or performing remedial work of any type, plugging and abandoning.	

"Dry hole"	
 	
A well that has not encountered a hydrocarbon bearing reservoir.	

"E&P"	
 	
Exploration and production.	

"Exploration costs"	
 	
Costs incurred in identifying and examining areas that are considered to have prospects containing oil and/or natural gas. This includes, but is not limited to, the acquisition of license areas, seismic data, and exploratory wells.	

"Exploration well" or "Exploratory well"	
 	
A well drilled either (a) in search of a new and as yet undiscovered pool of oil or natural gas or (b) with the hope of significantly extending the limits of a pool already developed.	

"Facies"	
 	
A body of rock sharing similar characteristics.	

"Fairway"	
 	
The trend along which a particular geological feature is likely, such as a depositional fairway.	

"Farm-in"	
 	
An agreement whereby an oil company acquires a portion of the working interest in a block from the owner of such interest, usually in return for cash and for taking on a portion of the drilling of one or more specific wells or other performance by the assignee as a condition of the assignment.	

"Farm-out"	
 	
An agreement whereby the owner of the working interest agrees to assign a portion of its interest subject to the drilling of one or more specific wells or other work by the assignee as a condition of the assignment.	

"Fault"	
 	
In geology, a fault is a planar fracture or discontinuity in a volume of rock, across which there has been displacement. Large faults within the Earth's crust result from the action of tectonic forces.	

"Fault closure"	
 	
A fault sealing surface combined with a specific reservoir shape, which together provide a trap where hydrocarbons can accumulate.	

"Field"	
 	
A geographical area under which an oil or natural gas reservoir exists in commercial quantities.	

"Finding and development costs"	
 	
Capital costs incurred in the acquisition, exploration, appraisal and development of proved oil and natural gas reserves divided by proved reserve additions.	
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"Four-way closure"	 	A structural trap where closure is present from all angles and hydrocarbons cannot effectively escape and drain to the surface. In contrast to a three-way fault closure, none of the components of closure in a four-way closure is formed by the presence of a fault. See "—Closure"	

"FPSO"	
 	
Floating Production, Storage and Offloading vessel.	

"Frac-packs"	
 	
Refers to the process where fluids and sand are injected into hydrocarbon bearing rock at high-pressure in order to fracture the rock and prop open the newly created fissures. This process, combined with specialized downhole equipment, increases well productivity and provides a measure of protection against formation sand production.	

"Gas-oil ratio"	
 	
The ratio of the volume of natural gas that comes out of solution from a volume of oil at standard atmospheric conditions (expressed in standard cubic feet per barrel of oil).	

"Gathering system"	
 	
Pipelines and other facilities that transport oil and gas from wells to a central delivery point for sale or delivery into a transmission line or mainline.	

"Gross acre"	
 	
An acre in which a working interest is owned. The number of gross acres is the total number of acres in which an interest is owned.	

"Horizon"	
 	
A term used to denote a surface in or of rock, or a distinctive layer of rock that might be represented by a reflection in seismic data.	

"Hydrocarbon"	
 	
A hydrocarbon is an organic compound made of two elements, carbon and hydrogen. Various carbon and hydrogen atomic structures can form oil and natural gas.	

"Interference test"	
 	
A test of pressure interrelationships (interference) between wells within the same formation. This test is used to determine, for example, oil in place, inter-well communication and various reservoir properties.	

"License"	
 	
A legal instrument executed by the host government or agency thereof granting the right to explore, drill, develop and produce oil and natural gas. An oil and natural gas license embodies the legal rights, privileges and duties pertaining to the licensor and licensee.	

"Milidarcy"	
 	
One thousandth of a "darcy," which is a unit of permeability.	

"Mcf"	
 	
Thousand cubic feet.	

"Mcfpd"	
 	
Thousand cubic feet per day.	

"Mmbbl"	
 	
Million barrels of oil.	

"Mmboe"	
 	
Million barrels of oil equivalent.	

"Mmcf"	
 	
Million cubic feet.	
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"Mud"	 	Mud is a term that is generally synonymous with drilling fluid and that encompasses most fluids used in hydrocarbon drilling operations, especially fluids that contain significant amounts of suspended solids, emulsified water or oil.	

"Natural gas"	
 	
Natural gas is a combination of light hydrocarbons that, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found in underground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.	

"Natural gas liquid"	
 	
Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others.	

"OPEC"	
 	
Organization of the Petroleum Exporting Countries.	

"Permeability"	
 	
A combination of rock and fluid properties representing the fluid's ability to flow through a network of interconnected pores within a reservoir. Expressed in either Darcys (D) or  1 / 1000  of a Darcy termed millidarcies (mD). A higher permeability value represents the reservoir's natural potential to produce fluids and vice versa.	

"Petroleum System"	
 	
A petroleum system consists of organic material that has been buried at a sufficient depth to allow adequate temperature and pressure to expel hydrocarbons and cause the movement of oil from the area in which it was formed to a reservoir rock where it can accumulate.	

"Plan of development"	
 	
A written document outlining the steps to be undertaken to develop a field.	

"Play"	
 	
A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects.	

"Porosity"	
 	
The ratio of pore volume or void space to the gross rock volume. Represents the amount of storage space within a reservoir able to accommodate fluids and generally expressed as a percentage or as a fraction of unity. A higher porosity value equates to more hydrocarbons that can be stored within a given volume of rock and vice versa. Values can range from 0% to a theoretical maximum of 47.6%.	

"Pressure communication"	
 	
Formation pressure measurements can be obtained within a well and compared to offset or surrounding wells that have had similar measurements previously captured. When these pressures are plotted versus depth, analysis can be performed which may suggest the wells have penetrated the same reservoir. When this occurs, the wells are said to be in "pressure communication". This information is critical in ensuring injection wells are appropriately placed to support and efficiently sweep hydrocarbons to the producing wells.	
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"Production costs"	 	The production or operational costs incurred while extracting and producing, storing, and transporting oil and/or natural gas. Typical of these costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes, and insurance.	

"Producing well"	
 	
A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.	

"Prospect(s)"	
 	
A potential trap which may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of them fail neither oil nor natural gas will be present, at least not in commercial volumes.	

"Proved reserves"	
 	
Estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).	

"Proved developed reserves"	
 	
Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.	

"Proved undeveloped reserves"	
 	
Proved undeveloped reserves are those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.	

"Reserves"	
 	
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, a revenue interest in the production, installed means of delivering oil, gas, or related substances to market, and all permits and financing required to implement the project.	

"Reservoir"	
 	
A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.	
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"Royalty"	 	A fractional undivided interest in the production of oil and natural gas wells or the proceeds therefrom, to be received free and clear of all costs of development, operations or maintenance.	

"Seal"	
 	
A relatively impermeable rock, commonly shale, anhydrite or salt, that forms a barrier or cap above and around reservoir rock such that fluids cannot migrate beyond the reservoir. A seal is a critical component of a complete petroleum system.	

"Seismic data"	
 	
Seismic data is used by scientists to interpret the composition, fluid content, extent and geometry of rocks in the subsurface. Seismic data is acquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflected beneath the earth's surface and a receiver is used to collect and record these reflections.	

"Sequence"	
 	
A sequence refers to a series of geological events, processes, or rocks, arranged in chronological order.	

"Shale"	
 	
A fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.	

"Shelf margin"	
 	
The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.	

"Shut in"	
 	
To close the valves on a well so that it stops producing.	

"Sidetrack"	
 	
To drill a secondary wellbore within the original wellbore away from an original wellbore.	

"Source rock"	
 	
This term refers to rocks with sufficient organic material from which hydrocarbons have been generated or are capable of being generated. They typically have a deeper, warmer, and higher pressure than reservoir rocks which allows the expelled hydrocarbons to accumulate.	

"Spud"	
 	
The very beginning of drilling operations of a new well, occurring when the drilling bit penetrates the surface utilizing a drilling rig capable of drilling the well to the authorized total depth.	

"Structural trap"	
 	
A structural strap is a topographic feature in the earth's subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and gas in the strata.	

"Structural-stratigraphic trap"	
 	
A structural-stratigraphic trap is a combination trap with structural and stratigraphic features.	

"Stratigraphy"	
 	
The study of the composition, relative ages and distribution of layers of sedimentary rock.	
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"Stratigraphic trap"	 	A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.	

"Submarine fan"	
 	
A fan-shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.	

"Tertiary"	
 	
A geological time period ranging between 65 million and 2.6 million years ago.	

"Three-way fault trap"	
 	
A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.	

"Thrust Fault"	
 	
A thrust fault occurs where rocks of lower (older) stratigraphic position are pushed up and over higher (younger) strata. Thrust faults are the result of compression forces.	

"Thrust Sheet"	
 	
Thrust sheet is the body of rock within a thrust fault.	

"Total depth"	
 	
The maximum depth reached by a well.	

"Trap"	
 	
A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.	

"Transform fault"	
 	
A transform fault or transform boundary is a type of fault at the margin of a tectonic plate. Transform faults occur where tectonic plates slide past or move apart from each other. Most transform faults are found on the ocean floor, however, the best-known transform faults are found on land.	

"Turbidite"	
 	
A turbidite is a sediment transported and deposited by a turbidity current. A turbidity current is an underwater current of rapidly moving sand-laden water moving down a slope, comparable to an underwater avalanche.	

"Turbidite fan"	
 	
A turbidite fan is a fan shaped deposit of sand deposted on the seabed by a turbidity current. The architecture of these fans is constructed through many repeated depositional events or cycles. See "—Turbidite."	

"Turbidite fan lobe"	
 	
A turbidite fan lobe is one depositional cycle within the overall larger turbidite fan. These turbidite fan lobes often consist of excellent reservoir rock.	

"Turonian"	
 	
A geological time period ranging between 93.5 million and 89.3 million years ago.	

"Updip"	
 	
This term refers to a relative location up the slope of a dipping surface or formation.	
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"Undeveloped acreage"	 	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.	

"Unitized production"	
 	
Pooled production from wells or a reservoir. The proceeds of this pooled production are distributed to the participants according to the agreed-upon formula.	

"West African Transform Margin"	
 	
A portion of the West African continental margin extending approximately 2,400 miles (1,500 kilometers) along the coast from eastern Ghana, across the Ivory Coast and Liberia, and to the west of Sierra Leone. The area is associated with a series of transform faults.	

"Working interest"	
 	
A percentage of ownership in an oil and gas lease granting its owner the right to explore, drill and produce oil and gas from a tract of property. Working interest owners are obligated to pay a corresponding percentage of the cost of leasing, drilling, producing and operating a well or unit. The working interest also entitles its owner to share in production revenues with other working interest owners, based on the percentage of working interest owned.	

"Workover"	
 	
Operations in a producing well to restore or increase production.	
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INDEX TO FINANCIAL STATEMENTS

 
	 	Page	 	
Kosmos Energy Holdings	 	 	 	 	
Audited Consolidated Financial Statements (a Development Stage Entity)	 	 	 	 	
 	Report of Independent Registered Public Accounting Firm	 	 	
F-2	 	
 	Consolidated Balance Sheets as of December 31, 2009 and 2010	 	 	
F-3	 	
 	Consolidated Statements of Operations for the years ended December 31, 2008, 2009 and 2010 and for the Period April 23, 2003 (Inception) through December 31, 2010	 	 	
F-4	 	
 	Consolidated Statements of Unit Holdings Equity for the Period April 23, 2003 (Inception) through December 31, 2003 and for each of the seven years in the period ended December 31, 2010	 	 	
F-5	 	
 	Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2009 and 2010 and for the Period April 23, 2003 (Inception) through December 31, 2010	 	 	
F-6	 	
 	Consolidated Statements of Comprehensive Loss for the years ended December 31, 2008, 2009 and 2010 and for the Period April 23, 2003 (Inception) through December 31, 2010	 	 	
F-7	 	
 	Notes to Consolidated Financial Statements	 	 	
F-8	 	
 	Supplementary Oil and Gas Data (Unaudited)	 	 	
F-37	 	
F-1

Table of Contents
Report of Independent Registered Public Accounting Firm

The Unit Holders
Kosmos Energy Holdings

        We have audited the accompanying consolidated balance sheets of Kosmos Energy Holdings (a development stage entity) (the "Company") as of December 31, 2009 and 2010, and the related consolidated statements of operations, unit holdings equity, cash flows and comprehensive loss for each of the three years in the period ended December 31, 2010, and for the period April 23, 2003 (Inception) through December 31, 2010. Our audits also included the financial statement schedules included at Item 16(b). These consolidated financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and schedules based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Kosmos Energy Holdings at December 31, 2009 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, and for the period April 23, 2003 (Inception) through December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the consolidated financial statements taken as a whole, presents fairly, in all material respects, the financial information set forth therein.
 	 	 	
 	 	/s/ Ernst & Young LLP	
Dallas, Texas
March 2, 2011

F-2

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Balance Sheets

	 	December 31	 	Pro Forma as
Adjusted as of
December 31
2010	 	 	
 
	 	2009	 	2010	 	 	 	 	

	 	 
	 	(Unaudited)

	 	(In thousands)
	 	 	
Assets	 	 	 	 	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	139,505	 	$	100,415	 	 	 	 	 	
 	Restricted cash	 	 	—	 	 	80,000	 	 	 	 	 	
 	Receivables:	 	 	 	 	 	 	 	 	 	 	 	
 	 	Joint interest billings	 	 	42,616	 	 	124,449	 	 	 	 	 	
 	 	Notes	 	 	52,318	 	 	113,889	 	 	 	 	 	
 	 	Other	 	 	1,693	 	 	615	 	 	 	 	 	
 	Inventories	 	 	19,621	 	 	37,674	 	 	 	 	 	
 	Prepaid expenses and other	 	 	848	 	 	13,278	 	 	 	 	 	
 	Current deferred tax assets	 	 	127	 	 	89,600	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Total current assets	 	 	256,728	 	 	559,920	 	 	 	 	 	
Property and equipment:	 	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas properties, net of accumulated depletion of zero and $6,430, respectively	 	 	595,091	 	 	989,869	 	 	 	 	 	
 	Other property, net of accumulated depreciation of $3,193 and $5,343, respectively	 	 	8,916	 	 	8,131	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Property and equipment—net	 	 	604,007	 	 	998,000	 	 	 	 	 	
Other assets:	 	 	 	 	 	 	 	 	 	 	 	
 	Restricted cash	 	 	30,000	 	 	32,000	 	 	 	 	 	
 	Long-term receivables—joint interest billings, net of allowance	 	 	41,593	 	 	21,897	 	 	 	 	 	
 	Debt issue costs and other assets, net of accumulated amortization of $3,266 and $32,093, respectively	 	 	89,729	 	 	78,217	 	 	 	 	 	
 	Derivatives	 	 	—	 	 	1,501	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Total assets	 	$	1,022,057	 	$	1,691,535	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Liabilities and unit holdings/shareholders' equity	 	 	 	 	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	 	 	 	 	
 	Current maturities of long-term debt	 	$	—	 	$	245,000	 	 	 	 	 	
 	Accounts payable	 	 	97,837	 	 	163,495	 	 	 	 	 	
 	Accrued liabilities	 	 	41,810	 	 	53,208	 	 	 	 	 	
 	Derivatives	 	 	—	 	 	20,354	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Total current liabilities	 	 	139,647	 	 	482,057	 	 	 	 	 	
Long-term debt	 	 	285,000	 	 	800,000	 	 	 	 	 	
Long-term derivatives	 	 	—	 	 	15,104	 	 	 	 	 	
Long-term asset retirement obligations	 	 	—	 	 	16,752	 	 	 	 	 	
Leasehold improvement allowance—long-term	 	 	1,369	 	 	1,014	 	 	 	 	 	
Long-term deferred tax liability	 	 	653	 	 	12,513	 	 	 	 	 	
Convertible preferred units, 100,000 units authorized:	 	 	 	 	 	 	 	 	 	 	 	
 	Series A—30,000 units issued at December 31, 2009 and 2010	 	 	300,000	 	 	383,246	 	 	 	 	 	
 	Series B—20,000 units issued at December 31, 2009 and 2010	 	 	500,000	 	 	568,163	 	 	 	 	 	
 	Series C—885 units issued at December 31, 2009 and 2010	 	 	13,244	 	 	27,097	 	 	 	 	 	
Unit holdings/shareholders' equity:	 	 	 	 	 	 	 	 	 	 	 	
 	Common units, 100,000 units authorized; 18,667 and 19,070 issued at December 31, 2009 and 2010, respectively	 	 	516	 	 	516	 	 	 	 	 	
 	Additional paid-in capital	 	 	19,108	 	 	—	 	 	 	 	 	
 	Deficit accumulated during development stage	 	 	(237,480	)	 	(615,515	)	 	 	 	 	
 	Accumulated other comprehensive income	 	 	—	 	 	588	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Total unit holdings/shareholders' equity	 	 	(217,856	)	 	(614,411	)	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Total liabilities, convertible preferred units and unit holdings/shareholders' equity	 	$	1,022,057	 	$	1,691,535	 	$	 	 	 	
 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-3

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Operations

	 	 

	 	Period
April 23, 2003
(Inception)
Through
December 31
2010	 	 	
 
	 	Years Ended December 31	 	 	 	 	 	
 
	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas revenue	 	$	—	 	$	—	 	$	—	 	$	—	 	 	 	
 	Interest income	 	 	1,637	 	 	985	 	 	4,231	 	 	9,142	 	 	 	
 	Other income	 	 	5,956	 	 	9,210	 	 	5,109	 	 	26,699	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total revenues and other income	 	 	7,593	 	 	10,195	 	 	9,340	 	 	35,841	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Exploration expenses, including dry holes	 	 	15,373	 	 	22,127	 	 	73,126	 	 	166,450	 	 	 	
 	General and administrative	 	 	40,015	 	 	55,619	 	 	98,967	 	 	236,165	 	 	 	
 	Depletion, depreciation and amortization	 	 	719	 	 	1,911	 	 	2,423	 	 	6,505	 	 	 	
 	Amortization—debt issue costs	 	 	—	 	 	2,492	 	 	28,827	 	 	31,319	 	 	 	
 	Interest expense	 	 	1	 	 	6,774	 	 	59,582	 	 	66,389	 	 	 	
 	Derivatives, net	 	 	—	 	 	—	 	 	28,319	 	 	28,319	 	 	 	
 	Equity in losses of joint venture	 	 	—	 	 	—	 	 	—	 	 	16,983	 	 	 	
 	Doubtful accounts expense	 	 	—	 	 	—	 	 	39,782	 	 	39,782	 	 	 	
 	Other expenses, net	 	 	21	 	 	46	 	 	1,094	 	 	1,949	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total costs and expenses	 	 	56,129	 	 	88,969	 	 	332,120	 	 	593,861	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Loss before income taxes	 	 	(48,536	)	 	(78,774	)	 	(322,780	)	 	(558,020	)	 	 	
 	Income tax expense (benefit)	 	 	269	 	 	973	 	 	(77,108	)	 	(75,148	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(245,672	)	$	(482,872	)	 	 	
Accretion to redemption value of convertible preferred units	 	 	
(21,449	
)	 	
(51,528	
)	 	
(77,313	
)	 	
(165,262	
)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net loss attributable to common unit holders	 	$	(70,254	)	$	(131,275	)	$	(322,985	)	$	(648,134	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	(Unaudited)	 	 	 	 	 	 	
Pro forma basic and diluted net loss per common share	 	 	 	 	 	 	 	$	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pro forma weighted average number of shares used to compute pro forma net loss per share, basic and diluted	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-4

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Unit Holdings Equity

	 	 

	 	Deficit
Accumulated
During
Development
Stage	 	 

 
	 	Common Units	 	 
	 	 	 	Accumulated
Other
Comprehensive
Income	 	 

	 	 	 	Additional
Paid-in
Capital	 	 	 	 	 	 

	 	Units	 	Amount	 	 	 	 	 	 	 	Total	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 
	 	(In thousands)

Inception (April 23, 2003)	 	 	—	 	$	—	 	$	—	 	$	—	 	$	—	 	$	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of Kosmos Energy, LLC units	 	 	350	 	 	350	 	 	—	 	 	—	 	 	—	 	 	350	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(1,232	)	 	—	 	 	(1,232	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2003	 	 	350	 	 	350	 	 	—	 	 	(1,232	)	 	—	 	 	(882	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Exchanged Kosmos Energy, LLC units	 	 	(350	)	 	(350	)	 	—	 	 	—	 	 	—	 	 	(350	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	for Kosmos Energy Holdings units	 	 	3,500	 	 	350	 	 	—	 	 	—	 	 	—	 	 	350	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	2,850	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(3,951	)	 	—	 	 	(3,951	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2004	 	 	6,350	 	 	350	 	 	—	 	 	(5,183	)	 	—	 	 	(4,833	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	392	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(765	)	 	(42	)	 	—	 	 	—	 	 	—	 	 	(42	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	6	 	 	—	 	 	—	 	 	6	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(17,949	)	 	—	 	 	(17,949	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2005	 	 	5,977	 	 	308	 	 	6	 	 	(23,132	)	 	—	 	 	(22,818	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	409	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(784	)	 	(42	)	 	—	 	 	(205	)	 	—	 	 	(247	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	10	 	 	—	 	 	—	 	 	10	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(24,728	)	 	—	 	 	(24,728	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2006	 	 	5,602	 	 	266	 	 	16	 	 	(48,065	)	 	—	 	 	(47,783	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	1,067	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(25	)	 	—	 	 	—	 	 	(75	)	 	—	 	 	(75	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	447	 	 	—	 	 	—	 	 	447	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(60,788	)	 	—	 	 	(60,788	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2007	 	 	6,644	 	 	266	 	 	463	 	 	(108,928	)	 	—	 	 	(108,199	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	9,595	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(67	)	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	3,671	 	 	—	 	 	—	 	 	3,671	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(48,805	)	 	—	 	 	(48,805	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2008	 	 	16,172	 	 	266	 	 	4,134	 	 	(157,733	)	 	—	 	 	(153,333	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	10	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(15	)	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of C1 units	 	 	2,500	 	 	250	 	 	11,506	 	 	—	 	 	—	 	 	11,756	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	3,468	 	 	—	 	 	—	 	 	3,468	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(79,747	)	 	—	 	 	(79,747	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2009	 	 	18,667	 	 	516	 	 	19,108	 	 	(237,480	)	 	—	 	 	(217,856	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	411	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(8	)	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	13,791	 	 	—	 	 	—	 	 	13,791	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Derivatives, net	 	 	—	 	 	—	 	 	—	 	 	—	 	 	588	 	 	588	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Accrete convertible preferred units to redemption amount	 	 	—	 	 	—	 	 	(21,143	)	 	(132,363	)	 	—	 	 	(153,506	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Accrete value of Series C Convertible Preferred Units	 	 	—	 	 	—	 	 	(11,756	)	 	—	 	 	—	 	 	(11,756	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(245,672	)	 	—	 	 	(245,672	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2010	 	 	19,070	 	$	516	 	$	—	 	$	(615,515	)	$	588	 	$	(614,411	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-5

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Cash Flows

	 	 

	 	Period
April 23, 2003
(Inception)
Through
December 31
2010	 	 	
 
	 	Years Ended December 31	 	 	 	 	 	
 
	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	
Operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(245,672	)	$	(482,872	)	 	 	
Adjustments to reconcile net loss to net cash used in operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Equity in losses of joint venture	 	 	—	 	 	—	 	 	—	 	 	16,983	 	 	 	
 	 	Depletion, depreciation and amortization	 	 	719	 	 	4,403	 	 	31,250	 	 	37,824	 	 	 	
 	 	Deferred income taxes	 	 	428	 	 	99	 	 	(77,614	)	 	(77,086	)	 	 	
 	 	Deferred rent income	 	 	—	 	 	(266	)	 	(355	)	 	(621	)	 	 	
 	 	Leasehold improvement incentive	 	 	—	 	 	1,989	 	 	—	 	 	1,989	 	 	 	
 	 	Loss on disposal of inventory and other property	 	 	—	 	 	564	 	 	1,076	 	 	1,658	 	 	 	
 	 	Unsuccessful well costs	 	 	90	 	 	74	 	 	59,401	 	 	102,792	 	 	 	
 	 	Doubtful accounts expense	 	 	—	 	 	—	 	 	39,782	 	 	39,782	 	 	 	
 	 	Derivative related activity	 	 	—	 	 	—	 	 	34,545	 	 	34,545	 	 	 	
 	 	Unit-based compensation	 	 	3,671	 	 	3,468	 	 	13,791	 	 	21,393	 	 	 	
 	 	Leasehold impairment	 	 	—	 	 	—	 	 	—	 	 	3,000	 	 	 	
 	 	Changes in assets and liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Increase in receivables	 	 	(28,701	)	 	(34,531	)	 	(100,605	)	 	(186,747	)	 	 	
 	 	 	Increase in inventories	 	 	(2,412	)	 	(14,465	)	 	(12,699	)	 	(32,541	)	 	 	
 	 	 	(Increase) decrease in prepaid expenses and other	 	 	(88	)	 	61	 	 	(12,429	)	 	(12,671	)	 	 	
 	 	 	Increase in accounts payable	 	 	7,051	 	 	80,883	 	 	65,800	 	 	163,494	 	 	 	
 	 	 	Increase in accrued liabilities	 	 	2,376	 	 	9,877	 	 	11,929	 	 	38,069	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net cash used in operating activities	 	 	(65,671	)	 	(27,591	)	 	(191,800	)	 	(331,009	)	 	 	
Investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas assets	 	 	(156,283	)	 	(411,939	)	 	(444,712	)	 	(1,068,405	)	 	 	
Other property	 	 	(3,799	)	 	(6,376	)	 	(1,452	)	 	(14,038	)	 	 	
Leasehold acquisition	 	 	—	 	 	—	 	 	—	 	 	(3,831	)	 	 	
Contribution to investment under equity method	 	 	—	 	 	—	 	 	—	 	 	(16,983	)	 	 	
Increase in cash due to acquisition	 	 	—	 	 	—	 	 	—	 	 	893	 	 	 	
Deferred organizational costs	 	 	—	 	 	—	 	 	—	 	 	(773	)	 	 	
Notes receivable	 	 	—	 	 	(52,078	)	 	(61,811	)	 	(113,889	)	 	 	
Restricted cash	 	 	3,200	 	 	(30,000	)	 	(82,000	)	 	(112,000	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net cash used in investing activities	 	 	(156,882	)	 	(500,393	)	 	(589,975	)	 	(1,329,026	)	 	 	
Financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Borrowings under long-term debt	 	 	—	 	 	285,000	 	 	760,000	 	 	1,045,000	 	 	 	
Net proceeds from issuance of units	 	 	332,656	 	 	325,344	 	 	—	 	 	824,986	 	 	 	
Debt issue costs	 	 	(1,572	)	 	(90,649	)	 	(17,315	)	 	(109,536	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by financing activities	 	 	331,084	 	 	519,695	 	 	742,685	 	 	1,760,450	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net increase (decrease) in cash and cash equivalents	 	 	108,531	 	 	(8,289	)	 	(39,090	)	 	100,415	 	 	 	
Cash and cash equivalents at beginning of period	 	 	39,263	 	 	147,794	 	 	139,505	 	 	—	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	 	$	147,794	 	$	139,505	 	$	100,415	 	$	100,415	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Supplemental cash flow information	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash paid for:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Interest	 	$	12	 	$	6,765	 	$	52,472	 	$	59,273	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Income taxes (net of refunds received)	 	$	856	 	$	(65	)	$	762	 	$	1,553	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Non cash activity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Deemed repayment and termination of notes receivable	 	$	—	 	$	—	 	$	90,197	 	$	90,197	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-6

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Comprehensive Loss

	 	 

	 	Period
April 23, 2003
(Inception)
Through
December 31
2010	 	 	
 
	 	Years Ended December 31	 	 	 	 	 	
 
	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	
Net loss	 	$	(48,085	)	$	(79,747	)	$	(245,672	)	$	(482,872	)	 	 	
Other comprehensive income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Change in fair value of cash flow hedges	 	 	—	 	 	—	 	 	(4,838	)	 	(4,838	)	 	 	
 	Loss on cash flow hedge included in operations	 	 	—	 	 	—	 	 	5,426	 	 	5,426	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Other comprehensive income	 	 	—	 	 	—	 	 	588	 	 	588	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Comprehensive loss	 	$	(48,085	)	$	(79,747	)	$	(245,084	)	$	(482,284	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-7

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements

1. Organization

        Kosmos Energy Holdings is a privately held Cayman Islands company that was formed March 5, 2004. As a holding company, its management operations are conducted through a wholly-owned subsidiary, Kosmos Energy, LLC. Kosmos Energy, LLC is a privately held Texas limited liability company that was formed April 23, 2003. Kosmos Energy, LLC became a wholly-owned subsidiary of Kosmos Energy Holdings on March 9, 2004. The terms "Kosmos," the "Company," "we," "us," "our," "ours," and similar terms refer to Kosmos Energy Holdings and its wholly-owned subsidiaries, unless the context indicates otherwise. We are an independent oil and gas exploration and production company focused on underexplored regions in Africa.

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

        On August 29, 2003, contributions were made by the seven founding partners in the amount of $350 thousand, for which they received 350,000 units in Kosmos Energy, LLC. On March 9, 2004, the seven founding partners exchanged their 350,000 units in Kosmos Energy, LLC for 3,500,000 units in Kosmos Energy Holdings.

        On October 9, 2009, upon execution and delivery and per Section 1.4 of the Kosmos Energy Holdings Second Amended and Restated Contribution Agreement, the Company issued a total of 2,500,000 C1 common units ("C1 Common Units") to the Series C Convertible Preferred investors. The proceeds of $25 million from the November 2, 2009 issuance of Series C Convertible Preferred Units ("Series C") was allocated on a relative fair value basis between the C1 Common Units and the Series C of $11.8 million and $13.2 million, respectively. See Note 13—Convertible Preferred Units.

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

        As of December 31, 2010, Kosmos Energy Holdings has nine members on the Board of Managers (directors). Warburg Pincus and The Blackstone Group appointed two directors each, one director is a company executive, and there are four independent directors.

2. Accounting Policies

Principles of Consolidation

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

Use of Estimates

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

Cash and Cash Equivalents

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

F-8

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

Restricted Cash

        At December 31, 2009 and 2010, Kosmos had a total of $30.0 million and $112.0 million of restricted cash on hand included in current and long-term assets. In accordance with our project financing commercial debt facilities agreement, we have the following types of restricted cash on hand: (1) a balance at all times of not less than $30.0 million is required during the year prior to Project Completion of the Jubilee Phase 1 Development (as defined in the agreement); (2) not less than $50.0 million in the Reserve Equity account which may only be withdrawn from the account to pay Jubilee Phase 1 costs under certain circumstances, or after Project Completion is available for withdrawal; and (3) not less than $9.0 million in the Stamp Duty Reserve account which may be utilized to meet any payment of stamp duty taxes in Ghana. We have the option to invest the restricted cash in an account which is satisfactory to the facility agents. As of December 31, 2010, $80.0 million was classified as current to offset maturing debt. This restricted cash will be released after Project Completion in mid-2011. The remaining $9.0 million is included in long-term assets.

        Effective December 30, 2010, Kosmos Energy Finance provided a $23.0 million cash collateralized irrevocable standby Letter of Credit ("LOC") in respect of Kosmos Ghana's Jubilee paying interest share of Tullow Ghana Limited's LOC related to their drilling contract for the Eirik Raude. The LOC expires on September 14, 2011. As of December 31, 2010, the LOC is included in long-term assets as it relates to oil and gas properties.

Receivables

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

Inventories

        Inventories were comprised of $19.6 million and $25.2 million of materials and supplies and zero and $12.5 million of hydrocarbons as of December 31, 2009 and 2010, respectively. The Company's materials and supplies inventory is primarily comprised of casing and wellheads and is stated at the lower of cost, using the weighted average cost method or market. Write downs of zero and $1.1 million as of December 31, 2009 and 2010, respectively, for materials and supplies were recorded as reductions to the carrying values for materials and supplies inventories in the Company's consolidated balance sheets and as other expenses, net in the accompanying consolidated statement of operations.

        Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or market. Hydrocarbon inventory costs include expenditures and other charges (including depletion) directly and indirectly incurred in bringing the inventory to its existing condition. Selling expenses and general and administration expenses are reported as period costs and excluded from inventory costs.

F-9

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

Exploration and Development Costs

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

        During the years ended December 31, 2008, 2009 and 2010, Kosmos recognized exploration expense of $15.4 million, $22.1 million and $73.1 million, respectively.

Depletion, Depreciation and Amortization

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

        As of December 31, 2010, depletion costs of $6.4 million are recorded in inventory on the consolidated balance sheets. Oil production commenced on November 28, 2010 and we received revenues from oil production in early 2011 at which time depletion costs were transferred to the consolidated statements of operations.

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

	 	Years
Depreciated	
Leasehold improvements	 	6	
Office furniture, fixtures and computer equipment	 	3 to 7	
Vehicles	 	5	
        Amortization of debt issue costs is computed using the straight-line method over the life of the related commercial debt facilities. Amortization of other assets is computed using the straight-line method over an estimated useful life of five years.

Capitalized Interest

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

F-10

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

Asset Retirement Obligations

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

Investments in Nonconsolidated Companies

        The Company uses the equity method of accounting for long-term investments for which it owns between 20% and 50% of the investee's outstanding voting shares or has the ability to exercise significant influence over operating and financial policies of the investee. The equity method requires periodic adjustments to the investment account to recognize our proportionate share in the investee's results, reduced by receipt of the investee's dividends.

Variable Interest Entity

        A variable interest entity ("VIE"), as defined by FASB ASC 810—Consolidation, is an entity that by design has insufficient equity to permit it to finance its activities without additional subordinated financial support or equity holders that lack the characteristics of a controlling financial interest. VIE's are consolidated by the primary beneficiary, which is the entity that has the power to direct the activities of the VIE that most significantly impact the VIE's performance and will absorb losses, or receive benefits from the VIE that could potentially be significant to the VIE. Kosmos Energy Finance, a wholly-owned subsidiary whose ultimate parent is Kosmos Energy Holdings, meets the definition of a VIE and the Company is the primary beneficiary. As a result, Kosmos Energy Finance is consolidated in these financial statements. Kosmos Energy Finance's assets and liabilities are shown separately on the face of the consolidated balance sheets in the following line items: current and long-term restricted cash; debt issue costs; long-term derivatives asset; current and long-term debt; and current and long-term derivatives liabilities. Included in cash and cash equivalents is $58.0 million related to Kosmos Energy Finance.

Impairment of Long-Lived Assets

        The Company reviews its long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. FASB ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable

F-11

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

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

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

Derivative Instruments and Hedging Activities

        We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of deferred premium puts and compound options (calls on puts). We also use interest rate swap contracts to mitigate our exposure to interest rate fluctuations related to our commercial debt facilities. Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We do not apply hedge accounting to our oil derivative contracts and effective June 1, 2010 discontinued hedge accounting on our interest rate swap contracts and accordingly the changes in the fair value of the instruments are recognized in income in the period of change. See Note 11—Derivative Financial Instruments.

Estimates of Proved Oil and Natural Gas Reserves

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

•
the engineering and geological interpretation of available data;

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

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

•
the judgments of the persons preparing the estimates.

Revenue Recognition

        We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known

F-12

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

in the industry as a production imbalance. Oil production commenced on November 28, 2010 and we received revenues from oil production in early 2011. As of December 31, 2010, no revenues have been recognized in our financial statements.

Income Taxes

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

Foreign Currency Translation

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

Profit Units

        The Company issues common units designated as profit units at various times to employees and certain directors with a threshold value of $0.85 to $90. The Company accounts for these units using FASB ASC 718—Compensation—Stock Compensation. The fair value of the profit units is expensed and recognized on a straight-line basis over the vesting periods of the awards. See Note 18—Profit Units.

Employees

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

Recent Accounting Standards

        In June 2009, the FASB issued Statement of Financial Accounting Standards ("SFAS") No. 166, "Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140." This Statement was codified into FASB ASC 860—Transfers and Servicing. This Statement removes the concept of qualifying special purpose entity ("SPE") and the exception for qualifying SPEs from the consolidation guidance. Additionally, the Statement clarifies the requirements for financial asset transfers eligible for sale accounting. The Company adopted this Statement on its effective date, January 1, 2010, and it did not have a material impact on the Company's financial position or results of operations.

F-13

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

        Also in June 2009, the FASB issued SFAS No. 167, "Amendments to FASB Interpretation No. 46(R)," to address the effects of the elimination of the qualifying SPE concept in SFAS No. 166, and other concerns about the application of key provisions of consolidation guidance for VIEs. This Statement was codified into FASB ASC 810—Consolidation. More specifically, SFAS No. 167 requires a qualitative rather than a quantitative approach to determine the primary beneficiary of a VIE, it amends certain guidance pertaining to the determination of the primary beneficiary when related parities are involved, and it amends certain guidance for determining whether an entity is a VIE. Additionally, this Statement requires continuous assessments of whether an enterprise is the primary beneficiary of a VIE. The Company adopted this Statement on its effective date, January 1, 2010, and it did not have a material impact on the Company's financial position or results of operations.

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

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

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

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

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

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

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

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

F-14

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

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

        In 2005, the Company acquired, through its wholly-owned subsidiary PNR Nigeria (320) Limited (subsequently renamed Kosmos Energy Nigeria (320) Limited), a 41.17647% interest in Pioneer Natural Resources (Nigeria) 320 Limited (subsequently renamed Kosmos Energy Deepwater Nigeria Limited—"KEDNL"). Between 2005 and 2007, Kosmos made capital contributions on its investment of $17.0 million. On July 16, 2007, Pioneer Natural Resources announced its decision to divest its interest in the OPL 320 block offshore Nigeria and took a charge on its investment. Kosmos recognized an impairment in 2006 of $4.0 million of its investment in Pioneer Natural Resources (Nigeria) 320 Limited, bringing its balance to zero.

        In September 2007, the Company, per an agreement with PNR Nigeria, acquired PNR Nigeria's interest in KEDNL. Kosmos Energy NHC I, a subsidiary of Kosmos Energy Holdings, now indirectly holds 100% of the stock of KEDNL. The transaction was accounted for as a business combination. No goodwill was recorded as a result of this transaction and no consideration was paid. The fair value of the assets obtained, consisting of cash, prepaid expenses and property and equipment was $2.1 million. The fair value of the accrued liabilities assumed was $2.1 million.

        On June 29, 2009, Kosmos provided notice of its withdrawal from OPL 320 to the Nigerian government and its block partners. The effective date of the withdrawal was July 31, 2009. All of the Company's Nigerian subsidiaries were dissolved as of November 16, 2010.

4. Notes Receivable

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

        Effective May 7, 2010, Tullow Ghana Limited ("TGL"), acting on behalf of the Unitization and Unit Operating Agreement ("UUOA") parties, entered into the Advance Payments Agreement with MODEC related to partially financing the construction of the FPSO facility. The payments limit for the Advance Payments Agreement is $466.3 million of which Kosmos Ghana's share is $122.2 million. Of the $466.3 million, a total of $341.1 million was deemed to have been advanced from TGL to MODEC. This amount included $188.9 million, principal and interest, related to the loan agreements, $127.3 million representing cash calls made between January 2010 and May 7, 2010, by MODEC to TGL under the Letter of Intent and $25.0 million representing the payment made by TGL for the variation order request 025 dated January 15, 2010, to enable MODEC to pay fees in connection with its long-term financing. MODEC is required to repay TGL the earlier of September 15, 2011 or the date of the first drawdown under MODEC's long-term financing. TGL is required, based on the terms of the joint operating agreement for the Jubilee Unit, to reimburse us the amounts MODEC reimburses to TGL within ten business days of repayment by MODEC. As of December 31, 2010,

F-15

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

4. Notes Receivable (Continued)

Kosmos Ghana's share of the payments made under the Advance Payments Agreement is $113.9 million (includes accrued interest of $0.3 million) and is recorded as notes receivable.

5. Jubilee Field Unitization

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

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

        Pursuant to the requirements of the WCTP and DT Petroleum Agreements, Kosmos Ghana (for the WCTP Block) and Tullow Ghana Limited (for the DT Block) submitted a declaration of commerciality for each block and a plan for the initial phase of development of the Jubilee Field ("Jubilee PoD") to Ghana's Ministry of Energy in late 2008. A declaration of commerciality is a formal designation made pursuant to each of the Petroleum Agreements. Pursuant to discussions between Jubilee Unit partners, GNPC and the Ministry of Energy, the contractor parties for the two blocks resubmitted a revised Jubilee PoD to GNPC who then submitted it to the Ministry of Energy for

F-16

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

5. Jubilee Field Unitization (Continued)

approval in April 2009. On July 13, 2009, the Ministry of Energy provided its written approval of the Jubilee Field Phase 1 Development Plan. Jubilee Field development operations are ongoing.

6. Joint Interest Billings

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

7. Property and Equipment

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

	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Oil and gas properties, net:	 	 	 	 	 	 	 	
 	Proved properties	 	$	251,814	 	$	426,831	 	
 	Unproved properties	 	 	128,557	 	 	198,149	 	
 	Support equipment and facilities	 	 	214,720	 	 	371,319	 	
 	Less: accumulated depletion	 	 	—	 	 	(6,430	)	
 	 	 	 	 	 	
 	 	$	595,091	 	$	989,869	 	
 	 	 	 	 	 	
Other property, net:	 	 	 	 	 	 	 	
 	Leasehold improvements	 	$	5,041	 	$	4,978	 	
 	Computer equipment and software	 	 	3,539	 	 	4,947	 	
 	Office equipment and furniture	 	 	3,529	 	 	3,549	 	
 	Less: accumulated depreciation	 	 	(3,193	)	 	(5,343	)	
 	 	 	 	 	 	
 	 	$	8,916	 	$	8,131	 	
 	 	 	 	 	 	
        The Company recorded $0.6 million, $1.9 million and $2.2 million of depreciation expense for the years ended December 31, 2008, 2009 and 2010, respectively.

8. Suspended Well Costs

        The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or is impaired. The capitalized exploratory well costs are presented in oil

F-17

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

8. Suspended Well Costs (Continued)

and gas properties in the consolidated balance sheets. If the exploratory well is determined to be impaired, the well costs are charged to expense.

        The following table reflects the Company's capitalized exploratory well activities during the years ended December 31, 2008, 2009 and 2010, respectively. The table excludes costs related to exploratory dry holes of $56.0 million which were incurred and subsequently expensed in 2010.

	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Beginning balance	 	$	11,938	 	$	71,883	 	$	114,307	 	
Additions to capitalized exploratory well costs pending the determination of proved reserves	 	 	59,945	 	 	508,197	 	 	55,706	 	
Reclassification due to determination of proved reserves	 	 	—	 	 	(465,773	)	 	—	 	
Capitalized exploratory well costs charged to expense	 	 	—	 	 	—	 	 	(2,502	)	
 	 	 	 	 	 	 	 	
Ending balance	 	$	71,883	 	$	114,307	 	$	167,511	 	
 	 	 	 	 	 	 	 	
        The following table provides aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands, except well counts)
	 	
Exploratory well costs capitalized for a period of one year or less	 	$	59,945	 	$	91,909	 	$	49,022	 	
Exploratory well costs capitalized for a period greater than one year	 	 	11,938	 	 	22,398	 	 	118,489	 	
 	 	 	 	 	 	 	 	
Ending balance	 	$	71,883	 	$	114,307	 	$	167,511	 	
 	 	 	 	 	 	 	 	
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	 	 	2	 	 	1	 	 	6	 	
 	 	 	 	 	 	 	 	
        As of December 31, 2010, the exploratory well costs capitalized in excess of one year since the completion of drilling relate to the Odum-1, Odum-2, Mahogany-3, Mahogany-4 and Mahogany Deep-2 exploration wells in the WCTP Block and Tweneboa-1 well in the DT Block. All costs incurred are approximately one to two years old.

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

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

8. Suspended Well Costs (Continued)

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

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

9. Accounts Payable and Accrued Liabilities

        At December 31, 2009 and 2010, $97.8 million and $163.5 million were recorded for invoices received but not paid in 2009 and 2010, respectively. Accrued liabilities were $41.8 million and $53.2 million at December 31, 2009 and 2010, respectively. Accrued liabilities consist of the following:

	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Accrued liabilities:	 	 	 	 	 	 	 	
 	Accrued exploration and development	 	$	34,723	 	$	26,843	 	
 	Accrued general and administrative expenses	 	 	2,236	 	 	23,393	 	
 	Accrued debt issue costs	 	 	3,232	 	 	—	 	
 	Taxes other than income	 	 	979	 	 	1,936	 	
 	Accrued interest	 	 	—	 	 	655	 	
 	Income taxes	 	 	640	 	 	381	 	
 	 	 	 	 	 	
 	 	$	41,810	 	$	53,208	 	
 	 	 	 	 	 	
10. Commercial Debt Facilities

        On July 13, 2009, Kosmos signed definitive documentation for $750 million project finance commercial debt facilities. The security package for the facilities included, among other things and subject to necessary consents, a pledge collateralization over the shares of the Company's subsidiaries, Kosmos Energy Development and Kosmos Ghana, and an assignment by way of security of their interest in the WCTP and DT Petroleum Agreements. The facilities were amended effective October 29, 2009, by revising the conditions precedent to initial utilization by putting in place an alternative security package that included a charge over the shares of additional subsidiaries of the Company. The Company completed an internal reorganization that included the interposition of a new subsidiary, Kosmos Energy Operating ("KEO"), between Kosmos Energy Holdings and the following subsidiaries: Kosmos Energy International, Kosmos Energy Development, Kosmos Ghana, Kosmos Energy Finance, Kosmos Energy Offshore Morocco HC, Kosmos Energy Cameroon HC, Longhorn Offshore Drilling Ltd. and Kosmos Energy Cote d'Ivoire. Kosmos Energy Holdings granted a charge over the shares of KEO to the lenders in order to secure the facilities. The facilities were further amended on December 24, 2009, increasing the total commercial debt facilities for up to $900.0 million,

F-19

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

10. Commercial Debt Facilities (Continued)

($825.0 million was committed as of December 31, 2009) and adding a new lender as a party to the facilities agreement. On March 31, 2010, Kosmos delivered a request notice to the senior facility agent to increase the commitment under the commercial debt facilities for the remaining $75.0 million by adding a new lender. The conditions set forth in the commercial debt facilities were met and both the increase and new lender were approved as of April 27, 2010. Effective August 23, 2010, the Company signed definitive documentation to increase the facilities by $350.0 million, raising the total amount of its debt commitments to $1.25 billion.

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

        The amount of funds available to be borrowed under the senior facilities, the Borrowing Base Amount, is determined twice a year on June 15 and December 15 of each year as part of the Forecast that is prepared and agreed by the Company and the Technical and Modeling Banks. The formula to calculate the Borrowing Base Amount is based, in part, on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages. As of December 31, 2010, borrowings against the commercial debt facilities totaled $1.05 billion, of which $970.0 million is senior debt and $75.0 million is junior debt. As of December 31, 2010, the availability under our commercial debt facilities was $203.0 million, with $205.0 million of committed undrawn capacity provided for in such facilities (with the difference being the result of borrowing base constraints). See Note 21—Subsequent Events.

        The interest is the aggregate of the applicable margin (5% to 6% on the senior facilities and 9% to 9.5% on the junior facilities); LIBOR; and mandatory cost (if any, as defined in the relevant documentation). Interest on each loan is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). The Company pays commitment fees on the undrawn and uncancelled portion of the total commitments. Commitment fees for the senior and junior lenders are equal to 50% per annum of the then applicable respective margin. Interest expense was $2.0 million and $39.0 million (net of capitalized interest of $0.6 million and $9.8 million) and commitment fees were $4.8 million and $8.2 million for the years ended December 31, 2009 and 2010, respectively.

        Certain facilities contain certain financial covenants, which include:

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

•
After project completion, maintenance of:

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

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

10. Commercial Debt Facilities (Continued)

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

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

in each case, as calculated on the basis of all available information. The "funding sufficiency ratio" is broadly defined, for each applicable calculation period, as the ratio of (x) available funding through the assumed completion date, being the sum of the total available commitments under our commercial debt facilities, the balance of certain accounts securing our commercial debt facilities and the amount of any additional indebtedness permitted under our commercial debt facilities, to (y) total costs through the assumed completion date, being the forecasted project costs, interests and principal payments on, and costs in connection with, our commercial debt facilities, hedging payments in connection with required hedges under our commercial debt facilities, taxes payable and any other costs, fees and expenses incurred in connection with carrying out the Jubilee Field Phase 1 development. The "debt service coverage ratio" is broadly defined, for each applicable forecast period, as the ratio of (x) net cash flow for that period, to (y) aggregate costs of financing the project under our commercial debt facilities, including interest, principal, fees and expenses payable for such period. The "field life cover ratio" is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of net cash flow through the depletion of the Jubilee Field plus the net present value of capital expenditures incurred in relation to the Jubilee Phase I development and funded under our commercial debt facilities, to (y) the aggregate loan amounts outstanding under the senior facility. The "loan life cover ratio" is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of net cash flow through the maturity date of the commercial debt facilities plus the net present value of capital expenditures incurred in relation to the Jubilee Phase I development and funded under our commercial debt facilities, to (y) the aggregate loan amounts outstanding under the senior facility.

        Kosmos has the right to cancel all the undrawn commitments under the facilities if such cancellation is simultaneous with the full repayment of all outstanding loans made under the facilities. The amount of funds available to be borrowed under the senior facilities, also known as the borrowing base amount, is determined on June 15 and December 15 of each year as part of a forecast that is prepared and agreed by Kosmos and the Technical and Modeling Banks. The formula to calculate the borrowing base amount is based, in part, on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages.

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

        Our payment obligations under the commercial debt facilities are secured by a charge over the shares of subsidiaries' of the Company as described above. The commercial debt facilities contain limitations on our activities, which among other things include incurring additional indebtedness; making distributions or payment of dividends or certain other restricted payments or investments; making certain payments on indebtedness; selling or otherwise disposing of assets; and merger, consolidation or sales of substantially all of our assets. At December 31, 2010, the Company's subsidiaries' had $119.8 million in cash and cash equivalents and restricted cash that could not be used for cash dividend payments, loans or advances to Kosmos Energy Holdings.

F-21

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

10. Commercial Debt Facilities (Continued)

        At December 31, 2010, the scheduled maturities of debt during the next five years and thereafter are as follows:

	 	Payments Due By Year	 	
 
	 	2011	 	2012	 	2013	 	2014	 	2015	 	Thereafter	 	
 
	 	(In thousands)
	 	
Commercial debt facilities(1)	 	$	245,000	 	$	250,000	 	$	200,000	 	$	175,000	 	$	100,000	 	$	75,000	 	

(1)
Pursuant to the terms in the commercial debt facilities, when any junior debt is outstanding, repayments may be required to be made under the agreement, whereby 75% of any funds remaining on any repayment date, after required payments are made, will be applied to prepay the junior facilities and the remaining 25% will be applied to prepay the senior facilities. The table of scheduled maturities assumes the outstanding borrowings under the junior facilities will be repaid on June 15, 2016. If repayments are required as noted above, amortization of the junior facilities will occur through such repayments.

        Debt issue costs associated with the facilities were $92.2 million and $109.5 million at December 31, 2009 and 2010, respectively. The Company amortizes debt issue costs using the straight-line method over the life of the facilities. Amortization expense of zero, $2.5 million and $28.8 million were recorded for the years ended December 31, 2008, 2009 and 2010, respectively.

11. Derivative Financial Instruments

        The Company uses financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes.

        The Company applies the provisions of the FASB ASC 815—Derivatives and Hedging, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss ("AOCI(L)") within equity until such time as the hedged item is recognized in earnings. In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically.

        The Company does not apply hedge accounting treatment to its oil derivative contracts and therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts are shown in our statement of operations.

        Effective June 1, 2010, the Company discontinued hedge accounting on all interest rate derivative instruments. Therefore, the Company will recognize, from that date forward, all changes in the fair values of its interest rate swap derivative contracts as gains or losses in the results of the period in which they occur.

F-22

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

11. Derivative Financial Instruments (Continued)

        The effective portions of the discontinued hedges as of May 31, 2010 are included in AOCI(L), in the equity section of the accompanying consolidated balance sheets, and are being transferred to earnings when the hedged transaction is recognized in earnings. Any ineffective portion of the mark-to-market gain or loss was recognized in earnings.

Oil Derivative Contracts

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

        The Company manages and controls market and counterparty credit risk in accordance with policies and guidelines approved by the Board. In accordance with these policies and guidelines, the Company's executive management determines the appropriate timing and extent of derivative transactions. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification. All of our commodity derivative contracts are with parties that are lenders under our commercial debt facilities. We have included an estimate of nonperformance risk in the fair value measurement of our commodity derivative contracts as required by the FASB ASC 820—Fair Value Measurements and Disclosures. At December 31, 2010, the net liability of commodity derivative contracts was reduced by $2.7 million for estimated nonperformance risk.

        The following table sets forth as of December 31, 2010 the volumes in barrels ("bbl") underlying the Company's outstanding oil derivative contracts and the weighted average Dated Brent prices per bbl for those contracts:
 	 	 	 	 	 	 	 	 	 	 	 	
Type of Contract and Period	 	bbl/day	 	Weighted
Average
Floor Price	 	Weighted
Average
Deferred
Premium/bbl	 	
Deferred Premium Puts	 	 	 	 	 	 	 	 	 	 	
 	July 2011 - December 2011	 	 	11,332	 	$	72.01	 	$	8.90	 	
 	January 2012 - December 2012	 	 	4,625	 	$	62.74	 	$	7.04	 	
 	January 2013 - December 2013	 	 	2,515	 	$	61.73	 	$	7.32	 	
Compound Options (calls on puts)	 	 	 	 	 	 	 	 	 	 	
 	July 2012 - December 2012(1)	 	 	5,399	 	$	66.48	 	$	6.73	 	
 	January 2013 - June 2013(1)	 	 	3,855	 	$	66.48	 	$	7.10	 	

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

Interest Rate Swaps Derivative Contracts

        In 2010, the Company entered into derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under its commercial debt facilities to a weighted average fixed rate. The following table

F-23

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

11. Derivative Financial Instruments (Continued)

summarizes our open interest rate swaps as of December 31, 2010, all of which were entered into as required under the terms of our commercial debt facilities and are with parties that are lenders under our commercial debt facilities:
 	 	 	 	 	 	 	 	 	
Term	 	Notional Amount	 	Fixed Rate	 	Floating Rate	
 
	 	(In thousands)

	
January 2011 - June 2016	 	$	161,250	 	 	2.22	%	6-month LIBOR	
January 2011 - June 2016	 	$	161,250	 	 	2.31	%	6-month LIBOR	
January 2011 - June 2014	 	$	77,500	 	 	0.98	%	6-month LIBOR	
January 2011 - June 2015	 	$	75,000	 	 	1.34	%	6-month LIBOR	
        Effective June 1, 2010, the Company discontinued hedge accounting on all existing interest rate derivative instruments. Prior to June 1, 2010, any ineffectiveness on the interest rate swaps was immaterial therefore no amount was recorded in earnings for ineffectiveness. We have included an estimate of nonperformance risk in the fair value measurement of our interest rate derivative contracts as required by the FASB ASC 820—Fair Value Measurements and Disclosures. At December 31, 2010, the net liability of interest rate derivative contracts was reduced by $0.5 million for estimated nonperformance risk.

        All of the Company's derivatives were made up of non-hedge derivatives as of December 31, 2010. The following tables provide disclosure of the Company's derivative instruments:
 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair Value of Derivative Instruments as of December 31, 2010	 	
 
	 	Asset Derivatives	 	Liability Derivatives	 	
Type	 	Balance Sheet Location	 	Fair
Value	 	Balance Sheet Location	 	Fair
Value	 	

	 	(In thousands)
	 	 
	 	(In thousands)
	 	
Derivatives not designated as hedging instruments	 	 	 	 	 	 	 	 	 	 	 	
 	Commodity derivatives	 	Derivatives—current	 	$	—	 	Derivatives—current	 	$	13,979	 	
 	Interest rate derivatives	 	Derivatives—current	 	 	—	 	Derivatives—current	 	 	6,375	 	
 	Commodity derivatives	 	Derivatives—noncurrent	 	 	—	 	Long-term derivatives	 	 	14,340	 	
 	Interest rate derivatives	 	Derivatives—noncurrent	 	 	1,501	 	Long-term derivatives	 	 	764	 	
 	 	 	 	 	 	 	 	 	 	
Total derivatives not designated as hedging instruments	 	 	 	 	1,501	 	 	 	 	35,458	 	
 	 	 	 	 	 	 	 	 	 	
Total derivatives	 	 	 	$	1,501	 	 	 	$	35,458	 	
 	 	 	 	 	 	 	 	 	 	
F-24

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

11. Derivative Financial Instruments (Continued)

        The Company did not have any derivative instruments at December 31, 2009.

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

	 	Years Ended
December 31	 	 	
 
	 	Location of Gain/(Loss)	 	 	 	 	 	
Derivatives in Cash Flow Hedging Relationships	 	 	 	2009	 	2010	 	 	 	 	

	 	(In thousands)
	 	 	 	 	
Interest rate derivatives	 	AOCI(L)	 	$	—	 	$	588	 	 	 	 	

 	 	 	 	 	 	 	 	 	 	 	

	 	Amount of Loss
Reclassified from
AOCI(L) into
Earnings	 	 	

	 	Years Ended
December 31	 	 	
 
	 	Location of Gain/(Loss)
Reclassified from
AOCI(L) into Earnings	 	 	 	 	 	
Derivatives in Cash Flow Hedging Relationships	 	 	 	2009	 	2010	 	 	 	 	

	 	(In thousands)
	 	 	 	 	
Interest rate derivatives	 	Interest expense	 	$	—	 	$	(5,426	)	 	 	 	

 	 	 	 	 	 	 	 	 	 	 	 	

	 	Amount of Gain
(Loss) Recognized in
Earnings on
Derivatives	 	 	

	 	Years Ended
December 31	 	 	
 
	 	Location of Gain (Loss)
Recognized in Earnings
on Derivatives	 	 	 	 	 	
Derivatives Not Designated as Hedging Instruments	 	 	 	2009	 	2010	 	 	 	 	

	 	(In thousands)
	 	 	 	 	
Commodity derivatives	 	Derivatives, net	 	$	—	 	$	(28,319	)	 	 	 	
Interest rate derivatives	 	Interest expense	 	 	—	 	 	(6,967	)	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	
 	Total	 	 	 	$	—	 	$	(35,286	)	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	
        The fair value of the effective portion of the derivative contracts on May 31, 2010 is reflected in AOCI(L) and is being transferred to interest expense over the remaining term of the contracts. In accordance with the mark-to-market method of accounting, the Company will recognize all future changes in fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur. During the twelve months ending December 31, 2011, the Company expects to reclassify $2.9 million of AOCI(L) losses to interest expense. See Note 15—Fair Value Measurements for additional information regarding the Company's derivative instruments.

F-25

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

12. Asset Retirement Obligations

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

	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Asset Retirement Obligations:	 	 	 	 	 	 	 	
 	Beginning asset retirement obligations	 	$	—	 	$	—	 	
 	Liabilities incurred during period	 	 	—	 	 	16,570	 	
 	Revisions in estimated retirement obligations	 	 	—	 	 	—	 	
 	Liabilities settled during period	 	 	—	 	 	—	 	
 	Accretion expense	 	 	—	 	 	182	 	
 	 	 	 	 	 	
 	Ending asset retirement obligations	 	$	—	 	$	16,752	 	
 	 	 	 	 	 	
        The Ghanaian legal and regulatory regime regarding oil field abandonment and other environmental matters is evolving. Currently, no Ghana environmental regulations expressly require that companies abandon or remove offshore assets although under international industry standards we would do so. The Petroleum Law provides for restoration which includes removal of property and abandonment of wells, but further states the manner of such removal and abandonment will be as provided in the Regulations; however, such Regulations have not been promulgated. Under the Environmental Permit for the Jubilee Field, issued to Tullow Ghana, Ltd., a decommissioning plan will be prepared and submitted to the Ghana Environmental Protection Agency. ASC 410 requires the Company to recognize this liability in the period in which the liability was incurred, which we have determined to be the fourth quarter of 2010 with the commencement of production. Accordingly, the Company recognized a liability in the quarterly period ending December 31, 2010 related to our asset retirement obligations.

13. Convertible Preferred Units

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

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

        On October 9, 2009, under the Kosmos Energy Holdings Second Amended and Restated Contribution Agreement, Kosmos secured an additional provisional commitment of up to $250.0 million from Warburg Pincus, The Blackstone Group, the management group, certain accredited employee investors and directors. For each $28.25 contribution, one Series C was issued. Contributions began on November 2, 2009. Upon execution and delivery and per Section 1.4 of the Kosmos Energy

F-26

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

13. Convertible Preferred Units (Continued)

Holdings Second Amended and Restated Contribution Agreement, the Company issued a total of 2,500,000 C1 Common Units to the Series C investors. The proceeds from the Series C issuance were allocated on a relative fair value basis between the Series C and the C1 Common Units, which created a discount on the Series C of approximately $11.8 million. The discount on the Series C has been recorded as of December 31, 2010, the date at which a determination was made that it was probable that an exchange of securities for common shares would occur.

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

	 	Warburg Pincus	 	The Blackstone
Group	 	Other Investors	 	Total	 	
Series A:	 	 	 	 	 	 	 	 	 	 	 	 	 	
2004 Issuance of 1,100 units	 	$	5,958	 	$	4,875	 	$	167	 	$	11,000	 	
2005 Retirement of 6 units	 	 	—	 	 	—	 	 	(63	)	 	(63	)	
2005 Issuance of 3,100 units	 	 	16,551	 	 	13,542	 	 	907	 	 	31,000	 	
2006 Retirement of 9 units	 	 	—	 	 	—	 	 	(85	)	 	(85	)	
2006 Issuance of 2,010 units	 	 	10,775	 	 	8,815	 	 	510	 	 	20,100	 	
2007 Issuance of 10,505 units	 	 	56,506	 	 	46,232	 	 	2,310	 	 	105,048	 	
2008 Issuance of 13,300 units	 	 	71,508	 	 	58,508	 	 	2,984	 	 	133,000	 	
Accumulated preferred return	 	 	44,758	 	 	36,621	 	 	1,867	 	 	83,246	 	
 	 	 	 	 	 	 	 	 	 	
Total Issuances—Series A	 	$	206,056	 	$	168,593	 	$	8,597	 	$	383,246	 	
 	 	 	 	 	 	 	 	 	 	
Series B:	 	 	 	 	 	 	 	 	 	 	 	 	 	
2008 Issuance of 7,986 units	 	$	107,718	 	$	88,132	 	$	3,806	 	$	199,656	 	
2009 Issuances of 12,014 units	 	 	161,576	 	 	132,199	 	 	6,569	 	 	300,344	 	
Accumulated preferred return	 	 	36,712	 	 	30,037	 	 	1,414	 	 	68,163	 	
 	 	 	 	 	 	 	 	 	 	
Total Issuances—Series B	 	$	306,006	 	$	250,368	 	$	11,789	 	$	568,163	 	
 	 	 	 	 	 	 	 	 	 	
Series C:	 	 	 	 	 	 	 	 	 	 	 	 	 	
November 2, 2009 Issuance of 885 units	 	$	7,126	 	$	5,830	 	$	288	 	$	13,244	 	
Accretion	 	 	6,325	 	 	5,175	 	 	256	 	 	11,756	 	
Accumulated preferred return	 	 	1,128	 	 	923	 	 	46	 	 	2,097	 	
 	 	 	 	 	 	 	 	 	 	
Total Issuances—Series C	 	$	14,579	 	$	11,928	 	$	590	 	$	27,097	 	
 	 	 	 	 	 	 	 	 	 	
        Under the Fourth Amended and Restated Operating Agreement of Kosmos Energy Holdings (the "Agreement") governing the Company, the holders of the Series A, Series B and Series C (collectively, "Convertible Preferred Units") would receive distributions, if any, equal to the "Accreted Value" of the units, prior to any distributions to the common unit holders. The Accreted Value is defined in the Agreement as the unit purchase price plus the preferred return amount per unit equal to 7% of the Accreted Value per annum (compounded quarterly) for the first seven years after the year of our initial operating agreement and 14% of the Accreted Value per annum (compounded quarterly) thereafter, unless a monetization event (as defined in the Agreement) occurs at which time the preferred return would revert to 7%. The holders of the Convertible Preferred Units will receive the accumulated preferred return upon the consummation of a "Qualified Public Offering" as defined in the Agreement. The accumulated preferred return on the Convertible Preferred Units has been recorded as of December 31, 2010, the date at which a determination was made that it was probable that an exchange

F-27

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

13. Convertible Preferred Units (Continued)

of securities for common shares would occur. The amount was applied to additional paid-in capital first, with the remaining amount applied to the deficit accumulated during development stage.

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

        Upon and immediately prior to the consummation of a Qualified Public Offering, each outstanding Common Unit and each outstanding Convertible Preferred Unit would be exchanged (at values determined in the Agreement) into common shares and preferred shares, respectively, of the "IPO Corporation," as defined in the Agreement. Each preferred share of the IPO Corporation would be exchanged for a combination of cash or common shares of the IPO Corporation equal to the accreted value at the option of the unit holders plus common shares of the IPO Corporation based on the provisions of the Agreement. The Convertible Preferred Units are classified as mezzanine equity as the Company cannot solely control the type of consideration issuable on the exchange and the Convertible Preferred Unit holders control the Company's Board of Directors.

14. Other Income

        Other income consists primarily of technical service fees and overhead expenses billed to third parties for the Jubilee Field per the Pre Unit Agreement through July 13, 2009, and subsequently the UUOA. The expenses associated with these third-party billings are recorded within the general and administrative expense line item in the accompanying consolidated financial statements. Other income under this agreement was $6.0 million, $9.6 million and $5.1 million for the years ended December 31, 2008, 2009 and 2010, respectively.

15. Fair Value Measurements

        In accordance with the FASB ASC 820—Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

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

•
Level 2—quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

15. Fair Value Measurements (Continued)

prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.•
Level 3—unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

        The following table presents the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2010, for each of the fair value hierarchy levels:

	 	Fair Value Measurements at
Reporting Date Using	 	 

	 	Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)	 	Significant
Other
Observable
Inputs
(Level 2)	 	Significant
Unobservable
Inputs
(Level 3)	 	Fair Value at
December 31
2010	 	
 
	 	(In thousands)
	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Money market accounts	 	$	18,056	 	$	—	 	$	—	 	$	18,056	 	
Interest rate derivatives	 	 	—	 	 	1,501	 	 	—	 	 	1,501	 	
 	 	 	 	 	 	 	 	 	 	
 	Total assets	 	$	18,056	 	$	1,501	 	$	—	 	$	19,557	 	
 	 	 	 	 	 	 	 	 	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	$	—	 	$	28,319	 	$	—	 	$	28,319	 	
Interest rate derivatives	 	 	—	 	 	7,139	 	 	—	 	 	7,139	 	
 	 	 	 	 	 	 	 	 	 	
 	Total liabilities	 	$	—	 	$	35,458	 	$	—	 	$	35,458	 	
 	 	 	 	 	 	 	 	 	 	
        All fair values have been adjusted for nonperformance risk resulting in a decrease of the commodity derivative liabilities of approximately $2.7 million and a decrease of the interest rate derivatives of approximately of $0.5 million as of December 31, 2010. When the accumulated net present value for all of the derivative contracts with a counterparty are in an asset position, the Company uses the counterparty's credit default swap ("CDS") rates to estimate non-performance risk. When the accumulated net present value for all derivative contracts for a counterparty are in a liability position, the Company uses its internal rate of borrowing to estimate our non-performance risk.

F-29

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

15. Fair Value Measurements (Continued)

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

	 	December 31, 2009	 	December 31, 2010	 	
 
	 	Carrying
Value	 	Fair Value	 	Carrying
Value	 	Fair Value	 	
 
	 	(In thousands)
	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Money market accounts	 	$	59,757	 	$	59,757	 	$	18,056	 	$	18,056	 	
 	Interest rate derivatives	 	$	—	 	$	—	 	$	1,501	 	$	1,501	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Commodity derivatives	 	$	—	 	$	—	 	$	28,319	 	$	28,319	 	
 	Interest rate derivatives	 	$	—	 	$	—	 	$	7,139	 	$	7,139	 	
        The book values of cash and cash equivalents, joint interest billings, notes and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. The carrying values of our commercial debt facilities approximates fair value since they are subject to short-term floating interest rates that approximate the rates available to the Company for those periods. The Company's long-term receivables after allowance approximate fair value.

Commodity Derivatives

        The Company's commodity derivatives represent crude oil deferred premium puts and compound options for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to the Company's oil derivatives as of December 31, 2010 are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for Dated Brent, (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market and (iv) an independently sourced estimate of volatility for Dated Brent. The volatility estimate is provided by certain independent brokers who are active in buying and selling oil options and were corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the puts and compound options. The Company's commodity derivative liability measurements represent Level 2 inputs in the hierarchy priority. See Note 11—Derivative Financial Instruments for additional information regarding the Company's derivative instruments.

Interest Rate Derivatives

        The Company's interest rate derivatives as of December 31, 2010 represent swap contracts for $475.0 million notional amount of debt, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate. The values attributable to the Company's interest rate derivative contracts as of December 31, 2010 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR rate yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market. The Company's interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy priority.

F-30

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

16. Income Taxes

        The components of earnings (loss) before income taxes were as follows:

	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
United States	 	$	674	 	$	2,497	 	$	1,476	 	
Foreign	 	 	(49,210	)	 	(81,271	)	 	(324,256	)	
 	 	 	 	 	 	 	 	
Ending balance	 	$	(48,536	)	$	(78,774	)	$	(322,780	)	
 	 	 	 	 	 	 	 	
        Kosmos Energy Holdings is a Cayman Island company that is treated as a partnership for U.S. tax purposes. Kosmos Energy Holding's operating subsidiaries in the United States, Ghana, Cameroon and Morocco are subject to taxation in their respective jurisdictions.

        The components of the provision for income taxes were as follows:

	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Current:	 	 	 	 	 	 	 	 	 	 	
 	U.S. federal	 	$	(232	)	$	651	 	$	844	 	
 	State and local	 	 	73	 	 	223	 	 	(338	)	
 	 	 	 	 	 	 	 	
Total current	 	 	(159	)	 	874	 	 	506	 	
Deferred:	 	 	 	 	 	 	 	 	 	 	
 	U.S. federal	 	 	428	 	 	99	 	 	(143	)	
 	Foreign	 	 	—	 	 	—	 	 	(77,471	)	
 	 	 	 	 	 	 	 	
Total deferred	 	 	428	 	 	99	 	 	(77,614	)	
 	 	 	 	 	 	 	 	
Provision (benefit) for income taxes	 	$	269	 	$	973	 	$	(77,108	)	
 	 	 	 	 	 	 	 	
        A reconciliation of the differences between the Company's applicable statutory tax rate and the Company's effective income tax rate follows:

	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
Tax provision at statutory rate (Cayman Islands)	 	 	—	%	 	—	%	 	—	%	
Loss subject to tax benefit in excess of statutory rate	 	 	22.39	 	 	18.24	 	 	23.19	 	
Change in valuation allowance	 	 	(22.73	)	 	(19.25	)	 	1.12	 	
Other	 	 	(0.21	)	 	(0.22	)	 	(0.42	)	
 	 	 	 	 	 	 	 	
Consolidated effective tax rate	 	 	(0.55	)%	 	(1.23	)%	 	23.89	%	
 	 	 	 	 	 	 	 	
        Deferred taxes reflect the tax effects of differences between the amounts recorded as assets and liabilities for financial reporting purposes and the amounts recorded for income tax purposes. The tax

F-31

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

16. Income Taxes (Continued)

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

	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Deferred tax assets:	 	 	 	 	 	 	 	
 	Ghana foreign capitalized operating expenses	 	$	20,591	 	$	8,473	 	
 	Foreign net operating losses	 	 	15,552	 	 	134,090	 	
 	Other	 	 	488	 	 	6,007	 	
 	 	 	 	 	 	
Total deferred tax assets	 	 	36,631	 	 	148,570	 	
Deferred tax liabilities:	 	 	 	 	 	 	 	
 	Depletion, depreciation and amortization	 	 	(653	)	 	(36,900	)	
 	Intangible drilling costs	 	 	(2,563	)	 	(4,243	)	
 	Other	 	 	(192	)	 	(200	)	
 	 	 	 	 	 	
Total deferred tax liabilities	 	 	(3,408	)	 	(41,343	)	
Valuation allowance	 	 	
(33,749	
)	 	
(30,140	
)	
 	 	 	 	 	 	
Net deferred tax asset (liability)	 	$	(526	)	$	77,087	 	
 	 	 	 	 	 	
        The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. During 2008, the Company determined that it was more likely than not that the net deferred tax asset for its U.S. operations would be realized in the amount of $79 thousand. Based on various factors including the commencement of start-up operations, the placing into service the equipment and infrastructure necessary to lift and store oil, the production of oil beginning on November 28, 2010, the Company's forecast of future production and estimates of future taxable income from the related oil sales, the Company determined that it was more likely than not that the deferred tax asset for its Ghana operations would be realized. The total deferred tax asset realized in Ghana was approximately $20.6 million. The change in the valuation allowance of $3.6 million is due to the release of the Ghana valuation allowance netted against current year activity in Morocco and Cameroon.

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

        The Company has foreign net operating loss carryforwards of approximately $58.9 million which begin to expire in 2011 through 2015 and approximately $298.6 million which do not expire.

F-32

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

16. Income Taxes (Continued)

        Effective January 1, 2009, the Company adopted the provisions of the FASB ASC 740—Income Taxes which clarifies the accounting for and disclosure of uncertainty in tax positions. Additionally, this standard provides guidance on the recognition, measurement, derecognition, classification and disclosure of tax positions and on the accounting for related interest and penalties. As a result of the implementation of this standard, the Company recognized no material adjustment for unrecognized income tax benefits. In addition, there were no material unrecognized income tax benefits recognized during the current year.

        The Company files a U.S. federal income tax return and a Texas margin tax return. In addition to the United States, the Company files income tax returns in the countries in which the Company operates. The Company is open to U.S. federal income tax examinations for tax years 2007 through 2010 and to Texas margin tax examinations for the tax years 2006 through 2010. In addition the Company is open to income tax examinations for years 2004 through 2010 in its significant foreign jurisdictions (Ghana, Cameroon and Morocco).

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

        During 2007, the Company settled an examination by the Internal Revenue Service. The settlement resulted in an adjustment that eliminated the domestic net operating loss carryforward. The Company was required to pay $137 thousand of additional tax related to the exam of the 2005 and 2006 federal income tax returns.

17. 401(k) Plan

        As of July 2007, the Company offers a 401(k) Plan to which employees may contribute tax deferred earnings subject to Internal Revenue Service limitations. Employee contributions of up to 6% of compensation, as defined by the plan, is matched by the Company at 100%. The Company's match is vested immediately. Matching contributions made by the Company to the 401(k) Plan were approximately $315 thousand, $550 thousand and $668 thousand for the years ended December 31, 2008, 2009 and 2010, respectively.

18. Profit Units

        Kosmos issues common units designated as profit units with a threshold value of $0.85 to $90 to employees, management and directors. Profit units, the defined term in the related agreements, are equity awards that are measured on the grant date and expensed over a vesting period of four years. Founding management and directors vest 20% as of the date of issuance and an additional 20% on the anniversary date for each of the next four years. Profit units issued to employees vest 50% on the second and fourth anniversary of the issuance date. Of the 100 million authorized common units,

F-33

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

18. Profit Units (Continued)

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

	 	Profit Units	 	Weighted-Average
Grant-Date
Fair Value	 	
 
	 	(In thousands)

Outstanding at December 31, 2007	 	 	3,984	 	$	0.13	 	
 	Granted	 	 	9,595	 	 	1.11	 	
 	Relinquished	 	 	(67	)	 	1.52	 	
 	 	 	 	 	 	 	
Outstanding at December 31, 2008	 	 	13,512	 	 	0.82	 	
 	Granted	 	 	10	 	 	2.94	 	
 	Relinquished	 	 	(15	)	 	3.05	 	
 	 	 	 	 	 	 	
Outstanding at December 31, 2009	 	 	13,507	 	 	0.81	 	
 	Granted	 	 	411	 	 	5.27	 	
 	Relinquished	 	 	(8	)	 	2.45	 	
 	 	 	 	 	 	 	
Outstanding December 31, 2010	 	 	13,910	 	 	1.76	 	
 	 	 	 	 	 	 	
        A summary of the status of the Company's non-vested profit units is as follows:

	 	Profit Units	 	Weighted-Average
Grant-Date
Fair Value	 	
 
	 	(In thousands)

Non-vested at December 31, 2007	 	 	2,080	 	$	0.22	 	
 	Granted	 	 	9,595	 	 	1.11	 	
 	Vested	 	 	(2,659	)	 	0.66	 	
 	Relinquished	 	 	(67	)	 	1.52	 	
 	 	 	 	 	 	 	
Non-vested at December 31, 2008	 	 	8,949	 	 	1.03	 	
 	Granted	 	 	10	 	 	2.94	 	
 	Vested	 	 	(2,000	)	 	0.90	 	
 	Relinquished	 	 	(15	)	 	3.05	 	
 	Other	 	 	13	 	 	0.02	 	
 	 	 	 	 	 	 	
Non-vested at December 31, 2009	 	 	6,957	 	 	1.06	 	
 	Granted	 	 	411	 	 	5.27	 	
 	Vested	 	 	(2,719	)	 	1.03	 	
 	Relinquished	 	 	(8	)	 	2.45	 	
 	Accelerated vesting	 	 	(1,177	)	 	10.66	 	
 	 	 	 	 	 	 	
Non-vested at December 31, 2010	 	 	3,464	 	 	1.60	 	
 	 	 	 	 	 	 	
        Effective December 31, 2010, James C. Musselman retired as the Company's Chairman and Chief Executive Officer. The Company entered into a retirement agreement with Mr. Musselman on December 17, 2010. Pursuant to the retirement agreement, 1.2 million profit units of Kosmos Energy Holdings that were unvested as of his retirement date became fully vested as of such date resulting in unit-based compensation of $11.5 million in the fourth quarter of 2010.

F-34

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

18. Profit Units (Continued)

        At December 31, 2010, the remaining unrecognized compensation cost from profit units was $3.1 million, which will be recognized over a weighted-average period of 2.3 years. Total profit unit compensation expense recognized in income was $3.7 million, $3.5 million and $13.8 million for the years ended December 31, 2008, 2009 and 2010, respectively.

        The significant assumptions used to calculate the fair values of the profit units granted over the past three years, as calculated using a binomial tree, were as follows: no dividend yield, expected volatility ranging from approximately 25% to 66%, risk-free interest rate ranging from 1.3% to 5.1%, expected life ranging from 1.2 to 8.1 years and projected turnover rate of 7.0% for employees and none for management.

19. Commitments and Contingencies

        As of September 12, 2003, the Company leased office space located at 8401 North Central Expressway, Dallas, Texas. The lease, as amended, expired on September 30, 2009.

        As of June 29, 2008, office lease agreements were signed between Harvest/NPE LP and Kosmos Energy, LLC with respect to spaces located at 8170 Park Lane, Dallas, Texas, referred to as the North Premises and the South Premises. The leases commenced in March 2009 and expire in 2015 and 2014, respectively. At December 31, 2009 and 2010, liabilities of $1.7 million and $1.4 million, respectively, were recorded for tenant improvement allowances. The Company received $2.0 million for leasehold incentives from Harvest/NPE LP in 2009.

        The Company leases other facilities under various operating leases that expire through 2015. Rent expense under these agreements along with the office lease agreements, was $0.9 million, $1.4 million and $1.4 million for the years ended December 31, 2008, 2009 and 2010, respectively.

        Future minimum rental commitments under these leases at December 31, 2010, are as follows:

	 	Office Leases	 	
 
	 	(In thousands)
	 	
2011	 	$	1,615	 	
2012	 	 	1,636	 	
2013	 	 	1,660	 	
2014	 	 	1,168	 	
2015	 	 	382	 	
Thereafter	 	 	—	 	
        On June 23, 2008, Kosmos Ghana signed an offshore drilling contract with Alpha Offshore Drilling Services Company, a wholly-owned subsidiary of Atwood Oceanics, Inc., for the semi-submersible rig, "Atwood Hunter." Noble Energy EG Ltd. ("Noble") also is a party to the contract. The rated water depth capability of the Atwood Hunter is currently 5,000 feet. The initial rig rate is $538 thousand per day and is subject to annual adjustments for cost increases. Effective, July 27, 2009 and 2010, the rig rate was adjusted to $543 thousand and $546 thousand per day, respectively. The contract, as amended, is for 1,152 days, with Kosmos Ghana and Noble allotted 797 days and 355 days, respectively. Kosmos Ghana and Tullow Ghana Limited entered into a rig and services sharing agreement on October 18, 2009, for use of the Atwood Hunter across WCTP and DT Blocks during part of Kosmos Ghana's

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

19. Commitments and Contingencies (Continued)

allocated time. The future minimum commitments under this contract as of December 31, 2010, are (in thousands): 2011—$138,588; and 2012—$133,131.

20. Litigation

        Kosmos Energy Holdings is not party to any litigation or proceedings with respect to the Company's operations which management believes, based on advice of counsel, will either individually or in the aggregate have a materially adverse impact on the Company's financial condition, results of operations or cash flows.

21. Subsequent Events

Commercial Debt Facilities

        In January 2011, the Company borrowed $28.0 million under the senior facilities. As of the date of the financial statements, borrowings against the commercial debt facilities totaled $1.07 billion and the scheduled principal maturities during the next five years and thereafter are (in thousands): 2011—$273,000; 2012—$250,000; 2013—$200,000; 2014—$175,000; 2015—$100,000 and thereafter—$75,000.

Exploration Expenses

        Drilling of the Mombe-1 exploration well was completed in January 2011. The well encountered hydrocarbons in sub-commercial quantities and accordingly will be plugged and abandoned. Total well related costs incurred from inception through December 31, 2010 of $26.1 million are included in exploration expenses in the accompanying consolidated statement of operations. As of the date of the financial statements, the Company estimates we will incur an additional $1.8 million of related well costs.

Exchange of Convertible Preferred Units

        Contemporaneous with the public offering, the holders of the convertible preferred units are expected to exercise their rights, acquired on formation, to exchange all of the outstanding convertible preferred units of the Company to ordinary shares based on the pre-offering equity value of such interests. As a result,                 convertible preferred units outstanding at that date will be exchanged into                ordinary shares. The ordinary shares have                 vote per share and a par value of                . The effects of the exchange of the convertible preferred units are shown in the balance sheet column "Pro Forma."

22. Pro forma Information (Unaudited)

Per share information

        Basic and diluted net loss per share have been calculated using the weighted average number of common shares, on a pro forma basis, assuming conversion of the redeemable preferred units into common shares. The weighted average common shares outstanding have been calculated as if the ownership restructure resulting from the corporate reorganization was in place since inception.

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

22. Pro forma Information (Unaudited) (Continued)

        The following is a reconciliation of the numerators and denominators of the pro forma diluted net loss per share computations (in thousands, except per share data).

	 	Year Ended
December 31
2010	 	
Numerator	 	 	 	 	
Net loss	 	$	 	 	
 	 	 	 	
Denominator	 	 	 	 	
Weighted average shares for basic and diluted net loss per common share	 	 	 	 	
Convertible preferred units	 	 	 	 	
 	 	 	 	
Weighted average shares for pro forma net loss per share	 	 	 	 	
 	 	 	 	
        The following table sets forth the computation of pro forma basic and diluted net loss per share (in thousands, except per share data).

	 	Year Ended
December 31
2010	 	
Numerator	 	 	 	 	
Net loss	 	$	 	 	
 	 	 	 	
Denominator	 	 	 	 	
Weighted average shares for basic and diluted net loss per common share	 	 	 	 	
 	 	 	 	
Pro forma basic and diluted net loss per share	 	 	 	 	

23. Supplementary Oil and Gas Data (Unaudited)

        In January 2010, the FASB issued ASU No. 2010-03—Extractive Activities—Oil and Gas (ASC 932) Oil and Gas Reserve Estimation and Disclosures so as to align the oil and gas reserve estimation and disclosure requirements of Extractive Activities—Oil and Gas (ASC 932) with the requirements in the SEC's final rule, Modernization of the Oil and Gas Reporting Requirements which was issued on December 31, 2008. The Company adopted the update as of December 31, 2009.

        Net proved oil and gas reserve estimates presented were prepared by Netherland, Sewell & Associates, Inc. ("NSAI"), independent petroleum engineers located in Dallas, Texas. The technical persons at NSAI have prepared the reserve estimates presented herein and meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to independent reserve engineers for their reserves review process. The supplementary oil and gas data that follows includes (1) net proved oil and gas reserves, (2) capitalized costs related to oil and gas producing activities, (3) costs incurred for property acquisition, exploration, and development activities, (4) results of operations for oil and gas producing activities, (5) a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, and (6) changes in the standardized measure of discounted future net cash flows. Oil production commenced on November 28, 2010, and we received revenues from oil production in early 2011; therefore, there are no disclosures related to item (4) above for 2010.

Net Proved Developed and Undeveloped Reserves

        The following table is a summary of net proved developed and undeveloped oil and gas reserves to Kosmos' interest in the Jubilee Field Phase 1 development in Ghana.

	 	Oil	 	Gas	 	Total	 	
 
	 	(Mmbbl)
	 	(Bcf)
	 	(Mmboe)
	 	
Net proved undeveloped reserves at December 31, 2008	 	 	—	 	 	—	 	 	—	 	
 	Discoveries and extensions	 	 	55	 	 	—	 	 	55	 	
 	Production	 	 	—	 	 	—	 	 	—	 	
 	Purchases of minerals-in-place	 	 	—	 	 	—	 	 	—	 	
 	 	 	 	 	 	 	 	
Net proved undeveloped reserves at December 31, 2009	 	 	55	 	 	—	 	 	55	 	
 	Discoveries and extensions	 	 	1	 	 	23	 	 	5	 	
 	Production	 	 	—	 	 	—	 	 	—	 	
 	Purchases of minerals-in-place	 	 	—	 	 	—	 	 	—	 	
 	 	 	 	 	 	 	 	
Net proved developed and undeveloped reserves at December 31, 2010	 	 	56	 	 	23	 	 	60	 	
 	 	 	 	 	 	 	 	
Proved developed reserves	 	 	 	 	 	 	 	 	 	 	
 	January 1, 2009	 	 	—	 	 	—	 	 	—	 	
 	December 31, 2009	 	 	—	 	 	—	 	 	—	 	
 	December 31, 2010	 	 	37	 	 	18	 	 	40	 	
Proved undeveloped reserves	 	 	 	 	 	 	 	 	 	 	
 	January 1, 2009	 	 	—	 	 	—	 	 	—	 	
 	December 31, 2009	 	 	55	 	 	—	 	 	55	 	
 	December 31, 2010	 	 	19	 	 	5	 	 	20	 	
        Net proved reserves were calculated utilizing the twelve month unweighted arithmetic average of the first-day-of-the-month oil price for each month for Brent crude in the period January through December 2010. The average Brent crude price of $79.35 per barrel is adjusted for crude handling, transportation fees, quality, and a regional price differential. Based on the crude quality, these adjustments are estimated to be an additional $0.35 per barrel; therefore, the oil flowstreams receive a crude price of $79.70 per barrel. This oil price is held constant throughout the lives of the properties. There is no gas price used because gas reserves are consumed in operations as fuel.

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Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

        Proved oil and gas reserves are defined by the SEC Rule 4.10(a) of Regulation S-X as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recovered under current economic conditions, operating methods, and government regulations. Inherent uncertainties exist in estimating proved reserve quantities, projecting future production rates and timing of development expenditures.

Capitalized Costs Related to Oil and Gas Activities

        The following table presents aggregate capitalized costs related to oil and gas activities:

	 	Ghana	 	Other West
Africa	 	Total	 	
 
	 	(In thousands)
	 	
As of December 31, 2009	 	 	 	 	 	 	 	 	 	 	
 	Unproved properties	 	$	121,781	 	$	7,206	 	$	128,987	 	
 	Proved properties	 	 	466,104	 	 	—	 	 	466,104	 	
 	 	 	 	 	 	 	 	
 	 	 	587,885	 	 	7,206	 	 	595,091	 	
Accumulated depletion, depreciation and amortization	 	 	
—	 	 	
—	 	 	
—	 	
 	 	 	 	 	 	 	 	
Net capitalized costs	 	$	587,885	 	$	7,206	 	$	595,091	 	
 	 	 	 	 	 	 	 	
As of December 31, 2010	 	 	 	 	 	 	 	 	 	 	
 	Unproved properties	 	$	190,184	 	$	7,965	 	$	198,149	 	
 	Proved properties	 	 	798,150	 	 	—	 	 	798,150	 	
 	 	 	 	 	 	 	 	
 	 	 	988,334	 	 	7,965	 	 	996,299	 	
Accumulated depletion, depreciation and amortization	 	 	(6,430	)	 	—	 	 	(6,430	)	
 	 	 	 	 	 	 	 	
Net capitalized costs	 	$	981,904	 	$	7,965	 	$	989,869	 	
 	 	 	 	 	 	 	 	
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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

Costs Incurred in Oil and Gas Activities

        The following table reflects total costs incurred, both capitalized and expensed, for oil and gas property acquisition, exploration, and development activities for the year.

	 	Ghana	 	Other West
Africa	 	Total	 	
 
	 	(In thousands)
	 	
Year ended December 31, 2008	 	 	 	 	 	 	 	 	 	 	
Property acquisition:	 	 	 	 	 	 	 	 	 	 	
 	Unproved	 	$	—	 	$	—	 	$	—	 	
 	Proved	 	 	—	 	 	—	 	 	—	 	
Exploration	 	 	45,961	 	 	9,631	 	 	55,592	 	
Development	 	 	146,728	 	 	—	 	 	146,728	 	
 	 	 	 	 	 	 	 	
Total costs incurred	 	$	192,689	 	$	9,631	 	$	202,320	 	
 	 	 	 	 	 	 	 	
Year ended December 31, 2009	 	 	 	 	 	 	 	 	 	 	
Property acquisition:	 	 	 	 	 	 	 	 	 	 	
 	Unproved	 	$	—	 	$	—	 	$	—	 	
 	Proved	 	 	—	 	 	—	 	 	—	 	
Exploration	 	 	88,103	 	 	20,776	 	 	108,879	 	
Development	 	 	304,948	 	 	—	 	 	304,948	 	
 	 	 	 	 	 	 	 	
Total costs incurred	 	$	393,051	 	$	20,776	 	$	413,827	 	
 	 	 	 	 	 	 	 	
Year ended December 31, 2010	 	 	 	 	 	 	 	 	 	 	
Property acquisition:	 	 	 	 	 	 	 	 	 	 	
 	Unproved	 	$	—	 	$	—	 	$	—	 	
 	Proved	 	 	—	 	 	—	 	 	—	 	
Exploration	 	 	109,624	 	 	32,304	 	 	141,928	 	
Development	 	 	325,975	 	 	—	 	 	325,975	 	
 	 	 	 	 	 	 	 	
Total costs incurred	 	$	435,599	 	$	32,304	 	$	467,903	 	
 	 	 	 	 	 	 	 	
Standardized Measure for Discounted Future Net Cash Flows

        The following table provides projected future net cash flows based on the twelve month unweighted arithmetic average of the first-day-of-the-month oil price for Brent crude in the period January through December 2010. The average Brent crude price of $79.35 per barrel is adjusted for crude handling, transportation fees, quality, and a regional price differential. Based on the crude quality, these adjustments are estimated to be an additional $0.35 per barrel; therefore, the oil flowstreams receive a crude price of $79.70 per barrel. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on market conditions that occurred.

        The projection should not be interpreted as representing the current value to Kosmos. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly

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Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

from those used; and actual costs may vary. Kosmos' investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on a wide range of different price and cost assumptions.

        The standardized measure is intended to provide a better means to compare the value of Kosmos' proved reserves at a given time with those of other oil producing companies than is provided by comparing raw proved reserve quantities.

	 	Ghana	 	
 
	 	(In millions)
	 	
At December 31, 2009	 	 	 	 	
Future cash inflows	 	$	3,098	 	
Future production costs	 	 	(990	)	
Future development costs	 	 	(630	)	
Future foreign income tax expenses	 	 	(351	)	
 	 	 	 	
Future net cash flows	 	 	1,127	 	
10% annual discount for estimated timing of cash flows	 	 	(429	)	
 	 	 	 	
Standardized measure of discounted future net cash flows	 	$	698	 	
 	 	 	 	
At December 31, 2010	 	 	 	 	
Future cash inflows	 	$	4,141	 	
Future production costs	 	 	(1,140	)	
Future development costs	 	 	(342	)	
Future foreign income tax expenses	 	 	(618	)	
 	 	 	 	
Future net cash flows	 	 	2,041	 	
10% annual discount for estimated timing of cash flows	 	 	(511	)	
 	 	 	 	
Standardized measure of discounted future net cash flows	 	$	1,530	 	
 	 	 	 	
Changes in the Standardized Measure for Discounted Cash Flows

	 	Ghana	 	
 
	 	(In millions)
	 	
Balance at December 31, 2009	 	$	698	 	
Net changes in prices	 	 	1,055	 	
Net changes in production costs	 	 	(150	)	
Net changes in development costs	 	 	288	 	
Extensions and discoveries	 	 	(12	)	
Net change in income taxes	 	 	(267	)	
Accretion of discount	 	 	(82	)	
 	 	 	 	
Balance at December 31, 2010	 	$	1,530	 	
 	 	 	 	
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Table of Contents
PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13.    Other Expenses of Issuance and Distribution.

        The following table sets forth an itemization of the various costs and expenses, all of which we will pay, in connection with the issuance and distribution of the securities being registered. All of the amounts shown are estimated except the SEC registration fee, the NYSE listing fee and the FINRA filing fee:
 	 	 	 	 	
SEC registration fee	 	$	58,050	 	
NYSE listing fee	 	 	 	 	
FINRA filing fee	 	 	30,500	 	
Accounting fees and expense	 	 	 	 	
Printing and engraving expenses	 	 	 	 	
Legal fees and expenses	 	 	 	 	
Transfer Agents and Registrar fees	 	 	 	 	
Miscellaneous	 	 	 	 	
 	 	 	 	
Total	 	$	 	 	
 	 	 	 	
Item 14.    Indemnification of Directors and Officers.

        Section 98 of the Companies Act 1981 of Bermuda (the "Bermuda Companies Act") provides generally that a Bermuda company may indemnify its directors, officers and auditors against any liability which by virtue of any rule of law would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust, except in cases where such liability arises from fraud or dishonesty of which such director, officer or auditor may be guilty in relation to the company. Section 98 further provides that a Bermuda company may indemnify its directors, officers and auditors against any liability incurred by them in defending any proceedings, whether civil or criminal, in which judgment is awarded in their favour or in which they are acquitted or granted relief by the Supreme Court of Bermuda pursuant to section 281 of the Bermuda Companies Act.

        We have adopted provisions in our bye-laws that provide that we shall indemnify our officers and directors in respect of their actions and omissions, except in respect of their fraud or dishonesty. Our bye-laws provide that the shareholders waive all claims or rights of action that they might have, individually or in right of the company, against any of the company's directors or officers for any act or failure to act in the performance of such director's or officer's duties, except in respect of any fraud or dishonesty of such director or officer. Section 98A of the Bermuda Companies Act permits us to purchase and maintain insurance for the benefit of any officer or director in respect of any loss or liability attaching to him in respect of any negligence, default, breach of duty or breach of trust, whether or not we may otherwise indemnify such officer or director.

        Insofar as indemnification by us for liabilities arising under the Securities Act may be permitted to our directors, officers or persons controlling the company pursuant to provisions of our bye-laws, or otherwise, we have been advised that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable. In the event that a claim for indemnification by such director, officer or controlling person of us in the successful defense of any action, suit or proceeding is asserted by such director, officer or controlling person in connection with the securities being offered, we will, unless in the opinion of our counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by us is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

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Table of Contents

        At the present time, there is no pending litigation or proceeding involving a director, officer, employee or other agent of ours in which indemnification would be required or permitted. We are not aware of any threatened litigation or proceeding, which may result in a claim for such indemnification.

        We carry insurance policies insuring our directors and officers against certain liabilities that they may incur in their capacity as directors and officers. In addition, we expect to enter into indemnification agreements with each of our directors prior to completion of the offering.

        Additionally, reference is made to the Underwriting Agreement filed as Exhibit 1.1. hereto, which provides for indemnification by the underwriters of Kosmos Energy Ltd., our directors and officers who sign the registration statement and persons who control Kosmos Energy Ltd., under certain circumstances.

Item 15.    Recent Sales of Unregistered Securities.

        During the past three years, Kosmos Energy Ltd.'s predecessor, Kosmos Energy Holdings, issued unregistered securities to funds affiliated with Warburg Pincus LLC ("Warburg Pincus"), The Blackstone Group L.P. ("Blackstone"), certain members of management, accredited employee investors and directors, as described below. None of these transactions involved any underwriters or any public offerings, and we believe that each of these transactions was exempt from the registration requirements pursuant to Section 3(a)(9) or Section 4(2) of the Securities Act of 1933, as amended. The recipients of the securities in these transactions represented their intention to acquire the securities for investment only and not with a view to or for sale in connection with any distribution thereof. The information presented below does not give effect to our corporate reorganization as described in the prospectus.

        During the fiscal year ended December 31, 2008, Kosmos Energy Holdings issued the following unregistered securities for the consideration listed:
 	 	 	 	 	 	 	
Recipient	 	Securities Issued	 	Consideration
Received by
Kosmos Energy
Holdings	 	
Warburg Pincus	 	7,150,893 Series A Convertible Preferred Units	 	$	71,508,930	 	
 	 	4,308,700 Series B Convertible Preferred Units	 	 	107,717,500	 	
Blackstone	 	5,850,738 Series A Convertible Preferred Units	 	
$	
58,507,380	 	
 	 	3,525,300 Series B Convertible Preferred Units	 	 	88,132,500	 	
Members of management, accredited employee investors and directors, in the aggregate	 	298,367 Series A Convertible Preferred Units	 	
$	
2,983,670	 	
 	 	152,250 Series B Convertible Preferred Units	 	 	3,806,250	 	
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        During the fiscal year ended December 31, 2009, Kosmos Energy Holdings issued the following unregistered securities for the consideration listed:
 	 	 	 	 	 	 	
Recipient	 	Securities Issued	 	Consideration
Received by
Kosmos Energy
Holdings	 	
Warburg Pincus	 	6,463,052 Series B Convertible Preferred Units	 	$	161,576,300	 	
 	 	476,134 Series C Convertible Preferred Units(1)	 	 	13,450,786	 	
Blackstone	 	5,287,948 Series B Convertible Preferred Units	 	
$	
132,198,700	 	
 	 	389,563 Series C Convertible Preferred Units(1)	 	 	11,005,155	 	
Members of management, accredited employee investors and directors, in the aggregate	 	262,750 Series B Convertible Preferred Units	 	
$	
6,568,750	 	
 	 	19,259 Series C Convertible Preferred Units(1)	 	 	544,066	 	

(1)
Kosmos Energy Holdings' financial statements reflect that the proceeds from the Series C funding were allocated on a relative fair value basis between the Series C Convertible Preferred Units and the C1 Common Units.

        During the fiscal year ended December 31, 2010, Kosmos Energy Holdings did not issue any unregistered securities. To date, during the current fiscal year, Kosmos Energy Holdings has not issued any unregistered securities. To date, during the current fiscal year, Kosmos Energy Ltd. has issued one common share in connection with its incorporation under the laws of Bermuda.

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Table of Contents

Item 16.    Exhibits and Financial Statement Schedules.
(a)
The following exhibits are filed as part of this registration statement:
 	 	 	 	
Exhibit
Number	 	Description of Document	
 	1.1	 	Form of Underwriting Agreement*	

3.1	
 	
Certificate of Incorporation of Kosmos Energy Ltd. (the "Company")	

3.2	
 	
Memorandum of Association of the Company	

3.3	
 	
Bye-laws of the Company*	

3.4	
 	
Fourth Amended and Restated Operating Agreement of Kosmos Energy Holdings (the "Predecessor")*	

3.5	
 	
Memorandum of Association of the Predecessor	

3.6	
 	
Articles of Association of the Predecessor	

4.1	
 	
Specimen share certificate*	

5.1	
 	
Opinion of Conyers Dill & Pearman Limited*	

9.1	
 	
Form of Shareholders Agreement.*	

10.1	
 	
Petroleum Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 22, 2004 among the Ghana National Petroleum Corporation ("GNPC"), Kosmos Energy Ghana HC ("Kosmos Ghana") and the E.O. Group Limited ("E.O. Group").***	

10.2	
 	
Operating Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 27, 2004 between Kosmos Ghana and E.O. Group.***	

10.3	
 	
Petroleum Agreement in respect of the Deepwater Tano Contract Area dated March 10, 2006 among GNPC, Tullow Ghana Limited ("Tullow Ghana"), Sabre Oil and Gas Limited ("Sabre") and Kosmos Ghana.***	

10.4	
 	
Joint Operating Agreement in respect of the Deepwater Tano Contract Area, Offshore Ghana dated August 14, 2006, among Tullow Ghana, Sabre Oil and Gas Limited, and Kosmos Ghana.***	

10.5	
 	
Assignment Agreement in respect of the Deepwater Tano Block dated September 1, 2006, among Anadarko WCTP Company ("Anadarko WCTP") and Kosmos Ghana.***	

10.6	
 	
Unitization and Unit Operating Agreement covering the Jubilee Field Unit located offshore the Republic of Ghana dated July 13, 2009, among GNPC, Tullow, Kosmos Ghana, Anadarko WCTP, Sabre and E.O. Group.***	

10.7	
 	
Atwood Hunter Offshore Drilling Contract dated June 23, 2008 among Kosmos Ghana, Alpha Offshore Drilling Services Company and Noble Energy EG Ltd., as amended.	

10.8	
 	
Ndian River Production Sharing Contract dated November 20, 2006 between the Republic of Cameroon and Kosmos Energy Cameroon HC ("Kosmos Cameroon").***	

10.9	
 	
Decree 2005/249 dated June 30, 2005 granting Perenco Oil and Gas (Cameroon) Ltd. ("Perenco") and Société Nationale des Hydrocarbures ("SNH") the Kombe-N'sepe Permit.***	

10.10	
 	
Contract of Association relating to the Kombe-N'sepe Permit dated December 11, 1997 between the Republic of Cameroon, CMS Nomeco Cameroon Ltd ("CMS Nomeco Cameroon"), Globex Cameroon, LLC ("Globex Cameroon") and SNH.***	
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Exhibit
Number	 	Description of Document	
 	10.11	 	Convention of Establishment relating to the Kombe-N'sepe Permit dated December 11, 1997 between the Republic of Cameroon, CMS Nomeco Cameroon and Globex Cameroon.***	

10.12	
 	
Deed of Assignment of the Kombe-N'sepe Permit, Contract of Association and Convention of Establishment dated November 16, 2005 between Perenco and Kosmos Cameroon.***	

10.13	
 	
Agreement on the Management of Petroleum Operations (JOA) covering the Kombe-N'sepe Permit dated July 3, 2008 among SNH, Perenco and Kosmos Cameroon.***	

10.14	
 	
Petroleum Agreement regarding the exploration for and exploitation of hydrocarbons in the area of interest named Boujdour Offshore dated May 3, 2006 between Office National des Hydrocarbures et des Mines ("ONHYM") and Kosmos Energy Offshore Morocco HC ("Kosmos Morocco").***	

10.15	
 	
Association Contract regarding the exploration for and exploitation of hydrocarbons in the Boujdour Offshore Block dated May 3, 2006 between ONHYM and Kosmos Morocco.***	

10.16	
 	
Memorandum of Understanding regarding a new petroleum agreement covering certain areas of the Boujdour Offshore Block dated September 27, 2010 between ONHYM and Kosmos Morocco.***	

10.17	
 	
Common Terms Agreement, dated July 13, 2009 among Kosmos Energy Finance ("Kosmos Finance"), Kosmos Ghana, Kosmos Energy Development ("Kosmos Development") and the various financial institutions and others party thereto, as amended.***	

10.18	
 	
Definitions Agreement, dated July 13, 2009 among Kosmos Finance, Kosmos Ghana, Kosmos Development and the various financial institutions and others party thereto, as amended.***	

10.19	
 	
Senior Bank Facility Agreement, dated July 13, 2009 among Kosmos Finance, Kosmos Development, Kosmos Ghana, Standard Chartered Bank, BNP Paribas SA, Societe Generale, Calyon, ABSA Bank Limited, Africa Finance Corporation, Cordiant Emerging Loan Fund III, L.P. and various other financial institutions party thereto, as amended.***	

10.20	
 	
Intercreditor Agreement, dated July 13, 2009 among Kosmos Finance, Kosmos Ghana, Kosmos Development and the various financial institutions and others party thereto, as amended.***	

10.21	
 	
Form of Long-term Incentive Plan of the Company*	

10.22	
 	
Form of Annual Incentive Plan*	

10.23	
 	
Form of Director Indemnification Agreement*	

10.24	
 	
Retirement Agreement dated December 17, 2010 between Kosmos Energy, LLC, Kosmos Energy Holdings, James C. Musselman, Musselman-Kosmos, Ltd. and funds affiliated with Warburg Pincus LLC and The Blackstone Group L.P.***	

10.25	
 	
Consulting Agreement dated November 17, 2010 between Kosmos Energy Holdings and John R. Kemp***	

10.26	
 	
Letter agreement, dated May 4, 2010 among Tullow Ghana Limited, Anadarko WCTP Company and Kosmos Energy Ghana HC	

21.1	
 	
List of Subsidiaries***	

23.1	
 	
Consent of Ernst & Young LLP	

23.2	
 	
Consent of Netherland, Sewell & Associates, Inc.	
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Exhibit
Number	 	Description of Document	
 	23.3	 	Consent of Davis Polk & Wardwell LLP*	

23.4	
 	
Consent of Conyers Dill & Pearman Limited (included in Exhibit 5.1)*	

24	
 	
Power of Attorney (included on the signature pages of this registration statement)	

99.1	
 	
Estimate of Reserves and Future Revenue to the Kosmos Energy Interest in the Jubilee Field Phase 1 Development Unit Area located in the West Cape Three Points and Deepwater Tano License Areas Offshore Ghana as of December 31, 2009.	

99.2	
 	
Estimate of Reserves and Future Revenue to the Kosmos Energy Interest in the Jubilee Field Phase 1 Development Unit Area located in the West Cape Three Points and Deepwater Tano License Areas Offshore Ghana as of December 31, 2010.	

99.3	
 	
Consent of David I. Foley, as director nominee**	

99.4	
 	
Consent of Jeffrey A. Harris, as director nominee**	

99.5	
 	
Consent of David Krieger, as director nominee**	

99.6	
 	
Consent of Prakash A. Melwani, as director nominee**	

99.7	
 	
Consent of Bayo O. Ogunlesi, as director nominee**	

99.8	
 	
Consent of Christopher A. Wright, as director nominee**	

*
To be filed by amendment.

**
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700 on January 14, 2011.

***
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 3, 2011.
(b)
Financial Statement Schedule

Schedule I—Condensed Parent Company Financial Statements

        Under the terms of agreements governing the indebtedness of subsidiaries of Kosmos Energy Holdings ("KEH," the "Parent Company"), such subsidiaries are restricted from making dividend payments, loans or advances to KEH. Schedule I of Article 5-04 of Regulation S-X requires the condensed financial information of the Parent Company to be filed when the restricted net assets of consolidated subsidiaries exceed 25 percent of consolidated net assets as of the end of the most recently completed fiscal year.

        The following condensed parent-only financial statements of KEH have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X and included herein. The Parent Company's 100% investment in its subsidiaries has been recorded using the equity basis of accounting in the accompanying condensed parent-only financial statements. The condensed financial statements should be read in conjunction with the consolidated financial statements of Kosmos Energy Holdings and subsidiaries and notes thereto.

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Kosmos Energy Holdings

(A Development Stage Entity)

Condensed Parent Company Balance Sheets

 
	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Assets	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	51,224	 	$	—	 	
 	Receivables from subsidiaries	 	 	3,878	 	 	—	 	
 	Prepaid expenses and other	 	 	15	 	 	—	 	
 	 	 	 	 	 	
Total current assets	 	 	55,117	 	 	—	 	
Other assets, net of accumulated depreciation and amortization of $773 and $773, respectively	 	 	
2	 	 	
—	 	
Investment in subsidiaries at equity	 	 	540,482	 	 	363,507	 	
 	 	 	 	 	 	
Total assets	 	$	595,601	 	$	363,507	 	
 	 	 	 	 	 	
Liabilities and unit holdings	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	
 	Accounts payable to subsidiaries	 	$	—	 	$	—	 	
 	Accrued liabilities	 	 	213	 	 	—	 	
 	 	 	 	 	 	
Total current liabilities	 	 	213	 	 	—	 	
Convertible preferred units, 100,000 units authorized:	 	 	 	 	 	 	 	
 	Series A—30,000 units issued at December 31, 2009 and 2010	 	 	300,000	 	 	383,246	 	
 	Series B—20,000 units issued at December 31, 2009 and 2010	 	 	500,000	 	 	568,163	 	
 	Series C—885 units issued at December 31, 2009 and 2010	 	 	13,244	 	 	27,097	 	
Unit holdings:	 	 	 	 	 	 	 	
 	Common units, 100,000 units authorized; 18,667 and 19,070 issued at December 31, 2009 and 2010, respectively	 	 	516	 	 	516	 	
 	Additional paid-in capital	 	 	19,108	 	 	—	 	
 	Deficit accumulated during development stage	 	 	(237,480	)	 	(615,515	)	
 	 	 	 	 	 	
Total unit holdings	 	 	(217,856	)	 	(614,999	)	
 	 	 	 	 	 	
Total liabilities, convertible preferred units and unit holdings	 	$	595,601	 	$	363,507	 	
 	 	 	 	 	 	
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Kosmos Energy Holdings

(A Development Stage Entity)

Condensed Parent Company Statements of Operations

 
	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas revenue	 	$	—	 	$	—	 	$	—	 	
 	Interest income	 	 	188	 	 	15	 	 	44	 	
 	 	 	 	 	 	 	 	
Total revenues and other income	 	 	188	 	 	15	 	 	44	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	
 	General and administrative	 	 	4,743	 	 	11,580	 	 	21,187	 	
 	General and administrative—related party	 	 	12,453	 	 	10,663	 	 	16,830	 	
 	Depreciation and amortization	 	 	155	 	 	39	 	 	—	 	
 	Equity in losses of subsidiaries	 	 	31,642	 	 	57,494	 	 	207,697	 	
 	Other expenses, net	 	 	—	 	 	(14	)	 	2	 	
 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	48,993	 	 	79,762	 	 	245,716	 	
 	 	 	 	 	 	 	 	
Loss before income taxes	 	 	
(48,805	
)	 	
(79,747	
)	 	
(245,672	
)	
Income tax expense	 	 	—	 	 	—	 	 	—	 	
 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(245,672	)	
 	 	 	 	 	 	 	 	
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Kosmos Energy Holdings

(A Development Stage Entity)

Condensed Parent Company Statements of Cash Flows

 
	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Operating activities	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(245,672	)	
Adjustments to reconcile net loss to net cash used in operating activities:	 	 	 	 	 	 	 	 	 	 	
 	Equity in losses of subsidiaries	 	 	31,642	 	 	57,494	 	 	207,697	 	
 	Depreciation and amortization	 	 	155	 	 	39	 	 	—	 	
 	Unit-based compensation	 	 	3,671	 	 	3,468	 	 	13,791	 	
 	Changes in assets and liabilities:	 	 	 	 	 	 	 	 	 	 	
 	 	(Increase) decrease in prepaid expenses and other	 	 	(47	)	 	32	 	 	15	 	
 	 	(Increase) decrease due to/from related party	 	 	1,008	 	 	(10,171	)	 	3,878	 	
 	 	Decrease in accounts payable	 	 	(75	)	 	—	 	 	—	 	
 	 	Increase (decrease) in accrued liabilities	 	 	—	 	 	213	 	 	(213	)	
 	 	 	 	 	 	 	 	
Net cash used in operating activities	 	 	(12,451	)	 	(28,672	)	 	(20,504	)	
Investing activities	 	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	 	 	(320,205	)	 	(245,496	)	 	(30,722	)	
Other property	 	 	—	 	 	(2	)	 	2	 	
 	 	 	 	 	 	 	 	
Net cash used in investing activities	 	 	(320,205	)	 	(245,498	)	 	(30,720	)	
Financing activities	 	 	 	 	 	 	 	 	 	 	
Net proceeds from issuance of units	 	 	332,656	 	 	325,344	 	 	—	 	
 	 	 	 	 	 	 	 	
Net cash provided by financing activities	 	 	332,656	 	 	325,344	 	 	—	 	
 	 	 	 	 	 	 	 	
Net increase (decrease) in cash and cash equivalents	 	 	
—	 	 	
51,174	 	 	
(51,224	
)	
Cash and cash equivalents at beginning of period	 	 	50	 	 	50	 	 	51,224	 	
 	 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	 	$	50	 	$	51,224	 	$	—	 	
 	 	 	 	 	 	 	 	
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Schedule II

Kosmos Energy Holdings

(A Development Stage Entity)

Valuation and Qualifying Accounts

For the Years Ended December 31, 2008, 2009 and 2010

 
	 	 
	 	Additions	 	 

Description
	 	Balance
January 1	 	Charged to
Costs and
Expenses	 	Charged
to Other
Accounts	 	Deductions
From
Reserves	 	Balance
December 31	 	
 
	 	(In thousands)
	 	
2008	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for doubtful receivables	 	
$	
—	 	
$	
—	 	
$	
—	 	
$	
—	 	
$	
—	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for deferred tax asset	 	
$	
9,404	 	
$	
9,727	 	
$	
—	 	
$	
—	 	
$	
19,131	 	
 	 	 	 	 	 	 	 	 	 	 	 	
2009	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for doubtful receivables	 	
$	
—	 	
$	
—	 	
$	
—	 	
$	
—	 	
$	
—	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for deferred tax asset	 	
$	
19,131	 	
$	
14,618	 	
$	
—	 	
$	
—	 	
$	
33,749	 	
 	 	 	 	 	 	 	 	 	 	 	 	
2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for doubtful receivables	 	
$	
—	 	
$	
39,782	 	
$	
—	 	
$	
—	 	
$	
39,782	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for deferred tax asset	 	
$	
33,749	 	
$	
(3,609	
)	
$	
—	 	
$	
—	 	
$	
30,140	 	
 	 	 	 	 	 	 	 	 	 	 	 	
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Item 17.    Undertakings.

        (a)   The undersigned registrant hereby undertakes:

        (1)   To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

            i.  To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;

           ii.  To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20 percent change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in the effective registration statement.

          iii.  To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

        (2)   That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

        (3)   To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

        (4)   That in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

            i.  Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

           ii.  Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

          iii.  The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

          iv.  Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

        (b)   The undersigned hereby undertakes to provide to the underwriter at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriter to permit prompt delivery to each purchaser.

        (c)   Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and

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Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer, or controlling person of the registrant in the successful defense of any action, suit, or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

        (d)   The undersigned registrant hereby undertakes that:

        (1)   For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

        (2)   For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES

        Pursuant to the requirements of the Securities Act of 1933, the Registrant certifies that it has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Dallas, Texas on March 23, 2011.
 	 	 	 	 	
 	 	Kosmos Energy Ltd.	
 	 	By:	 	/s/ BRIAN F. MAXTED

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

        Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities held on the dates indicated.
 	 	 	 	 	
SIGNATURE	 	TITLE	 	DATE	

 	

 	
/s/ BRIAN F. MAXTED

Brian F. Maxted	 	Director and Chief Executive Officer (Principal Executive Officer)	 	March 23, 2011	

/s/ W. GREG DUNLEVY

W Greg. Dunlevy	
 	
Chief Financial Officer and Executive Vice President (Principal Financial Officer)	
 	
March 23, 2011	

/s/ SYLVIA MANOR

Sylvia Manor	
 	
Vice President and Controller
(Principal Accounting Officer)	
 	
March 23, 2011	
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SIGNATURE	 	TITLE	 	DATE	

 	

 	
/s/ JOHN R. KEMP

John R. Kemp	 	Chairman of the Board of Directors	 	March 23, 2011	

/s/ DAVID I. FOLEY

David I. Foley	
 	
Director	
 	
March 23, 2011	

/s/ JEFFREY A. HARRIS

Jeffrey A. Harris	
 	
Director	
 	
March 23, 2011	

/s/ DAVID B. KRIEGER

David B. Krieger	
 	
Director	
 	
March 23, 2011	

/s/ PRAKASH A. MELWANI

Prakash A. Melwani	
 	
Director	
 	
March 23, 2011	

/s/ ADEBAYO O. OGUNLESI

Adebayo O. Ogunlesi	
 	
Director	
 	
March 23, 2011	

/s/ CHRIS TONG

Chris Tong	
 	
Director	
 	
March 23, 2011	

/s/ CHRISTOPHER A. WRIGHT

Christopher A. Wright	
 	
Director	
 	
March 23, 2011	
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INDEX OF EXHIBITS

Exhibit
Number	 	Description of Document	
 	1.1	 	Form of Underwriting Agreement*	

3.1	
 	
Certificate of Incorporation of Kosmos Energy Ltd. (the "Company")	

3.2	
 	
Memorandum of Association of the Company	

3.3	
 	
Bye-laws of the Company*	

3.4	
 	
Fourth Amended and Restated Operating Agreement of Kosmos Energy Holdings (the "Predecessor")*	

3.5	
 	
Memorandum of Association of the Predecessor	

3.6	
 	
Articles of Association of the Predecessor	

4.1	
 	
Specimen share certificate*	

5.1	
 	
Opinion of Conyers Dill & Pearman Limited*	

9.1	
 	
Form of Shareholders Agreement.*	

10.1	
 	
Petroleum Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 22, 2004 among the GNPC, Kosmos Ghana and the E.O. Group.***	

10.2	
 	
Operating Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 27, 2004 between Kosmos Ghana and E.O. Group.***	

10.3	
 	
Petroleum Agreement in respect of the Deepwater Tano Contract Area dated March 10, 2006 among GNPC, Tullow Ghana, Sabre and Kosmos Ghana.***	

10.4	
 	
Joint Operating Agreement in respect of the Deepwater Tano Contract Area, Offshore Ghana dated August 14, 2006, among Tullow Ghana, Sabre Oil and Gas Limited, and Kosmos Ghana.***	

10.5	
 	
Assignment Agreement in respect of the Deepwater Tano Block dated September 1, 2006, among Anadarko WCTP and Kosmos Ghana.***	

10.6	
 	
Unitization and Unit Operating Agreement covering the Jubilee Field Unit located offshore the Republic of Ghana dated July 13, 2009, among GNPC, Tullow, Kosmos Ghana, Anadarko WCTP, Sabre and E.O. Group.***	

10.7	
 	
Atwood Hunter Offshore Drilling Contract dated June 23, 2008 among Kosmos Ghana, Alpha Offshore Drilling Services Company and Noble Energy EG Ltd., as amended.	

10.8	
 	
Ndian River Production Sharing Contract dated November 20, 2006 between the Republic of Cameroon and Kosmos Cameroon.***	

10.9	
 	
Decree 2005/249 dated June 30, 2005 granting Perenco and SNH the Kombe-N'sepe Permit.***	

10.10	
 	
Contract of Association relating to the Kombe-N'sepe Permit dated December 11, 1997 between the Republic of Cameroon, CMS Nomeco Cameroon, Globex Cameroon and SNH.***	

10.11	
 	
Convention of Establishment relating to the Kombe-N'sepe Permit dated December 11, 1997 between the Republic of Cameroon, CMS Nomeco Cameroon and Globex Cameroon.***	

10.12	
 	
Deed of Assignment of the Kombe-N'sepe Permit, Contract of Association and Convention of Establishment dated November 16, 2005 between Perenco and Kosmos Cameroon.***	

Table of Contents
 	 	 	 	
Exhibit
Number	 	Description of Document	
 	10.13	 	Agreement on the Management of Petroleum Operations (JOA) covering the Kombe-N'sepe Permit dated July 3, 2008 among SNH, Perenco and Kosmos Cameroon.***	

10.14	
 	
Petroleum Agreement regarding the exploration for and exploitation of hydrocarbons in the area of interest named Boujdour Offshore dated May 3, 2006 between ONHYM and Kosmos Morocco.***	

10.15	
 	
Association Contract regarding the exploration for and exploitation of hydrocarbons in the Boujdour Offshore Block dated May 3, 2006 between ONHYM and Kosmos Morocco.***	

10.16	
 	
Memorandum of Understanding regarding a new petroleum agreement covering certain areas of the Boujdour Offshore Block dated September 27, 2010 between ONHYM and Kosmos Morocco.***	

10.17	
 	
Common Terms Agreement, dated July 13, 2009 among Kosmos Finance, Kosmos Ghana, Kosmos Development and the various financial institutions and others party thereto, as amended.***	

10.18	
 	
Definitions Agreement, dated July 13, 2009 among Kosmos Finance, Kosmos Ghana, Kosmos Development and the various financial institutions and others party thereto, as amended.***	

10.19	
 	
Senior Bank Facility Agreement, dated July 13, 2009 among Kosmos Finance, Kosmos Development, Kosmos Ghana, Standard Chartered Bank, BNP Paribas SA, Societe Generale, Calyon, ABSA Bank Limited, Africa Finance Corporation, Cordiant Emerging Loan Fund III, L.P. and various other financial institutions party thereto, as amended.***	

10.20	
 	
Intercreditor Agreement, dated July 13, 2009 among Kosmos Finance, Kosmos Ghana, Kosmos Development and the various financial institutions and others party thereto, as amended.***	

10.21	
 	
Form of Long-term Incentive Plan of the Company*	

10.22	
 	
Form of Annual Incentive Plan*	

10.23	
 	
Form of Director Indemnification Agreement*	

10.24	
 	
Retirement Agreement dated December 17, 2010 between Kosmos Energy, LLC, Kosmos Energy Holdings, James C. Musselman, Musselman-Kosmos, Ltd. and funds affiliated with Warburg Pincus LLC and The Blackstone Group L.P.***	

10.25	
 	
Consulting Agreement dated November 17, 2010 between Kosmos Energy Holdings and John R. Kemp***	

10.26	
 	
Letter agreement, dated May 4, 2010 among Tullow Ghana Limited, Anadarko WCTP Company and Kosmos Energy Ghana HC	

21.1	
 	
List of Subsidiaries***	

23.1	
 	
Consent of Ernst & Young LLP	

23.2	
 	
Consent of Netherland, Sewell & Associates, Inc.	

23.3	
 	
Consent of Davis Polk & Wardwell LLP*	

23.4	
 	
Consent of Conyers Dill & Pearman Limited (included in Exhibit 5.1)*	

24	
 	
Power of Attorney (included on the signature pages of this registration statement)	

99.1	
 	
Estimate of Reserves and Future Revenue to the Kosmos Energy Interest in the Jubilee Field Phase 1 Development Unit Area located in the West Cape Three Points and Deepwater Tano License Areas Offshore Ghana as of December 31, 2009.	

Table of Contents
 	 	 	 	
Exhibit
Number	 	Description of Document	
 	99.2	 	Estimate of Reserves and Future Revenue to the Kosmos Energy Interest in the Jubilee Field Phase 1 Development Unit Area located in the West Cape Three Points and Deepwater Tano License Areas Offshore Ghana as of December 31, 2010.	

99.3	
 	
Consent of David I. Foley, as director nominee**	

99.4	
 	
Consent of Jeffrey A. Harris, as director nominee**	

99.5	
 	
Consent of David Krieger, as director nominee**	

99.6	
 	
Consent of Prakash A. Melwani, as director nominee**	

99.7	
 	
Consent of Bayo O. Ogunlesi, as director nominee**	

99.8	
 	
Consent of Christopher A. Wright, as director nominee**	

*
To be filed by amendment.

**
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on January 14, 2011.

***
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 3, 2011.

Exhibit 3.1
 
Registration No. 45011

 
BERMUDA
 
CERTIFICATE OF INCORPORATION
 
I hereby in accordance with section 14 of the Companies Act 1981 issue this Certificate of Incorporation and do certify that on the  6th January 2011
 
Kosmos Energy Ltd.
 
was registered by me in the Register maintained by me under the provisions of the said section and that the status of the said company is that of an  exempted  company.
 
 	Given under my hand and the Seal of the REGISTRAR OF COMPANIES this  10th  day of  January 2011	 	

 	 	 	 	 	 	

 	 	 	 	 	 	 	 	 	

 	 	 	 	 	 	 	 	 	 	 	 	

 	/s/ REGISTRAR OF COMPANIES	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	for Registrar of Companies	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

Exhibit 3.2
 
FORM NO. 2

 
BERMUDA
THE COMPANIES ACT 1981
MEMORANDUM OF ASSOCIATION OF
COMPANY LIMITED BY SHARES
(Section 7(1) and (2))
 
MEMORANDUM OF ASSOCIATION
OF
 
Kosmos Energy Ltd.
(hereinafter referred to as “the Company”)
 
1.	 	The liability of the members of the Company is limited to the amount (if any) for the time being unpaid on the shares respectively held by them.	
 	 	 	
2.	 	We, the undersigned, namely,	
 
 	 	 	 	BERMUDIAN	 	 	 	NUMBER OF	
 	 	 	 	STATUS	 	 	 	SHARES	
NAME	 	ADDRESS	 	(Yes/No)	 	NATIONALITY	 	SUBSCRIBED	
 	 	 	 	 	 	 	 	 	
Michael G. Frith	 	Clarendon House	 	Yes	 	British	 	One	
 	 	2 Church Street	 	 	 	 	 	 	
 	 	Hamilton HM 11	 	 	 	 	 	 	
 	 	Bermuda	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
David J. Doyle	 	”	 	Yes	 	British	 	One	
 	 	 	 	 	 	 	 	 	
Alison R. Guilfoyle	 	”	 	No	 	British	 	One	
 
do hereby respectively agree to take such number of shares of the Company as may be allotted to us respectively by the provisional directors of the Company, not exceeding the number of shares for which we have respectively subscribed, and to satisfy such calls as may be made by the directors, provisional directors or promoters of the Company in respect of the shares allotted to us respectively.

 
3.	 	The Company is to be an exempted company as defined by the Companies Act 1981.	
 	 	 	
4.	 	The Company, with the consent of the Minister of Finance, has power to hold land situate in Bermuda not exceeding                 in all, including the following parcels:-  N/A	
 	 	 	
5.	 	The authorised share capital of the Company is US$12,000.00 divided into shares of US$0.01 each.	
 	 	 	
6.	 	The objects for which the Company is formed and incorporated are unrestricted.	
 	 	 	
7.	 	Subject to paragraph 4, the Company may do all such things as are incidental or conducive to the attainment of its objects and shall have the capacity, rights, powers and privileges of a natural person, and —	
 	 	 	 	
 	 	(i)	pursuant to Section 42 of the Act, the Company shall have the power to issue preference shares which are, at the option of the holder, liable to be redeemed;	
 	 	 	 	
 	 	(ii)	pursuant to Section 42A of the Act, the Company shall have the power to purchase its own shares for cancellation; and	
 	 	 	 	
 	 	(iii)	pursuant to Section 42B of the Act, the Company shall have the power to acquire its own shares to be held as treasury shares.	

 
Signed by each subscriber in the presence of at least one witness attesting the signature thereof
 
/s/ MICHAEL G. FRITH	 	 	

/s/ DAVID J. DOYLE	 	 	

/s/ ALISON R. GUILFOYLE	 	 	

 	 	 	

(Subscribers)	 	(Witnesses)	
 
SUBSCRIBED this 6th day of January 2011

Exhibit 3.5
 
 	MEMORANDUM OF ASSOCIATION
 
OF
 
KOSMOS ENERGY HOLDINGS
(Company Limited by Guarantee
and not having a share capital)	[SEAL]	
 
1.          The name of the Company is Kosmos Energy Holdings.
 
2.          The registered office will be situate at the offices of Huntlaw Corporate Services Ltd., P.O. Box 1350 GT, the Huntlaw Building, Fort Street, George Town in the Island of Grand Cayman or at such other place in the Cayman Islands as the directors may from time to time decide.
 
3.          The objects for which the Company is established are unrestricted and the Company shall have full power and authority to carry out any object not prohibited by any law as provided by Section 7(4) of the Companies Law (2003 Revision).
 
4.          Except as prohibited or limited by the laws of the Cayman Islands, the Company shall have full power and authority to carry out any object and shall have and be capable of from time to time and at all times exercising any and all of the powers at any time or from time to time exercisable by a natural person of full capacity or body corporate in any part of the world whether as principal, agent, contractor or otherwise irrespective of any question of corporate benefit as provided by Section 27 (2) of the Companies Law (2003 Revision).
 
5.          The liability of the Members is limited.
 
6.          Every Member (as defined in the Articles of Association) of the Company undertakes to contribute to the assets of the Company in the event of its being wound up while he is a Member, or within one year after he ceases to be a member, for the payment of the debts and liabilities of the Company contracted before he ceases to be a Member, and the costs, charges and expenses of winding up the same, and for the adjustments of the rights of the contributories among themselves, such amount as may be required not exceeding One United States Dollar (US$ 1.00).

 
7.          The Company may exercise the power contained in Section 226 of the Companies Law (2003 Revision) to deregister in the Cayman Islands and be registered by way of continuation in some other jurisdiction.
 
The Subscriber whose name and address is subscribed herein is desirous of being formed into a Company limited by guarantee in pursuance of this Memorandum of Association, the Subscriber agrees to take a Membership Interest in the Company.
 
DATED the 5 day of March Two Thousand and Four.
 
NAME OF	 	 	 	 	
SUBSCRIBER	 	ADDRESS	 	OCCUPATION	
Huntlaw Nominees Ltd.	 	P.O. Box 1350GT
Grand Cayman
Cayman Islands	 	Company	
 	 	 	 	 	
/s/ Sarah Bolton	 	 	 	 	
Signed: Sarah Bolton	 	 	 	 	
 
WITNESS TO THE ABOVE SIGNATURE:

/s/ Sally Castro	 	
Sally Castro	 	

 	[SEAL]	 	
 	 	 	
 	[SEAL]	 	
 
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Exhibit 3.6

 
THE COMPANIES LAW
 
Company Limited by Guarantee
and not having a share capital

ARTICLES OF ASSOCIATION
 
OF
 
KOSMOS ENERGY HOLDINGS
 
INTERPRETATION
 
1.	 	(a)	 	In these Articles the following terms shall have the meanings set opposite unless the context otherwise requires:-	
 
(i)	 	Articles	 	these Articles of Association of the Company from time to time in force;	
 	 	 	 	 	
(ii)	 	Board	 	the Board of Managers of the Company at any time;	
 	 	 	 	 	
(iii)	 	Capital Accounts	 	the accounts to be kept as part of the accounting records of the Company reflecting the economic interests of the Members in the Company pursuant to Article 36;	
 	 	 	 	 	
(iv)	 	Company	 	Kosmos Energy Holdings;	
 	 	 	 	 	
(v)	 	Law	 	the Companies Law (2003 Revision) of the Cayman Islands and any amendment or other statutory modification thereof and where in these Articles any provision of the Law is referred to, the reference is to that provision as modified by any law for the rime being in force;	
 	 	 	 	 	
(vi)	 	Managers	 	the Managers of the Company for the time being or, as the case may be, the Managers assembled as a board, and the term Manager shall be included in any reference to directors under the Law;	
 	 	 	 	 	
(vii)	 	Meeting	 	shall include, without limitation, a general	

 
 	 	 	 	meeting in the case of Members;	
 	 	 	 	 	
(viii)	 	Member	 	a person who is registered in the Register of Members as a Member of the Company;	
 	 	 	 	 	
(ix)	 	Membership Interests	 	the interest of a Member in the Company, including rights to distributions (liquidating or otherwise), allocations, information, all other rights, benefits and privileges enjoyed by that Member (under the Law, these Articles, the Operating Agreement or otherwise) in its capacity as a Member and otherwise to participate in the management of the Company; and all obligations, duties and liabilities imposed on that Member (under the Law, these Articles, the Operating Agreement or otherwise) in its capacity as a Member; provided, however, that such term shall not include any management rights held by a Member solely in its capacity as a Manager, and Membership Interests shall be divided into Units;	
 	 	 	 	 	
(x)	 	Month	 	a calendar month;	
 	 	 	 	 	
(xi)	 	officers	 	any officer of the Company;	
 	 	 	 	 	
(xii)	 	Operating Agreement	 	that certain Operating Agreement entered into, or to be entered into, by and among the Company and the Members named therein as amended or supplemented from time to time;	
 	 	 	 	 	
(xiii)	 	Ordinary Resolution	 	a resolution of a general meeting passed by a majority of the Members entitled to vote present at the meeting or a written resolution signed by all Members entitled to vote;	
 	 	 	 	 	
(xiv)	 	Registered Office	 	the registered office of the Company as provided in Section 50 of the Law;	
 	 	 	 	 	
(xv)	 	Register of Members	 	the register of Members to be kept pursuant to Section 40 of the Law;	
 	 	 	 	 	
(xvi)	 	Special Resolution	 	a resolution of a general meeting passed by a two thirds majority of the Members entitled to vote thereat present at the meeting or a written	
 
2

 
 	 	 	 	resolution signed by all Members entitled to vote and otherwise in accordance with Section 60 of the Law;	
 	 	 	 	 	
(xvii)	 	Units	 	Units of the Company which may be divided into, and designated and issued as, classes and series of Units, and which shall have such preferences, rights, qualifications, limitations and restrictions as are set forth in these Articles or in the Operating Agreement.	
 
(b)                                Unless the context otherwise requires, expressions defined in the Law and used herein shall have the meanings so defined.
 
(c)                                 In these Articles unless the context otherwise requires:-
 
(i)                                    words importing the singular number shall include the plural number and vice-versa;
 
(ii)                                 words importing the masculine gender only shall include the feminine gender;
 
(iii)                              words importing persons only shall include companies or associations or bodies of persons whether incorporated or not;
 
(iv)                             a notice provided for herein shall be in writing unless otherwise specified and all reference herein to “in writing” and “written” shall include printing, lithography, photography and other modes of representing or reproducing words in permanent visible form; and
 
(v)                                “may” shall be construed as permissive and “shall” shall be construed as imperative.
 
(d)                                Heading used herein are intended for convenience only and shall not affect the construction of these Articles.
 
2.                                      Operating Agreement
 
Unless otherwise set out in these Articles, or otherwise required by the Law, all provisions governing the operation of the Company shall be as set out in the Operating Agreement.
 
MEMBERSHIP
 
3.                                      Initial Member - The subscriber to the Memorandum of Association shall be the sole initial Member of the Company, and is admitted to the Company as a
 
3

 
Member effective contemporaneously with the registration of the Company under the Law.
 
4.                                      Additional Members - Additional persons may be admitted by the Company as Members in accordance with the Operating Agreement (including by any addendum thereto) and registered in the Register of Members as such only by the Managers and on the terms and conditions of these Articles and the Operating Agreement, and upon admission such persons shall be Members, provided, however, that a person who is named in Schedule I of the Operating Agreement as a Member, and who is a signatory to the Operating Agreement, shall be admitted as a Member of the Company automatically upon signature of the Operating Agreement without further action. Any minimum and maximum number of Members shall be as set out in the Operating Agreement.
 
5.                                      Liability of Members -
 
(a)                                 No Member shall be liable to third parties for the debts, obligations or liabilities of the Company except as expressly agreed to by any such Member.
 
(b)                                The liability of the Members to the Company shall be limited to the amount guaranteed to be contributed by each Member in the event of the Company being wound up pursuant to Clause 6 of the Memorandum of Association, provided that it shall be lawful for any Member to guarantee any larger sum than US$1.00 by executing a bond or subscription contract with the Company to that effect.
 
6.                                      Register of Members - The Company shall maintain a Register of Members in accordance with the Law specifying the name and address of each Member and the date on which each Member was entered on such Register and the date on which each Member ceased to be a Member as well as the amount of the guarantee obligation of each Member pursuant to Clause 6 of the Memorandum of Association.
 
7.                                      Class Rights of Members - The rights attached to any class or series of Units (unless otherwise provided by the terms of admission or issuance of that class or series) may be varied in accordance with the Operating Agreement.
 
8.                                      Equitable Interests - Except as required by law, no person shall be recognised by the Company as holding any Membership Interest or Unit upon any trust, and the Company shall not be bound by or be compelled in any way to recognise (even when having notice thereof) any equitable, contingent, future or partial interest in any Membership Interest or Unit (except only as by these Articles or by law otherwise provided or under an order of a court of competent jurisdiction) or any
 
4

 
other rights in respect of any Member in respect of any Membership Interest or Unit except an absolute right to the entirety thereof in the registered holder.
 
9.                                      Issue of Membership Interests and Units - Membership Interests shall be acquired and Units shall be issued to Members in accordance with, and subject to such terms and conditions attached thereto as shall be set out in, the provisions of these Articles and the Operating Agreement. Units may be issued in such classes and series, and with such rights, terms and conditions attached thereto, as may be set out in these Articles and in the Operating Agreement. In particular, the Units will be subject on issue to such provisions relating to anti-dilution and preemption in respect thereto as shall be set out in the Operating Agreement.
 
10.                                Membership Interests and Units shall have such rights, terms and conditions (if any) attached to them in respect of conversions and exchanges as shall be set out in the Operating Agreement.
 
TRANSFER AND TRANSMISSION OF MEMBERSHIP INTERESTS
AND UNITS
 
11.                                The disposition or transfer of Membership Interests in the Company, including Units, shall be governed by the Operating Agreement.
 
CESSATION OF MEMBERSHIP
 
12.                                A Member shall cease to be a Member of the Company:
 
(a)                                 in the case of the subscriber to the Memorandum of Association, automatically upon the admission of any other person to the Company as a Member; and
 
(b)                                in the case of any other Members, upon the satisfaction of such conditions, and in accordance with such provisions, as are set out in the Operating Agreement.
 
13.                                Membership Interests, including Units, shall be subject to such provisions, if any, relating to forfeiture, redemption, repurchase and buy-back as set out in the Operating Agreement.
 
MEETINGS OF MEMBERS
 
14.                                Meetings (including general meetings) of the Members shall be held at such times, in such places and shall be convened or requisitioned in accordance with the detailed provisions set out in the Operating Agreement.
 
5

 
15.                               All provisions relating to quorum, calling, the giving of notices, dissolution, adjournment and proceedings of meetings of Members shall be as set out in the Operating Agreement.
 
16.                               A resolution of the Members, whether an Ordinary Resolution or a Special Resolution (subject to the provisions of the Law) in writing signed by all the Members for the time being entitled to receive notice of and to attend and vote at general meetings, (or being corporations by their duly authorised representatives) including a resolution signed in counterpart by or on behalf of such Members or by way of signed telefax transmission, shall be as valid and effective as if the same had been passed at a general meeting of the Company duly convened and held.
 
VOTES OF MEMBERS
 
17.                               The voting rights and procedures relating to the exercise of votes of Members and appointment of proxies shall be as set out in the Operating Agreement.
 
MANAGERS, OFFICERS AND BOARD
 
18.                               (a)                                 The name of the first Managers shall be determined in writing by the subscriber(s) of the Memorandum of Association.
 
(b)                                Notwithstanding any provision inthese Articles to the contrary, a sole Manager shall be entitled to exercise all of the powers and functions of the Managers which may be imposed on them by Law or by these Articles or by the Operating Agreement.
 
POWERS AND DUTIES OF MANAGERS
 
19.                               The business of the Company shall be conducted and managed bythe Managers, acting through the Board, who may pay all expenses incurred in setting up and registering the Company and may exercise all such powers of the Company as are not, by the Law or these Articles or the Operating Agreement, required to be exercised by the Company in general meeting, subject, nevertheless, to any clause of these Articles and the Operating Agreement, to the provisions of the Law, and to such regulations, being not inconsistent with the aforesaid clauses or provisions, as may be prescribed by the Company in general meeting but no regulation made by the Company in general meeting shall invalidate any prior act of the Managers which would have been valid if that regulation had not been made.
 
20.                               All provisions relating to the appointment, powers and duties of Managers, and the appointment, powers and duties of officers, shall be as set out in the Operating Agreement.
 
6

 
21.                               Subject always to the terms of the Operating Agreement, the Managers may exercise all the powers of the Company to borrow money and to mortgage or charge its undertaking, property and uncalled capital or any part thereof, to issue debentures, debenture stock and other securities whenever money is borrowed or as security or guarantee for any debt, liability or obligation of the Company or of any third party.
 
22.                                                        (a)        Subject always to the provisions of the Operating Agreement, the Managers may delegate any of the powers exercisable by them to a person or persons acting individually or jointly as they may from time to time by resolution appoint upon such terms and conditions and with such restrictions as they may think fit, and may from time to time by resolution revoke, withdraw, alter or vary all or any such powers.
 
(b)       All cheques, promissory notes, drafts, bills of exchange and other negotiable instruments, and all receipts for moneys paid to the Company shall be signed, drawn, accepted, endorsed, or otherwise executed, as the case may be, in such manner as the Managers shall from time to time by resolution determine.
 
DISQUALIFICATION AND CHANGES OF MANAGERS
 
23.                               Subject to applicable law, the office of Manager shall be vacated in accordance with the terms of the Operating Agreement.
 
24.                               Any casual vacancy occurring in the Board of Managers may be filled in accordance with the provisions (if any) set out in the Operating Agreement.
 
25.                               The Managers shall only have the power at any time, and from time to time, to appoint a person as an additional Manager or persons as additional Managers in accordance with the provisions (if any) in relation thereto set out in the Operating Agreement.
 
26.                               The Members shall be entitled to appoint and remove a Manager or Managers solely in accordance with the provisions set out in the Operating Agreement.
 
PROCEEDINGS OF MANAGERS
 
27.                               All matters relating to meetings of Managers, including, but without limitation, those relating to the procedure for calling meetings, notices, quorum, voting and alternates and appointment of committees, shall be as set out in the Operating Agreement.
 
28.                               Subject to any contrary provision in the Operating Agreement, the continuing Managers may act notwithstanding any vacancy in their body, but, if and so long
 
7

 
as their number is reduced below the number fixed by or pursuant to the Articles of the Company as the necessary quorum of Managers, the continuing Managers may act for the purpose of increasing the number of Managers to that number, or of summoning a general meeting of the Company, but for no other purpose.
 
29.                               Subject to any contrary provision in the Operating Agreement, any Manager or officer may act by himself or his firm in a professional capacity for the Company, and he or his firm shall be entitled to remuneration for professional services as if he were not a Manager or officer Provided that nothing herein contained shall authorise a Manager or officer or his firm to act as auditor of the Company.
 
30.                               Subject to the provisions of the Operating Agreement, no person shall be disqualified from the office of Manager or prevented by such office from contracting with the Company, either as vendor, purchaser or otherwise, nor shall any such contract or any contract or transaction entered into by or on behalf of the Company in which any Manager shall be in any way interested be or be liable to be avoided, nor shall any Manager so contracting or being so interested be liable to account to the Company for any profit realised by any such contract or transaction by reason of such Manager holding office or of the fiduciary relation thereby established. A Manager shall be counted in the quorum of any relevant meeting which he attends and shall be at liberty to vote in respect of any contract or transaction in which he is so interested as aforesaid provided however that the nature of the interest of any Manager in any such contract or transaction shall be disclosed by him at or prior to its consideration and any vote thereon and a general notice that a Manager is a shareholder of any specified firm or company and/or is to be regarded as interested in any transaction with such firm or company shall be sufficient disclosure hereunder and after such general notice it shall not be necessary to give special notice relating to any particular transaction.
 
31.                               (a)         All acts done by any meeting of the Managers or of a committee of Managers, or by any person acting as a Manager shall, notwithstanding that it be afterwards discovered that there was some inadvertent defect in the appointment of any such Manager or person acting as aforesaid, be as valid as if every such person had been duly appointed and was qualified to be a Manager.
 
(b)        The Managers shall be entitled to act by unanimous written resolution in accordance with the provisions of the Operating Agreement.
 
DISTRIBUTIONS
 
32.                               Subject in each case to restrictions imposed by applicable law, the Company or the Managers may make such distributions to holders of Units in the amounts, at the times, to such persons and in all respects as set out in the Operating Agreement.
 
8

 
33.                               No distribution shall be paid otherwise than out of monies available for payment as a distribution in accordance with the Law.
 
34.                               All other provisions relating to distributions shall be as set out in the Operating Agreement.
 
ACCOUNTS
 
35.                               The books of account relating to the Company’s affairs shall be kept in accordance with the Law and otherwise in such manner as may be determined from time to time by the Company by Ordinary Resolution or failing such determination by the Managers of the Company.
 
36.                               Capital Accounts- A separate Capital Account shall be established and maintained for each Member in the books and records of the Company. The initial balance of a Member’s Capital Account shall equal the original capital contribution made by such Member to the Company. The Capital Account of such Member shall thereafter increase and decrease in the manner as specified in the Operating Agreement. All other provisions governing the operation of Capital Accounts shall be as set out in the Operating Agreement.
 
WINDING UP
 
37.                               All provisions in relation to the winding up of the Company, and the order of distribution of any assets in connection therewith (if applicable), shall be as set out in the Operating Agreement.
 
NOTICES
 
38.                               All provisions relating to the giving and acceptance of notices shall be as set out in the Operating Agreement, unless otherwise set out in these Articles.
 
39.                               If a Member has no registered address and has not supplied to the Company an address for the giving of notice to him, a notice addressed to him and advertised in a newspaper circulating in the Cayman Islands shall be deemed to be duly given to him at noon on the day following the day on which the newspaper is circulated and the advertisement appeared therein.
 
40.                               A notice may be given by the Company to the joint holders of a Membership Interest or Unit by giving the notice to the joint holder named first in the Register of Members in respect of the Membership Interest or Unit.
 
41.                               A notice may be given by the Company to the person entitled to a Membership Interest, including a Unit, in consequence of the death or bankruptcy of a Member by sending it through the post in a prepaid letter addressed to them by
 
9

 
name, or by the title of representatives of the deceased, or trustee of the bankrupt, or by any like description, at the address, if any, supplied for the purpose by the persons claiming to be so entitled, or (until such an address has been so supplied) by giving the notice in any manner in which the same might have been given if the death or bankruptcy had not occurred.
 
42.                               Notice of every general meeting shall be given in some manner hereinbefore authorised to:
 
(a)                                every Member entitled to vote except those Members entitled to vote who (having no registered address) have not supplied to the Company an address for the giving of notices to them; and
 
(b)                               every person entitled to a Membership Interest, including a Unit, in consequence of the death or bankruptcy of a Member, who, but for his death or bankruptcy would be entitled to receive notice of the meeting.
 
No other persons shall be entitled to receive notices of general meetings.
 
RECORD DATE
 
43.                               The Managers may fix in advance a date as the record date for any determination of Members entitled to notice of or to vote at a meeting of the Members, or for any other purpose, in accordance with the provisions set out in the Operating Agreement.
 
AMENDMENT OF MEMORANDUM AND ARTICLES
 
44.                               Subject to and insofar as permitted by the provisions of the Law, the Company may from time to time by Special Resolution alter or amend its Memorandum of Association or these Articles in whole or in part, including, for the avoidance of doubt, by resolution signed by the initial Member of the Company, provided however that no such amendment shall affect the rights attaching to the Members or to any class or series of Units without the consent or sanction provided for in Article 7.
 
ORGANISATION EXPENSES
 
45.                               The preliminary and organisation expenses incurred in forming the Company shall be paid by the Company and may be amortised in such manner and over such period of time and at such rate as the Managers shall determine and the amount shall be paid all in accordance with the provisions set out in the Operating Agreement.
 
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OFFICES OF THE COMPANY
 
46.                            The Registered Office of the Company shall be at such address in the Cayman Islands as the Managers shall from time to time determine. The Company, in addition to its Registered Office, may establish and maintain an office in the Cayman Islands or elsewhere as the Managers may from time to time determine.
 
INDEMNITY
 
47.                            Every Manager and officer for the time being of the Company or any trustee for the time being acting in relation to the affairs of the Company and their respective heirs, executors, administrators, personal representatives or successors or assigns shall be indemnified by the Company to the extent as set out in the Operating Agreement.
 
TRANSFER BY WAY OF CONTINUATION
 
48.                            The Company shall, subject to the provisions of the Law and with the approval of a Special Resolution, have the power to register by way of continuation as a body corporate under the laws of any jurisdiction outside the Cayman Islands and to be deregistered in the Cayman Islands.
 
 	 	 	 	DESCRIPTION OF	
NAME OF SUBSCRIBER	 	ADDRESS	 	SUBSCRIBER	
Huntlaw Nominees Ltd.	 	P.O. Box 1350GT,	 	Company	
 	 	Grand Cayman	 	1 Membership Interest	
 	 	Cayman Islands	 	 	
 	 	 	 	 	
/s/ Sarah Bolton	 	 	 	 	
By: Sarah Bolton	 	 	 	 	

DATED the 5th day of March, Two Thousand and Four.	 	 	
 	 	 	
Witness to the above signature:	 	 	

/s/ Sally Castro	 	 	
Sally Castro	 	 	
 
[SEAL]
[SEAL]
 
11

 
Association of the Company.
 
Special Resolution
 
RESOLVED as a Special Resolution that the Articles of Association of the Company be amended as follows with immediate effect:
 
1.              The current Article 31(b) of the Articles shall be removed and shall be replaced in its entirety by a new Article 31(b) as follows:
 
“31(b). The Managers shall be entitled to act by unanimous written resolution, and a resolution signed by all of the Managers, shall be as valid and effectual as if it had been passed at a meeting of the Managers duly called and constituted. All other provisions relating to written resolutions of the Managers shall be as set out in the Operating Agreement.”
 
RESOLVED to file this resolution with the companies registry.

Dated: 8th March, 2004	 	 	

/s/ Sarah Bolton	 	 	
Forand on behalf of	 	 	
HUNTLAW NOMINEES LTD.	 	 	

 
UNANIMOUS WRITTEN RESOLUTIONS of the SOLE MEMBER of KOSMOS ENERGY HOLDINGS (the “Company”) passed pursuant to Article 16 of the Articles of Association of the Company.
 
Special Resolution
 
RESOLVED as a Special Resolution that the Articles of Association of the Company be amended as follows with immediate effect:
 
1.              The current definition of “Membership Interests” in Article 1(a)(ix) of the Articles shall be removed in its entirety and shall be replaced by a new definition of “Membership Interests” as follows:
 
“Membership Interests”              the property interest as opposed to the personal interest of a Member in the Company, and as a holder of Units, including rights to distributions (liquidating or otherwise), allocations, information, all other rights, benefits and privileges enjoyed by that Member (under the Law, these Articles, the Operating Agreement or otherwise) by virtue of the Units held by that Member and otherwise to participate in the management of the Company; and all obligations, duties and liabilities imposed on that Member (under the Law, these Articles, the Operating Agreement or otherwise) by virtue of the Units held by that Member; provided, however, that such term shall not include any management rights held by a Member solely in its capacity as a Manager;
 
RESOLVED to file this resolution with the companies registry.

Dated: 9 March, 2004	 	 	

/s/ Sarah Bolton	 	 	
For and on behalf of	 	 	
HUNTLAW NOMINEES LTD.	 	 	

Exhibit 10.7

 
CONTRACT MADE THIS 23RD DAY OF JUNE 2008
BETWEEN
 
KOSMOS ENERGY GHANA HC
AND
NOBLE ENERGY EG LTD.
AND
ALPHA OFFSHORE DRILLING SERVICES COMPANY
 
FOR OPERATIONS OFFSHORE GHANA AND EQUATORIAL GUINEA

(ATW NO. 08-006)

 
OFFSHORE DRILLING CONTRACT
 
BETWEEN
 
Kosmos Energy Ghana HC and Noble Energy EG Ltd.
 
AND
 
Alpha Offshore Drilling Services Company
 
Utilizing the “ATWOOD HUNTER”
 
kosmos/Noble/Alpha Drilling Contract Executed 23 June 2008
ATW No. 08-006
 
1

 
OFFSHORE DRILLING CONTRACT
 
TABLE OF CONTENTS
 
SECTION	 	PAGE	
 	 	 	
AGREEMENT	 	8	
1.	DEFINITIONS, INTERPRETATION AND EXHIBITS	 	8	
 	1.1	Definitions	 	 	
 	1.2	Interpretation	 	 	
 	1.3	Exhibits	 	 	
 	 	 	 	 	
2.	PERFORMANCE OF THE SERVICES	 	14	
 	2.1	Several Liability	 	 	
 	2.2	Operational Performance	 	 	
 	2.3	Designation of Well Location(s); Access to Well Location(s)	 	 	
 	2.4	Mobilization and Drilling Unit Movements	 	 	
 	2.5	Not Used	 	 	
 	2.6	Fluids Program	 	 	
 	2.7	Formation and Sampling	 	 	
 	2.8	Additional Well Services Required of Contractor	 	 	
 	2.9	Completion, Re-completion or Working Over of Wells	 	 	
 	2.10	Stoppage of the Services for Convenience	 	 	
 	2.11	Abandonment of Wells	 	 	
 	2.12	Standards of Performance	 	 	
 	2.13	Loss of Control of the Hole and Takeover of the Services by Company	 	 	
 	2.14	Removal of Wreckage	 	 	
 	2.15	Well Records and Reports	 	 	
 	2.16	Loading/Unloading of Supply Vessels	 	 	
 	 	 	 	 	
3.	DURATION OF THE CONTRACT; TERMINATION AND SUSPENSION PROVISIONS	 	20	
 	3.1	Duration of the Contract	 	 	
 	3.2	Initial Operating Term of the Contract; Extensions of the Initial Operating Term of the Contract	 	 	
 	3.3	Termination of the Contract by Company without an Opportunity to Cure Default	 	 	
 	3.4	Termination of the Contract by Company with an Opportunity to Cure Default	 	 	
 	3.5	Termination of the Contract by Company for Convenience	 	 	
 	3.6	Contractor’s Actions on Termination	 	 	
 	3.7	Payments by Company upon Termination of the Contract	 	 	
 	3.8	Reinstatement after Termination for Mechanical Breakdown of Contractor’s Equipment	 	 	
 	3.9	Suspension of the Services for Cause	 	 	
 	3.10	Rights of Company are Subject to Rig Share Agreement	 	 	
 	 	 	 	 	
4.	REPRESENTATIONS AND WARRANTIES	 	27	
 
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 	4.1	Initial Representations	 	 	
 	4.2	Continuing Representations	 	 	
 	 	 	 	 	
5.	SAFETY	 	29	
 	5.1	Notification of Hazardous Conditions & Work Stoppage	 	 	
 	5.2	Health, Safety and Environment Provisions; Drug, Alcohol and Search Policies	 	 	
 	5.3	Contractor’s Safety Management System	 	 	
 	5.4	Installation of Blowout Prevention Devices	 	 	
 	5.5	Notification of Safety Requirements to Personnel on the Drilling Unit & Safety Training	 	 	
 	5.6	Fire Prevention Actions	 	 	
 	5.7	HSE Systems Audit and Inspection	 	 	
 	5.8	Material Safety Data Sheets	 	 	
 	5.9	Emergency Evacuation Plan	 	 	
 	5.10	Waste Disposal	 	 	
 	5.11	Contractor’s Subcontractors	 	 	
 	 	 	 	 	
6.	CONTRACTOR’S PERSONNEL AND EQUIPMENT; IMPORT AND EXPORT OBLIGATIONS	 	32	
 	6.1	Contractor’s Personnel	 	 	
 	6.2	Contractor’s Drilling Unit, Services and Supplies	 	 	
 	6.3	Import/Export Obligations	 	 	
 	 	 	 	 	
7.	ITEMS TO BE FURNISHED BY COMPANY	 	43	
 	7.1	Company Items	 	 	
 	7.2	Emergency Medical Treatment and Emergency Medical Evacuation	 	 	
 	 	 	 	 	
8.	COMPENSATION	 	44	
 	8.1	Service Rates	 	 	
 	8.2	Effect of Mechanical Failure or Damage to the Drilling Unit	 	 	
 	8.3	Variation of Service Rates	 	 	
 	8.4	Variation of Rates Due to Changes in Law	 	 	
 	 	 	 	 	
9.	REIMBURSEMENTS TO CONTRACTOR	 	51	
 	9.1	Reimbursement for Additional Materials and Services.	 	 	
 	9.2	Requirement to Competitively Bid	 	 	
 	9.3	Reimbursement for Additional Personnel	 	 	
 	9.4	Reimbursement for Contractor’s Personnel Air Transportation	 	 	
 	9.5	Reimbursement for Meals and Lodging	 	 	
 	 	 	 	 	
10.	FINANCIAL MATTERS	 	52	
 
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 	10.1	Contractor’s Invoices (Kosmos)	 	 	
 	10.2	Invoice Payments	 	 	
 	10.3	No Waiver of Company’s Rights	 	 	
 	10.4	Liens and Subcontractor Payments	 	 	
 	10.5	Overpayments	 	 	
 	10.6	Electronic Procurement	 	 	
 	10.7	Contractor’s Invoices (Noble)	 	 	
 	10.8	Invoice Payments	 	 	
 	10.9	No Waiver of Company’s Rights	 	 	
 	10.10	Liens and Subcontractor Payments	 	 	
 	10.11	Overpayments	 	 	
 	10.12	Electronic Procurement	 	 	
 	 	 	 	 	
11.	CONFLICT OF INTEREST, IMPROPER INFLUENCE AND DATA PRIVACY	 	59	
 	11.1	Conflict of Interest	 	 	
 	11.2	Improper Influence	 	 	
 	11.3	Data Privacy	 	 	
 	 	 	 	 	
12.	CONTROLS, RECORDS AND INSPECTION	 	61	
 	12.1	Controls	 	 	
 	12.2	Records	 	 	
 	12.3	Retention of Records	 	 	
 	12.4	Inspection of Records	 	 	
 	12.5	Access and Assistance	 	 	
 	12.6	Use of Information	 	 	
 	12.7	Confidentiality	 	 	
 	 	 	 	 	
13.	TAXES	 	63	
 	13.1	Contractor’s Taxes	 	 	
 	13.2	Company’s Taxes	 	 	
 	13.3	VAT, GST, Sales and Similar Taxes	 	 	
 	13.4	Subcontractor Taxes	 	 	
 	13.5	Reports and Withholding	 	 	
 	13.6	Tax Records	 	 	
 	13.7	Cooperation	 	 	
 	 	 	 	 	
14.	CLAIMS, LIABILITIES AND INDEMNITIES	 	65	
 
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 	14.1	Intent of Indemnity Provisions	 	 	
 	14.2	Property	 	 	
 	14.3	Indemnitees’ Property	 	 	
 	14.4	Illness, Injury or Death	 	 	
 	14.5	Pollution Damage	 	 	
 	14.6	Limitation on Liability for Well Event Control Costs and Well Event Pollution Costs	 	 	
 	14.7	Use of Medical Facilities or Medical Evacuation	 	 	
 	14.8	Intellectual Property	 	 	
 	14.9	Fines and Assessments	 	 	
 	14.10	Conflict of Interest and Improper Influence	 	 	
 	14.11	Breach of Applicable Law	 	 	
 	14.12	Indemnity for Liens	 	 	
 	14.13	Indemnity for Import and Export Obligations	 	 	
 	14.14	Limitation on Damages	 	 	
 	14.15	Application of Release and Indemnity Obligations; Exclusion for Sole Negligence or Willful Misconduct	 	 	
 	14.16	Defense of Claims	 	 	
 	14.17	Duration of Indemnity, Release and Defense Obligations	 	 	
 	 	 	 	 	
15.	MUTUAL RELEASE AND INDEMNITY BETWEEN CONTRACTOR AND RELEASED CONTRACTORS; INSURANCE	 	74	
 	15.1	Definition of Released Contractor	 	 	
 	15.2	Definition of Released Contractor Group	 	 	
 	15.3	Release, Defense and Indemnity Obligations	 	 	
 	15.4	Application of Release and Indemnity Obligations; Exclusion for Gross Negligence or Willful Misconduct	 	 	
 	15.5	Insurance	 	 	
 	15.6	Subcontract Requirements	 	 	
 	 	 	 	 	
16.	INSURANCE	 	76	
 	16.1	Effect of Insurance on Contractor’s Liability and Indemnity Obligations	 	 	
 	16.2	Insurance Required of Contractor	 	 	
 	16.3	Policy Endorsements	 	 	
 	16.4	Evidence of Insurance	 	 	
 	16.5	Deductibles or Self-Insured Retentions	 	 	
 	16.6	Waiver of Subrogation for Contractor’s Property Damage Insurance	 	 	
 	16.7	Insurance Required from Subcontractors	 	 	
 	16.8	Insurance Provided by Company	 	 	
 	 	 	 	 	
17.	CONTRACT INFORMATION	 	80	
 
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 	17.1	Confidentiality of Contract Information	 	 	
 	17.2	Permitted Disclosure	 	 	
 	17.3	Required Disclosure	 	 	
 	17.4	Use of Contract Information	 	 	
 	17.5	Ownership of Property Rights	 	 	
 	17.6	Equitable Relief	 	 	
 	17.7	No License	 	 	
 	17.8	Return of Contract Information	 	 	
 	 	 	 	 	
18.	BUSINESS RELATIONSHIP	 	82	
 	18.1	Contract for Services	 	 	
 	18.2	Independent Contractor	 	 	
 	18.3	Contractor’s Responsibility for Obligations of the Contractor Group	 	 	
 	18.4	Control over Performance	 	 	
 	 	 	 	 	
19.	ASSIGNMENT	 	82	
 	19.1	Assignment By Contractor	 	 	
 	19.2	Assignment By Company	 	 	
 	19.3	Successors and Assigns	 	 	
 	 	 	 	 	
20.	FORCE MAJEURE	 	83	
 	20.1	Definition of Force Majeure Event	 	 	
 	20.2	Excuse of Performance due to a Force Majeure Event	 	 	
 	20.3	Notice and Mitigation	 	 	
 	20.4	Termination of the Contract due to a Force Majeure Event	 	 	
 	 	 	 	 	
21.	GOVERNING LAW AND RESOLUTION OF DISPUTES	 	85	
 	21.1	Governing Law	 	 	
 	21.2	Resolution of Disputes	 	 	
 	21.3	Direct Negotiations	 	 	
 	21.4	Mediation	 	 	
 	21.5	Arbitration	 	 	
 	21.6	Additional Arbitration Provisions	 	 	
 	21.7	Enforceability	 	 	
 	21.8	Confidentiality	 	 	
 	 	 	 	 	
22.	NOTICES, REPRESENTATIVES AND CONTACT INFORMATION	 	88	
 	22.1	Notices	 	 	
 	22.2	Representatives and Contact Information	 	 	
 	 	 	 	 	
23.	PUBLIC ANNOUNCEMENTS	 	88	
24.	THIRD PARTY RIGHTS	 	88	
25.	GENERAL PROVISIONS	 	88	
 
6

 
 	25.1	Prior Agreements	 	 	
 	25.2	Amendment	 	 	
 	25.3	Waiver	 	 	
 	25.4	Severability	 	 	
 	25.5	Survival	 	 	
 	25.6	Time of the Essence	 	 	
 	25.7	Counterparts	 	 	
 	25.8	Drafting	 	 	
 	25.9	Parent Company Guarantee	 	 	
 	 	 	 	 	
26.	CHANGE OF LOCALE FOR THE OPERATIONS	 	90	
 
EXHIBIT A — SCOPE OF WORK
 
 	ATTACHMENTS TO EXHIBIT A:
 
Attachment Al             Drilling and Ancillary Equipment Specifications
Attachment A2 —Equipment, Supplies, Materials, and Services to be Furnished by Company and Contractor
Attachment A3                 Personnel to be Furnished by Contractor
Attachment A4 — Drilling Unit Commissioning, Inspection and Acceptance Requirements
Attachment A5 - Drill String Component Inspection Requirements
Attachment A6 - Drilling Hoisting Equipment Inspection Requirements
Attachment A7 - BOP Acceptance, Inspection and Testing
Attachment A8 — Environmental, Safety, Fire and Health Systems Audit and Inspection
Attachment A9                  Contractor’s Safety Management System
Attachment A10                Application for Permit to Operate in Ghana	
 
EXHIBIT B — INDEPENDENT CONTRACTOR HEALTH, ENVIRONMENTAL AND SAFETY GUIDELINES
EXHIBIT C      DRUG, ALCOHOL AND SEARCH POLICY
EXHIBIT D — COMPENSATION
EXHIBIT E - RIG SHARING AGREEMENT
EXHIBIT F - INVOICING PROCEDURES - KOSMOS
EXHIBIT G -  BUSINESS CONDUCT - FCPA
EXHIBIT H -  PARENT COMPANY GUARANTEE
 
7

 
OFFSHORE DRILLING CONTRACT
 
This OFFSHORE DRILLING CONTRACT (“Contract”) dated as of June 23, 2008 (the “Effective Date”) is made by and between  Kosmos Energy Ghana HC  a company, with offices at Clifton House, 75 Fort Street, George Town, Grand Cayman, Cayman Islands (hereinafter referred to as “Kosmos” or “Company” as appropriate);  Noble Energy EG Ltd.,  a company with offices at 100 Glenborough Drive, Suite 100, Houston, Texas 77067 (hereinafter referred to as “Noble” or “Company” as appropriate) and  Alpha Offshore Drilling Services Company,  a Cayman Islands company, with its registered office located at M&C Corporate Services Ltd., P.O. Box 309 GT, Ugland House, South Church Street, George Town, Grand Cayman, Cayman Islands (hereinafter referred to as “Contractor”).
 
RECITALS
 
A.                                  Contractor is a drilling contractor and Contractor represents that it has a deepwater, moored semi-submersible Drilling Unit, appropriate equipment in good working order and qualified, trained personnel capable of carrying out Operations in a good and workmanlike manner and in various locations offshore Ghana (for Kosmos as Company) and Equatorial Guinea (for Noble as Company) where Company desires Services, including but not limited to, the performance of offshore drilling services, which may include drilling, working over, logging, testing, completing, deepening or abandoning wells under the terms and conditions set out in this Contract.
 
B.                                    Contractor has significant experience relevant to these offshore drilling services, has appropriate equipment in good working order, and desires, itself and through subcontractors, to provide these services for the benefit of Company under the terms and conditions set out in this Contract.
 
C.                                    Kosmos and Noble have agreed to share the use of the Drilling Unit for a 1,240 days drilling program (exclusive of Mobilization) offshore Ghana (for Kosmos for approximately 810 days) and Equatorial Guinea (for Noble for approximately 430 days) with a one (1) year option.
 
D.                                   In consideration of the mutual promises set out in this Contract, and other good and valuable consideration, the receipt and sufficiency of which is acknowledged, Noble, Kosmos, and Contractor agree to be bound by the terms of this Contract.
 
AGREEMENT
 
1.                                DEFINITIONS, INTERPRETATION AND EXHIBITS
 
1.1                                            Definitions.As used in this Contract, these words or expressions have the following meanings:
 
“Affiliate” means any legal entity which controls, is controlled by, or is under common control with, another legal entity. An entity is deemed to “control” another if it owns directly or indirectly at least fifty percent of either of the following:
 
(A)   The shares entitled to vote at a general election of directors of such other entity.
 
8

 
(B)   The voting interest in such other entity if such entity does not have either shares or directors.
 
“Area of Operations” means the areas described in Exhibit A — Scope of Work where any member of Contractor Group performs or is expected to perform the Services.
 
“Claim” means any claim, liability, loss, demand, damages, Lien, cause of action of any kind, obligation, costs, royalty, fees, assessments, penalties, fines, judgment, interest and award (including legal counsel fees and costs of litigation legally recoverable by the Person asserting the original Claim), whether arising by law, contract, tort, or otherwise, and including any Claim arising out of ingress, egress, loading, or unloading of personnel or cargo.
 
“Commencement Date” means the date on which all of the following requirements have occurred:
 
(A)         The Drilling Unit has commenced mobilization pursuant to Section 2.4 herein and is one (1) nautical mile from Noble’s Affiliate’s last well location in Israel.
 
(B)          All inspections, certifications and tests specified in Attachments A4, A5, A6 and A7 of Exhibit A — Scope of Work together with any repairs or replacement of parts or equipment necessary after such inspections, certifications or tests in accordance with Sections 5.7 and 6.2 of this Contract have been satisfactorily completed.
 
(C)          Contractor obtains all necessary permits and licenses required to conduct the Services, except those required under the Contract to be obtained by Company.
 
“Company” means Kosmos in connection with Kosmos’ use of the Drilling Unit and Noble in connection with Noble’s use of the Drilling Unit.
 
“Company Group” means Company, Company’s Affiliates, Joint Interest Owners and their Affiliates, and the directors, officers and employees of all of them, and any other Person (excluding Contractor Group, Company’s contractors and their subcontractors and the employees of those contractors and subcontractors) whose presence in the Area of Operations is by invitation of any member of Company Group.
 
“Company Representative” means the person identified as the Company Representative, as set out in the Exhibit A — Scope of Work to this Contract, or any other person replacing that individual as Company Representative in accordance with Section 22.2(B).
 
“Contract Information” means all information (including business, technical and other information), data, knowledge, works and ideas that are provided or made available to Contractor by Company orally, visually, by document, electronic mail, computer disks, magnetic tape, or by any other manner, whether directly or indirectly, for the purposes of this Contract or that Contractor learns, discovers, develops or creates as a consequence of or arising out of Contractor entering into this Contract or performing the Services, including all original works of authorship, inventions, discoveries and improvements that are made or conceived by Contractor Group in the performance of the Services and all
 
9

 
intellectual property rights associated with those original works of authorship, inventions, discoveries and improvements, but does not include information that is any of the following:
 
(A)         Contractor Background Technology.
 
(B)          Available generally to the public, as evidenced by printed publication or similar proof, through no act or omission of Contractor Group.
 
(C)          Independently made available to Contractor by a third party with a legal right to disclose that information without restriction.
 
Detailed information shall not be excluded from the definition of Contract Information merely because it is embraced by more general information excluded under paragraphs (A), (B) or (C) above. Combinations of items shall not be so excluded unless the combination itself and its principle of operation fall within paragraphs (A), (B) or (C) above.
 
“Contractor” means the Person defined as “Contractor” in the introductory paragraph of this Contract.
 
“Contractor Background Technology” means technical information and know-how, including any invention, improvement or discovery, whether or not patentable, that is conceived, owned or controlled by Contractor prior to the Effective Date or that is generated or created independently of this Contract during or after the duration of this Contract, including any patent rights which claim such technical information, know-how, or both.
 
“Contractor Group” means Contractor, Contractor’s Affiliates, Subcontractors, and directors, officers, employees and other personnel of all of them, and any Person acting on behalf of any of them in connection with any subject matter of this Contract, or whose presence in the Area of Operations is by invitation of any member of Contractor Group.
 
“Contractor Representative” means the person identified as Contractor Representative, as set out in the Exhibit A — Scope of Work to this Contract, or any other person replacing that individual as Contractor Representative in accordance with Section 22.2(B).
 
“Controls” means the collection of internal processes (including policies, procedures, codes and other internal management systems) adopted by an organization for any of the following purposes:
 
(A)         To obtain assurances that the organization and its directors, officers, employees and other personnel (and any other Person acting on behalf of any of them in relation to the organization or its activities) comply with applicable laws and regulations and the policies of that organization.
 
(B)          To obtain assurances that the financial reporting of the organization is reliable, that its assets are safeguarded and that its operations are effective.
 
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(C)          To help determine how the organization, its directors, its officers, its employees and its other personnel (and any other Person acting on behalf of any of them in relation to the organization or its activities) perform or behave, including the assessment of the effectiveness of, and the correction of any deficiencies in, such Controls.
 
“Country” has the meaning given in Exhibit A — Scope of Work as it applies respectively to the Kosmos or Noble portions of the Work.
 
“Currency” has the meaning given in Exhibit D — Compensation.
 
“Dispute” means any dispute or controversy arising out of this Contract or the performance of the Services, including a Claim under this Contract and any dispute or controversy regarding the existence, construction, validity, interpretation, enforceability or breach of this Contract.
 
“Drill String” has the meaning stated in Section 6.2(F).
 
“Drilling Unit” means the deepwater moored semi-submersible drilling rig and its ancillary equipment used for the Services that arc described in Attachment Al to Exhibit A — Scope of Work.
 
“Effective Date” means the date defined as “Effective Date” in the introductory paragraph of this Contract.
 
“Exhibit” means a document referred to in Section 1.3(A).
 
“Force Majeure Event” has the meaning given in Section 20.
 
“Import/Export Charges” has the meaning given in Section 6.3(A)(1).
 
“Import/Export Exemptions” has the meaning given in Section 6.3(A)(2).
 
“Import/Export Items” has the meaning given in Section 6.3(A)(3).
 
“Indemnitee” means each Person who is a member of Company Group.
 
“Joint Interest Owner” means a Person (including a co-interest owner, joint venturer, partner or co-lessee of Company) who shares an economic interest in common with Company or an Affiliate of Company in relation to the Area of Operations.
 
“Lien” means charge, encumbrance or similar right available to creditors at law to secure debts owed to them.
 
“Mobilization Completion Date” means completion of mobilization of the Drilling Unit to within one (1) nautical mile of Kosmos’ first well location.
 
“Operating Term” has the meaning described in Section 3.2(A) as it may be extended in Sections 3.2 (B), (C), (D) & (E).
 
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“Party” means Company or Contractor and “Parties” mean both of them.
 
“Payroll Burden” has the meaning given in Exhibit D — Compensation.
 
“Person” means an individual, corporation, company, state, statutory corporation, government entity or any other legal entity.
 
“Personnel Rates” means the day rates for Contractor’s personnel as specified in Attachment A3 to Exhibit A - Scope of Work.
 
“Point of Origin” and “Port of Entry” for Contractor’s equipment and personnel means the locations specified in Exhibit A — Scope of Work. Exhibit A — Scope of Work may provide for different Points of Origin for expatriate and local personnel.
 
“Pollution” means a continuous or intermittent seepage, release, spill, leak, blowout, or discharge of whatever nature or kind of gaseous, semi-solid, solid or liquid materials.
 
“Property” of a Person means property owned, leased or furnished by that Person or in which that Person has an economic interest.
 
“Public International Organization” means an international organization formed by states, governments, or other public international organizations, whatever the form of organization and scope of competence.
 
“Records” means information in any recorded form, whether electronic or otherwise, including books, papers, documents, contracts, financial accounts, ledgers, recordings, purchase orders, invoices, vouchers, receipts, manifests, correspondence, memoranda, instructions, plans, drawings, personnel records, timesheets, payroll records, inspection records, registers, statements, reports, written and other information on procedures and Controls, computer data and other data.
 
“Released Contractor” has the meaning given in Section 15.1.
 
“Released Contractor Group” has the meaning given in Section 15.2.
 
“Rig Sharing Agreement” means that certain document as agreed by the Parties, a copy of which is attached as Exhibit E.
 
“Services”, “Work” or “Operations” (except as referenced to Company’s operations) means the offshore drilling, suspending, or abandoning, sidetracking (which for the sake of clarity includes the drilling of multilateral wells), logging, testing, completion, work over, deepening, installing Subsea completions, fishing, piling and workovers and other work to be performed by Contractor under this Contract, including the mobilizations and demobilizations, and all other work or goods required in connection with Company’s exploration and development activities specified by Company from time to time together with Drilling Unit moves between Company’s well locations and while moving between countries for the respective Kosmos and Noble portions of the respective drilling programs during the duration of the Contract.
 
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“Subcontractor” means any Person who is engaged by Contractor or any Subcontractor to provide the Services (other than a Person engaged as an employee).
 
“Third Party” means any Person not a member of Company Group, Contractor Group, or Released Contractor Group.
 
“Well Event” means a blowout of a well or other uncontrolled well flow.
 
“Well Event Control Costs” means all of the following:
 
(A)                             The cost of regaining or attempting to regain control of a well following a Well Event affecting that well, including drilling of wells used for pressure relief to regain control and extinguishing or attempting to extinguish fires resulting from that Well Event.
 
(B)                               Thecost of restoring, re-drilling or plugging and abandoning a well where restoration, re-drilling or plugging and abandoning is necessary because of a Well Event.
 
(C)                               Loss of oil or gas.
 
(D)                              Damage to the hole, the formation, strata or reservoir.
 
“Well Event Pollution Costs” mean all Claims for damage or loss to property caused by pollution or contamination that arises from a Well Event, including cleanup costs. Well Event Pollution Costs do not include Claims made against or suffered by any member of Contractor Group for damage or loss to property of any member of Contractor Group.
 
1.2                                Interpretation.Unless the context expressly requires otherwise, all of the following apply to the interpretation of this Contract:
 
(A)                   The plural and singular words each include the other.
 
(B)                     The masculine, feminine and neuter genders each include the others.
 
(C)                     The word “or” is not exclusive.
 
(D)                    The word “includes” and “including” are not limiting.
 
(E)                      References to matters “arising” (or which “arise” or “arises”) “out of this Contract” include matters which arise in connection with this Contract or have a causal connection with or which flow from this Contract or which would not have arisen or occurred but for the entering into this Contract or the performance of or failure to perform obligations under this Contract.
 
(F)                      The headings in this Contract are included for convenience and do not affect the construction or interpretation of any provision of, or the rights or obligations of a Party under, this Contract.
 
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(G)                     All obligations and rights of the Parties under this Contract shall be enforceable as of the Effective Date unless the text specifically makes such enforceable as of the Commencement Date.
 
1.3                                Exhibits.
 
(A)                   All of the Exhibits that are attached to the body of this Contract are an integral part of this Contract and are incorporated by reference into this Contract, including:
 
(1)          Exhibit A – Scope of Work and its Attachments.
 
(2)          Exhibit B – Independent Contractor Health, Environmental and Safety Guidelines.
 
(3)          Exhibit C – Drug, Alcohol and Search Policy.
 
(4)          Exhibit D – Compensation.
 
(5)          Exhibit E     Rig Sharing Agreement.
 
(6)          Exhibit F – Invoicing Procedures – Kosmos
 
(7)          Exhibit G    Business Conduct – FCPA
 
(8)          Exhibit H - Parent Company Guarantee
 
(B)                     If a conflict exists between the body of this Contract and the Exhibits, the body prevails to the extent of the conflict.
 
(C)                     If a conflict exists between the Exhibits or within an Exhibit as they apply to Contractor, a resolution shall be mutually agreed by the Parties; failing which the conflict shall be resolved in accordance with Section 21 of this Contract.
 
2.          PERFORMANCE OF THE SERVICES
 
2.1                                Several Liability.Kosmos and Noble are each severally, but not jointly, liable to Contractor for their respective use of the Drilling Unit under this Contract. Kosmos and Noble shall each use the Drilling Unit in direct continuation of one another, and such use shall be subject to the Rig Sharing Agreement. For all matters relating to or arising out of their respective use of the Drilling Unit, Kosmos and Noble (and their respective assigns if applicable) shall each be defined and referred to as Company throughout this Contract.
 
2.2                                Operational Performance.Contractor shall utilize Contractor’s Drilling Unit and personnel to carry out all Services as specified by Company at any location designated by Company within the Area of Operations. This Contract shall govern all Services undertaken by Contractor for Company.
 
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(A)                   Contractor shall furnish the Drilling Unit and all equipment, machinery, drill strings, tools, spare parts, materials and supplies that are specified in Attachments Al and A2 to Exhibit A — Scope of Work as well as such other items which are customarily provided by drilling contractors engaged to perform similar services, except for those items referenced in Section 7.1. Contractor shall maintain adequate stock levels of the items to be furnished and arrange for their replenishment as necessary for the prompt and efficient performance of Services.
 
(B)                     The Drilling Unit and all equipment provided by Contractor and used in the performance of the Services must be in good working order and repair and be suitable for, and capable of safely and properly performing the Services as and when required under this Contract.
 
(C)                     In the performance of the Operations, Contractor shall specifically perform the following:
 
(1)                  Operate the Drilling Unit in conformity with all applicable laws, certifications, licenses and manufacturer’s requirements, except that Contractor may use qualified facilities other than the manufacturer’s to perform maintenance and may use experienced—based maintenance to enhance the equipment and/or reliability as required by that experience. Notwithstanding the above, Contractor shall advise Company for its approval under the PMS provisions indicated in Section 6.2(D)(2) below. Contractor shall provide to Company data that supports the use of non-original equipment manufacturer service and parts on a case by case basis.
 
(2)                  Maintain the Drilling Unit in proper and safe operating condition.
 
(3)                  Promptly make any repairs needed for the proper and safe operation of the Drilling Unit at Contractor’s sole cost and expense unless otherwise provided for in this Contract.
 
(4)                  Direct the overall moving operations of the Drilling Unit.
 
(5)                  Ensure that the Drilling Unit position is maintained throughout Operations.
 
(D)                    Without prejudice to the generality of the foregoing:
 
(1)                  It shall be the responsibility of the Contractor to determine at all times whether Operations, including towing and moving the Drilling Unit, can be safely undertaken or continued, including but without limitation the duty and responsibility to determine by the Contractor’s own inspection that all cargo and items of equipment are loaded and stored aboard the Drilling Unit in a secure and seaworthy manner, that all proper and necessary precautions are taken for the safety of all personnel aboard the Drilling Unit, and that the Drilling Unit is in all respects in a condition
 
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suitable to undertake any contemplated Operations including towing and moving the Drilling Unit as aforesaid under the then prevailing or reasonably foreseeable sea and weather conditions.
 
(2)                  The Contractor shall decide when in the face of impending adverse sea or weather conditions it is necessary to institute precautionary measures in order to safeguard the well, the well equipment, the Drilling Unit or personnel aboard the Drilling Unit and shall ensure that all such measures are promptly taken. The Contractor shall keep the Company fully informed of all actions taken under this Section 2.2(D)(2) and specifically in the case of measures taken in order to safeguard the well and the well equipment and will, except when impractical due to urgent necessity, consult with the Company before taking such measures.
 
(3)                  In the event that the Contractor should consider it necessary at any time to suspend Operations for safety reasons, it shall immediately notify the Company of that fact and of the reasons therefore.
 
(4)                  For the avoidance of doubt it is expressly agreed that neither the presence on board the Drilling Unit of Company’s Representative nor the presence of any other Company personnel, regardless of whether an employee or contractor of the Company, including without limitation during tows and moves of the Drilling Unit, shall relieve the Contractor of any of its obligations and responsibilities under the Contract.
 
2.3                                Designation of the Well Location(s); Access to Well Location(s).
 
(A)           Designation of the Well Location(s).TheArea of Operations and/or the location(s) of well(s) to be drilled/worked-over shall be designated in Exhibit A — Scope of Work. Company shall select, survey, mark, and provide coordinates of the well location(s) in accordance with Contractor’s requirements and shall provide Contractor with information for each proposed well location as per the provisions of Section 2.3(B). Contractor shall have the right to review such information and request additional information and data.
 
(B)           Access to Well Location(s).
 
(1)                  Company shall provide Contractor with suitable access to and egress from the well location(s). Company shall survey, or have surveyed by a third party, each well location with DGPS or other appropriate means, along with bathymetric data needed by Contractor.
 
(2)                  The Party responsible for providing permissions necessary to enter the Area of Operations to operate at the drilling location selected by Company shall be identified in Exhibit A — Scope of Work.
 
(3)                  Company will provide information in its possession relative to sea bottom conditions, at the drilling location or within the prospective anchor
 
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pattern including information from marine well site surveys contracted by Company for the drilling location.
 
(4)                  Company shall provide the Drilling Unit with sound well locations for all Operations, free of obstacles and obstructions and provide a conductor pipe program adequate to prevent soil and subsoil washout.
 
2.4                                Mobilization and Drilling Unit Movements.Contractor shall direct the mobilization and movement of the Drilling Unit. Such operations may include, towing, positioning, pre-loading, ballasting, de-ballasting, anchoring, rigging up, mooring and unmooring the Drilling Unit at each drilling location. When the Drilling Unit and Contractor’s equipment is being mobilized from Israel to Ghana, Noble shall be responsible for 66.6°° and Kosmos will be responsible for 33.4°° of the mobilization costs from the commencement of the mobilization at one (1) nautical mile from the last well location offshore Israel until the Drilling Unit reaches the latitude of 17 degrees North offshore Mauritania (the “Mauritania Line”). Upon reaching Mauritania Line, the balance of the mobilization of the Drilling Unit to Ghana shall be shared equally (50°°/50°°) by Kosmos and Noble until the Drilling Unit is within one (1) nautical mile of Kosmos’ first well location when the entire mobilization cost burden shall be fully assumed by Kosmos. Mobilization shall be conducted at ninety percent (90°°) of the Operating Rate plus Company’s provision of appropriate tow/transport vessel(s) and fuel. All commercial terms as well as all liability and indemnity provisions of the Contract shall apply from the commencement of the mobilization of the Drilling Unit from Israel and throughout the duration of the Contract.
 
2.5                                Not used.
 
2.6                                Fluids Program.Contractor shall assist Company’s other contractors to make, maintain and use drilling mud or completion fluids with appropriate properties for the well, including but not limited to, weight loss, viscosity and other general characteristics in accordance with such fluids program as Company may designate, subject only to safety considerations pursuant to Section 5, and at the cost of the Party designated in Attachment A2 to Exhibit A — Scope of Work. At all times, Contractor shall exercise due care and diligence in keeping the hole and all strings of casing and spaces between casing filled with drilling and or completion fluids. If Company requests, Contractor shall test drilling and/or completion fluids at least twice each tour for weight loss, viscosity and other general characteristics. Contractor shall record the results of such tests and use of fluids and additive materials in its daily drilling reports.
 
2.7                                Formation and Sampling. Contractor shall assist Company’s other contractors to keep accurate measurements and records of all formations encountered and notify Company immediately when any oil or gas-bearing formation is detected or encountered. If Company requests, Contractor shall also collect, save and identify all cores and cuttings taken according to Company’s instructions and place them in labeled, separate containers to be furnished by Company, if required by Company as set forth in Attachment A2 to Exhibit A —
 
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Scope of Work. Cuttings and cores shall be made available to Company at the location and kept in proper storage until Company takes final possession of them.
 
2.8                                Additional Well Services Required of Contractor.Contractor shall, while drilling the well(s), measure deviation from the vertical if requested by Company, measure the depth of the hole, and if necessary in the opinion of Company, plug back or sidetrack. Contractor shall at any time prior to completion or abandonment of a well, perform any and all tests, measurements and other well services requested by Company as set forth in Attachment A2 to Exhibit A — Scope of Work.
 
2.9                                Completion, Re-completion or Working Over of Wells.Company may at any time elect to have a well completed, re-completed, worked-over or suspended at any time. Upon notice of such election, Contractor shall perform the work of completing, re-completing or working over the well in accordance with the program provided by Company in a manner and to the extent desired by Company.
 
2.10                          Stoppage of the Services for Convenience.Company may elect to stop the Services at any time for convenience without any default by Contractor in performance of the Services. Contractor shall be paid at the applicable rate provided for in Section 8.2(D) or (E) as applicable during any stoppage period.
 
2.11                          Abandonment of Wells.Company may at any time elect to have a well abandoned at any depth. Upon notice of such election, Contractor shall abandon the hole in accordance with the program provided by Company, in a manner satisfactory to Company and in compliance with all applicable governmental rules and regulations with respect to well abandonment. Upon abandonment of a well, Contractor shall remove from the location the Drilling Unit and such other equipment, materials and supplies furnished by it and by Company within the number of days set forth in Exhibit A — Scope of Work after the completion of the Services.
 
2.12                          Standards of Performance.Contractor warrants that:
 
(A)          Contractor has and will utilize in Services under this Contract the technical competence, financial capacity, management skills, competent and qualified personnel and equipment necessary to carry out the duties and responsibilities of a competent drilling contractor as are specified in this Contract.
 
(B)            Contractor shall conduct all Services in a diligent, workmanlike manner, and in accordance with accepted and prudent oil field practices and international professional standards.
 
(C)            Contractor shall use all reasonable efforts to avoid any disturbances in the existing labor situation that would adversely affect the business of the Company, its Affiliates or other contractors in the Area of Operations. Contractor shall promptly notify Company of any labor problems that have a potential to interrupt Services.
 
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(D)             Contractor shall perform the Services in compliance with applicable laws, regulations, codes and standards imposed by law, and applicable codes and standards which have been adopted by Company and notified to Contractor.
 
2.13                            Loss of Control of the Hole and Takeover of the Services by Company.
 
(A)            Subject to the provisions of this Section 2.13, if fire or blowout occurs while Contractor is working on a drilling location, Contractor shall endeavor to control any such fire or blowout.
 
(B)              Subject to Section 8.1(G) and Section 14.6, if the hole is lost or damaged, Contractor shall, at Company’s election, drill a relief well, a new hole on the same location or re-drill sections of the existing hole as Company may require. Contractor will coordinate with Company and Contractor’s underwriters on the selection of an adequate location for drilling a relief well.
 
(C)              In addition to the provisions of Sections 2.13(A) and 2.13(B), Company has the right to take over complete control and supervision of those Services required to bring a well under control or for the reasons provided in Section 2.13(D). However, such take over shall not extend to the marine functions of the Drilling Unit, although decisions relative to the movement of the Drilling Unit may be undertaken by Company and carried out by Contractor’s personnel. If Company exercises this right, Contractor shall give Company full use of Contractor’s Drilling Unit and other equipment, materials, supplies and personnel at the well location subject to both of the following considerations:
 
(l)                                    Contractor shall continue to maintain the insurances set forth in Section 16, subject to insurer’s approval which Contractor must use its best efforts to obtain.
 
(2)                                 Therate of compensation that Contractor is entitled to receive during the time that Company is in control of the Drilling Unit shall be the rate (as set out in Exhibit D — Compensation) in effect on the date of the take over of the Drilling Unit by Company reduced by an amount equal to the Personnel rates shown in Attachment A3 of Exhibit A — Scope of Work for the Contractor personnel released from the Drilling Unit as agreed by the Parties. Should a rate for a Contractor person not be listed then the rate shall be calculated as actual costs for salary (plus Payroll Burden) for Contractor’s personnel.
 
(D)             If in the circumstances contemplated under this Section 2.13, Contractor fails to conduct the well control activities as required in this Contract, Company may give written notice of this failure to Contractor. In this event, Company has the right to take over complete control and supervision of the well control activities.
 
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2.14                                     Removal of Wreckage.
 
(A)             If the Drilling Unit or any part thereof is lost or damaged beyond repair and removal is required by law or governmental authority, or the wreckage is interfering with Company’s operations in Company’s opinion, Contractor shall promptly remove such damaged or lost Drilling Unit or part thereof from the Area of Operations at Contractor’s sole cost.
 
(B)               Notwithstanding the provisions of Section 2.14(A), in the event that the Drilling Unit cannot be raised and/or removed with available technology and equipment due to water depth and a governmental authority orders removal of such wreckage, then Contractor and Company shall work together in an attempt to obtain a waiver from applicable governmental authorities for the obligation to remove the wreckage.
 
2.15                                     Well Records and Reports.
 
(A)             Contractor shall maintain an authentic, legible, and accurate history and log of Services performed on forms and in a manner prescribed by Company (including all measurements required for fishing operations with a record of all downhole equipment). The history and log shall be open at all times to inspection by Company and furnished to its authorized employees and representatives upon their request.
 
(B)               Contractor shall maintain continuous recordings of the total measured depth, the rate of penetration, weight of Drill String, pump pressure, torque, rotary speed, pit level and flow charts. Contractor shall provide copies thereof’ to Company’s Representative as requested.
 
(C)               Contractor shall furnish Company’s Representative with a daily written report, on forms and in the language prescribed by Company, showing depths and Services performed during the preceding twenty-four hours and any other information relative to the day’s Services requested by Company. All such reports shall be legible and accurate.
 
2.16                                     Loading/Unloading of Supply Vessels.Contractor’s personnel shall load and unload supply vessels to/from the Drilling Unit upon Company’s request at the cost of the Party set forth in Attachment A2 to Exhibit A Scope of Work. Under no circumstances shall Contractor’s personnel be permitted aboard the supply vessels, without the express written consent of Contractor.
 
3.             DURATION OF THE CONTRACT; TERMINATION AND SUSPENSION PROVISIONS
 
3.1                                           Duration of the Contract. ThisContract shall remain in full force and effect from the Effective Date, through the Operating Term and completion of Demobilization unless terminated earlier by either Company or Contractor as set forth in this Section 3.
 
3.2                                           Initial OperatingTerm of the Contract; Extensions and Reductions of the Initial Operating Term of the Contract.
 
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(A)           The initial Operating Term of this Contract is 1,240 days and shall commence upon the Mobilization Completion Date. The initial Operating Term is anticipated to be as follows:
 
(1)                                 Kosmos has two hundred seventy (270) days of operations offshore Ghana; then
 
(2)                                 Noble has two hundred eighty (280) days of operations offshore Equatorial Guinea; then
 
(3)                                 Kosmos has two hundred seventy (270) days of operations offshore Ghana; then
 
(4)                                 Noble has one hundred fifty (150) days of operations offshore Equatorial Guinea; then
 
(5)                                 Kosmos has two hundred seventy (270) days of operations offshore Ghana.
 
The Parties acknowledge that Contractor or Contractor’s Affiliate has entered into a drilling contract with Noble’s Affiliate, Noble Energy Mediterranean Ltd. (“Noble Med”) to mobilize the Drilling Unit, drill and test one well (with an option to drill, but not test, a second well) in the Eastern Mediterranean with a total allocated period of 166 days (subject to Noble Med’s right to use the Drilling Unit for additional days as specified in the Rig Sharing Agreement). In any event, to the extent that the actual total number of days used by Noble Med (including mobilization and operating) is less or greater than 166 days, the days allocated to Noble under the Drilling Contract, and thus the initial Operating Term, shall be adjusted accordingly, with any increase or decrease in the number of days for Noble being applied to the drilling segment referenced in Section 3.2(A)(4).
 
The Parties hereto further acknowledge that the Mobilization under this Contract from Israel to the Mauritania Line is estimated to take 35 days and (and the cost is allocated two-thirds to Noble and one-third to Kosmos), and the Mobilization from the Mauritania Line to one mile from Kosmos’ first well in Ghana is estimated to take 20 days (and the cost is allocated one-half each to Noble and Kosmos). To the extent that the actual mobilization days are less or greater than the estimated days, the days shall be adjusted and allocated to Noble or Kosmos in the same proportion as cost has been allocated under the Drilling Contract (2/3 Noble and 1/3 Kosmos from Israel to Mauritania Line and 50/50 from the Mauritania Line to Kosmos’ first well in Ghana), and the initial Operating Term shall be adjusted accordingly.
 
Notwithstanding anything to the contrary in the Contract and consistent with KOSMOS’ plan to commence oil production in Ghana during the first half of 2010, should Kosmos and its Joint Interest Owners fail to achieve commercial oil production by September 30, 2010 and, in Contractor’s reasonable opinion, Kosmos’ financial capability is insufficient to complete its payment obligations
 
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under the Contract, Kosmos and Atwood shall meet in good faith to review relevant payment security issues to resolve the matter, including posting of a letter of credit. After such review, if Contractor, in its reasonable opinion, is not satisfied with remedies discussed, Contractor may reduce the term of the Kosmos’ segments of the Contract accordingly, not to exceed a nine (9) month reduction in term. In the event of such reduction and the option set forth in Section 3.2(C) has been exercised by Noble, Noble shall he obligated to accept the Drilling Unit on an accelerated basis immediately following the conclusion of the relevant Kosmos’ drilling program segment(s).
 
(B)             Optional extension of the initial Operating Term by Company.Either or both of Kosmos and Noble shall have the right, but not the obligation, to extend the initial Operating Term at the same rates set forth in Exhibit D Compensation as follows:
 
(1)                                 For any or all of the time necessary for Contractor to complete the Services on the last well commenced during each of the segments used by Kosmos or Noble during the initial Operating Term, such election to be made by Company within sixty (60) days of the completion of said Services or by October 01, 2010, whichever is later;
 
(2)                                 For any or all of the amount of time for which the Zero Rate has been applicable during the Contract, such election to be made by Company within sixty (60) days of the completion of said Services or by October 01, 2010, whichever is later.
 
(C)             Option to extend the Contract by Company.On or before October 01, 2010, either or both of Kosmos and Noble shall have the right to extend the Operating Term as follows at Service rates to be mutually agreed with Contractor
 
(1)                                 For a period of up to one (1) year to he shared equally by Kosmos and Noble unless otherwise mutually agreed between Kosmos and Noble.
 
(D)             Additional optional extension of the Contract by Company.Company shall have the right, but not the obligation, to extend the Contract as follows at the the Service rates in effect at the time the Services are performed:
 
(1)                                 For any or all of the total amount of time for which Contractor has been paid at the Force Majeure Rate stated in Section 8.1(F), such election to be made by Company within sixty (60) days of the completion of each such Force Majeure period or by October 01, 2010, whichever is later; or
 
(2)                                 For any or all of the period of suspension as stated in 3.9(D), such election to he made by Company within sixty (60) days of the completion
 
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of each such suspension period or by October 01, 2010, whichever is later; or
 
(3)                                 For any or all of the paid days necessary for Contractor to complete all Drilling Unit classification and regulatory inspections conducted during the duration of the Contract and as detailed in Section 6.2 (E). Such election to be made by Company within sixty (60) days of the completion of each classification and regulatory inspection period or by October 01, 2010, whichever is later.
 
(E)                                 Completion of Services on last well.In an event, the Contract shall be extended for the time necessary for Contractor to complete the Services on the last well commenced during the Operating Term.
 
3.3                                    Termination of the Contract by Company without an Opportunity to Cure Default.This Contract may be terminated by Company without penalty to Company as follows:
 
(A)            Atany time if Contractor or its creditors seek relief under any insolvency law or if Contractor should become insolvent or make an assignment for the benefit of creditors or file a voluntary petition for bankruptcy or if receivership proceedings should be instituted against Contractor and such relief action, voluntary petition or receivership proceeding is not stayed or withdrawn within ninety days;
 
(B)              Pursuant to the provisions of Sections 11 .1 and 11.2;
 
(C)              After the number of days specified in Exhibit A – Scope of Work following the occurrence and subsistence of a Force Majeure Event and subject to certain obligations specified elsewhere in the Contract;
 
(D)             If the Drilling Unit becomes an actual or constructive total loss.
 
Termination under this Section 3.3 may he made by Company upon notice to Contractor without any opportunity on the part of Contractor to correct or cure the default or situation that may give rise to termination hereunder.
 
3.4                                    Termination of theContract by Company with an Opportunity to Cure Default.
 
(A)                                  Should Contractor:
 
(i)                          Default in any way in the performance of the Services after the Effective Date of the Contract, including failing, refusing or neglecting to supply sufficient equipment to be supplied by Contractor, or tools or properly skilled personnel to complete the Services;
 
(ii)                       Carry out its obligations in a negligent or careless manner or fail to carry out the same due to its fault or negligence;
 
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(iii)                    Fail to obtain approval for, or maintain in effect, permits, certifications or clearances required to be in Contractor’s name or to be secured by Contractor from the appropriate governmental regulatory bodies of the Country or any political subdivision thereof or certification authorities which arc necessary to conduct Services in the Area of Operations;
 
(iv)                   Breach the covenants in Section 5, the applicable Exhibit B - Independent Contractor Health Environmental and Safety Guidelines, Exhibit C – Drug, Alcohol and Search Policy or any health, safety or environmental obligation imposed by federal, state, provincial or local statutes, rules or regulations;
 
(v)                      Not complete remedial work on the Drilling Unit as identified by Company as the result of an inspection undertaken pursuant to Section 5.7;
 
(vi)                   At any time breach the warranties contained in Sections 2.12 and 6.2(E);
 
(vii)                Breach the Records and Audit covenants pursuant to Section 12; or
 
(viii)             Fail to meet the requirements as defined in Attachment A2 to Exhibit A Scope of Work, or any other material obligations of Contractor under this Contract;
 
and Contractor fails to initiate reasonable corrective action to Company’s satisfaction within forty-eight hours after written notice from Company or fails to continue to correct the deficiencies as promptly as reasonably possible or fails to complete corrective action to Company’s satisfaction within thirty (30) days after such notice, Company may, at any time thereafter terminate the Contract.
 
(B)                                    Company, in the case of Work stoppage pursuant to Section 8.2, may suspend or terminate this Contract in accordance with Section 8.2.
 
3.5                                    Termination of the Contract by Company for Convenience.Company may terminate this Contract for convenience by giving Contractor thirty days prior written notice of termination.
 
3.6                                    Contractor’s Actions on Termination.Upon receipt of a notice of termination from Company, Contractor shall:
 
(A)                   Place no further orders for materials, equipment and services other than as may be necessarily required for completion of such portion of the Services that is not terminated.
 
(B)                     Promptly make every reasonable effort to either obtain termination on terms satisfactory to Company of all orders to subcontractors or assign those orders to Company.
 
(C)                     Safely, promptly and efficiently conclude the Services and provide Company information on the status of the well and other information as required even after termination.
 
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(D)                    Use commercially reasonable efforts to mitigate adverse financial exposure of the Parties.
 
(E)                      Comply with Section 17 relative to Contract Information.
 
(F)                      Remove the Drilling Unit and other Contractor equipment and materials from the Area of Operations.
 
3.7                                     Payments by Company upon Termination of the Contract.
 
(A)                   If Company terminates this Contract for any of the causes stated in Section 3.4(A) or 3.4(B), Company shall owe no further compensation after the termination date and no termination penalty shall apply.
 
(B)                     If Company terminates this Contract for convenience under Section 3.5, Company shall pay Contractor eighty-five percent (85%) of the Operating Rate in monthly installments for the remainder of the Operating Term of the Contract effective from the date of termination. In addition, Company shall pay the Demobilization Fee. If Contractor obtains follow-on work within what would have been the remainder of the Operating Term of this Contract, then Company’s obligation to pay the above termination fee will be decreased by the cumulative day rate paid to Contractor by the new operator. Contractor is responsible for informing Company about the obtainment of any follow-on contracts and day rates payable thereunder subsequent to termination under this Section 3.7(B).
 
(C)                     If after the ninety (90) day remediation period in Section 3.4(B), Company terminates the Contract due to equipment damage then:
 
(1)                                 if the damage was caused in the normal course of operations and without relation to the negligent actions of Company Group, no penalty for termination is owed; and
 
(2)                                 if the damage was caused by the negligent actions of Company Group, then a lump sum payment of US$7,500,000.00 is due from the Party acting as Company at the time of the damage.
 
(D)                    If Company terminates this Contract under Section 3.3 except Section 3.3(C), Company shall pay Contractor for that portion of the Services which Company, in its reasonable judgment, determines were satisfactorily performed prior to termination. In addition, Company shall pay Contractor an amount reasonably calculated to compensate Contractor for documented expenses it has incurred for purchases made by Contractor, at the request of Company, over and above the equipment listed in Attachment Al to Exhibit A - Scope of Work, less any amount that Contractor could have avoided or mitigated.
 
(E)                      IfCompany elects to terminate this Contract for a Force Majeure Event under Section 3.3(C) after ninety (90) days, Company shall owe no further compensation after the termination date and no termination penalty shall apply.
 
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In addition, if the Zero Rate is applicable for a Force Majeure Event, Contractor shall have the right to terminate the Contract unless Company has agreed to continue to pay the applicable Force Majeure Rate. Kosmos and Noble agree to utilize commercially reasonable efforts to move the Drilling Unit between Countries and shift the timing of their respective drilling segments as specified in Section 3.2 (A) in order to minimize the effect of a Force Majeure Event on the Parties.
 
(F)                      If the provisions of Exhibit D – Compensation require the payment of a Demobilization Fee, Company shall pay such fee to Contractor in the event of early termination of the Contract under the provisions of Sections 3.3(C) or 3.5.
 
(G)                     If Company terminates this Contract under Sections 3.3, 3.4 or 3.5, in addition to any payments owed pursuant to the provisions of Section 3.7, Company shall pay Contractor for that portion of the Services which were satisfactorily performed prior to termination. In addition, Company shall pay Contractor an amount reasonably calculated to compensate Contractor for documented expenses it has incurred for purchases made by Contractor, at the request of Company, over and above the equipment listed in Attachment Al to Exhibit A - Scope of Work, less any amount that Contractor could have avoided or mitigated.
 
3.8                                   Reinstatement after Termination for Mechanical Breakdown of Contractor’s Equipment.Company has the right to reinstate this Contract before the Drilling Unit is moved out of the Area of Operations if Contractor is able to resume Services after termination of this Contract. The effective date of this reinstatement shall be when Company’s notice to reinstate is received by Contractor, and Contractor is able to re-commence operational performance as described in Section 2.1. Company may elect to add the number of days between termination and reinstatement to the Operating Term of the Contract and notify Contractor of such election.
 
3.9                                   Suspension of the Contract for Cause.
 
(A)            Right to Suspend.Company may by notice to Contractor suspend with immediate effect the Contract,
 
(1)                                 If Company, in its sole and considered judgment, determines that in providing the Services any member of Contractor Group is failing to comply with Exhibit B - Independent Contractor Health, Environmental and Safety Guidelines, or with Exhibit C – Drug, Alcohol and Search Policy or with applicable safety laws and regulations while in the Country or any political subdivision thereof and the Area of Operations.
 
(2)                                 Under Sections 8.2(A)(2), 8.2(B)(2) and 8.2(C)(2).
 
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Suspension under this Section 3.9 continues until Company notifies Contractor that the suspension is lifted. Contractor acknowledges that Company has no obligation to lift the suspension until it is satisfied that Contractor will thereafter comply with the requirements referenced in Section 3.9(A)(1) or that the mechanical breakdown under Section 8.2 has been remedied.
 
(B)           Compensation and Expenses during Suspension.IfCompany suspends the Contract under this Section 3.9, Contractor is not entitled to Service rates compensation for the period or the suspension, but is entitled to reimbursement of any regular and daily operating expenses for Company personnel such as food and accommodation incurred during the suspension.
 
(C)           Reservation of Rights during Suspension.Suspension of the Contract under this Section 3.9 does not affect any other right of Company or Contractor under this Contract, including the right to terminate this Contract.
 
(D)          Extension of the Operating Term of the Contract.Company may elect to add any of all of the number of days between the suspension of the Contract and the lifting thereof to the Operating Term of the Contract and notify Contractor of such election in accordance with the provisions of Section 3.2(B).
 
3.10                              Rights of Company are Subject to Rig Share Agreement.
 
(A)         Whenever Kosmos or Noble, in the capacity or Company, has a right to extend the Operating Term of the Contract or to terminate the Contract, or otherwise to affect the Contract, such right shall be exercised by Kosmos or Noble only in compliance with the Rig Sharing Agreement and, in the absence of compliance with the Rig Sharing Agreement or the mutual agreement of Kosmos and Noble, neither kosmos nor Noble shall have the right to limit, modify, or terminate the use of the Drilling Unit by the other Party or the application of this Contract to such other Party.
 
4.             REPRESENTATIONS AND WARRANTIES
 
4.1                                    Initial Representations.Contractor represents and warrants to Company that as of the Effective Date:
 
(A)         Contractor is a corporation or company (as the case may be) duly organized, validly existing and in good standing under the laws or the jurisdiction of its organization.
 
(B)           Contractor has full corporate or company power and authority to enter into and perform this Contract, and has taken all actions necessary to authorize its execution and delivery of this Contract.
 
(C)           This Contract has been duly executed and delivered by its authorized officer or other representative and constitutes its legal, valid and binding obligation enforceable in accordance with its terms, and no consent or approval of any
 
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other Person is required in connection with its execution, delivery and performance of this Contract.
 
(D)          Contractor understands the nature and scope of the Services required by this Contract and is familiar with all relevant matters which may affect or govern the provision of the Services, including all of the matters listed below:
 
(1)                                 The geographic, climatic, weather, economic, security, political and cultural conditions prevailing in the Country and the Area of Operations.
 
(2)                                 The availability and quality of third-party services, labor, material, transportation, equipment and facilities in the Country and the Area of Operations.
 
(3)                                 Rules, regulations, statutory guidelines, orders, ordinances, codes, policies and laws which have legal force in the Country or any political subdivision thereof and the Area of Operations or which apply to the provision of the Services.
 
(E)            No event has occurred prior to the Effective Date which, had it occurred after the Effective Date, would constitute a violation of Section 11.1 or Section 11.2.
 
4.2                                     Continuing Representations.In addition to those warranties provided by Contractor in Section 4.1, Contractor represents and warrants to Company all of the following, as of the Effective Date and on a continuing basis during this Contract:
 
(A)         Contractor and the members of Contractor Group have the technical competence, expertise, financial capacity, management skills, resources and equipment necessary to perform their obligations under this Contract.
 
(B)           Contractor Group personnel to be used to perform the Services are competent, qualified, fit for duty and skilled for the purpose of performing. the Services as required by this Contract.
 
(C)           Contractor and the members of Contractor Group are at all relevant times in compliance with all requirements of this Contract, and have obtained all necessary licenses, permits, consents, approvals and other authorizations.
 
(D)          Without limiting any other provision in this Contract, Contractor shall comply with, and shall ensure that all members of Contractor Group comply with, all applicable permits, licenses, authorizations, concessions and clearances and all applicable laws and regulations, including those of the Country or any political subdivision thereof.  Nothing in this Contract shall require Contractor or members of Contactor Group to comply with any applicable laws and regulations if such compliance would subject either Party or their Affiliates to liabilities or penalties under United States of America law.
 
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5.            SAFETY
 
Company and Contractor shall have the following rights and obligations relative to safety:
 
5.1                                     Notification of Hazardous Conditions & Work Stoppage.
 
(A)          Notice of Hazardous Conditions. If at any time Contractor or Company determines that Services cannot be safely undertaken or Services may create a hazardous condition, that Party shall notify the other Party of such determination. As soon as reasonably possible after such determination is made, Contractor shall consult with Company prior to deciding on the subsequent course of action. At all times Contractor shall make every effort that in its opinion is required to control or overcome the cause of or minimize the adverse effect of the hazardous condition.
 
(B)            Work Stoppage. Both Company and Contractor shall have the right to stop Work by Contractor or its subcontractors or Company’s other contractors when Work conditions are deemed to be imminently hazardous to persons, property or the environment and the requisite notice is given as per Section 5.1(A).
 
(C)            Safety Issue Resolution. In case of conflict between Company and Contractor as to the determination of the course of conduct which affords the greatest safety, Contractor’s opinion shall control. Nothing in this Section 5.1 shall be construed as a waiver by Company of its rights to suspend the Contract or stop the performance of the Services under the provisions of Section 3.9(A) or Section 17 of Exhibit B - Independent Contractor Health, Environmental and Safety Guidelines.
 
5.2                                     Health, Safety and Environment Provisions; Drug, Alcohol and Search Policies. Contractor shall, at its expense, take all measures reasonably necessary or proper to provide safe working conditions, and shall comply with Company’s furnished safety requirements including those found in Exhibits B and C and with the applicable safety and environmental requirements of the Country or any political subdivision thereof and the Company if Company has local policies that apply to Contractor’s Services in the Area of Operations. Should Company have additional Health, Safety and Environment or Drug, Alcohol and Search policies that differ from those in Exhibits B and C, such shall be included in Exhibit A Scope of Work. It is understood that any work, safety and environmental guidelines established by Company are intended to supplement Contractor’s established programs and Company’s guidelines shall be considered as minimum requirements.
 
5.3                                     Contractor’s Safety Management System. Prior to acceptance of the Drilling Unit, Contractor shall submit for Company’s approval a copy of Contractor’s Safety Management System to address its safety obligations under this Contract. Such Safety Management System shall be attached to Exhibit A - Scope of Work as Attachment A9. Without limiting the generality of the foregoing, Contractor shall maintain proper barriers, guard rails and other safety devices to lessen hazards during the performance of Services under this Contract.
 
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Contractor shall not permit smoking or any open flames nor the carrying of matches or lighters except in the designated areas on the Drilling Unit. All engine exhausts shall be equipped with spark arresters to eliminate fire hazards. Any conflicts between Company’s and Contractor’s policies shall be resolved in a mutually agreed written bridging document. Contractor’s policies shall be attached to the bridging document.
 
5.4                                     Installation of Blowout Prevention Devices.As soon as Contractor considers it advisable, or earlier if requested by Company, Contractor shall install blowout prevention devices as specified in Attachment Al to Exhibit A Scope of Work, on each well. Contractor shall operate and pressure test the blowout prevention devices at intervals directed by Company, or as required by an agency of the Country or any political subdivision thereof if such intervals are shorter, by methods specified in Attachment A7 to Exhibit A — Scope of Work and to Company’s satisfaction. Results of such tests shall be recorded on the daily reports referred to in Section 2.15. At a minimum well control drills shall be conducted weekly or more frequently if required by Company for each drilling crew and results of these drills shall also be recorded on such daily reports.
 
5.5                                     Notification of Safety Requirements to Personnel on the Drilling & Safety Training.
 
(A)          Contractor shall give notice to all persons at the well location of all safety requirements which apply to any person at the well location. Additionally, Contractor shall ensure that such persons are fully informed of, receive training in (at Contractor’s cost for Contractor Group’s personnel only) and comply with such requirements. The Contractor shall set up and conduct weekly safety drills.
 
(B)            Additionally, Contractor shall take appropriate action requiring such persons to cease activities whenever Contractor is aware that persons are not complying with such safety requirements. The Contractor shall set up and conduct weekly safety drills.
 
(C)            Company and Contractor will consult and cooperate to get the appropriate notices and information to other contractors of Company and to implement this Section 5.5 with other contractors and their personnel.
 
5.6                                     FirePrevention Actions.Contractor shall, within the capabilities of the equipment and personnel required to be furnished by Contractor, adopt such precautions as are within generally accepted drilling industry standards to prevent the well catching fire or to bring the well under control or to put out the fire, including all precautions required and instructions given by Company. At such time as Contractor’s Drilling Unit is engaged in Services, Contractor shall provide vapor-proofed wiring and lighting and exhaust spark arresters to enable the Drilling Unit safely to work-over, complete/perforate and perform testing Services, pull wet strings and pull testing tools at any time.
 
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5.7                                     HSE Systems Audit and Inspection.
 
(A)          Company may, at its option, require a Health, Safety and Environmental (“HSE”) systems audit and inspection prior to the Commencement Date of the Contract. The HSE audit and inspection will be performed by Company’s HSE department and, for non-U.S. operations, Company’s Medical departments or third party selected by and at the expense of Company.
 
(B)            The audit will be a comprehensive survey, including record checks, employee interviews and random physical condition checks to confirm equipment, programs, procedures and administrative controls are in place to protect the health and safety of rig personnel and the environment.
 
(C)            The HSE systems audit and inspection will document identified deficiencies to ensure the Drilling Unit is in compliance with equipment and programs specified in the Contract. A copy of the written audit and inspection report will be given to Contractor following the inspection. All deficiencies identified in the audit or inspection shall be repaired or corrected at Contractor’s cost, and all programs or procedures in place, prior to the Commencement Date of the Contract, unless otherwise mutually agreed by the Parties in writing.
 
(D)           Company reserves the right to periodically re-inspect any of the above during the Contract.
 
(E)             Contractor shall provide reasonable access to the Drilling Unit, including, if appropriate and practicable, using its best efforts to obtain permission from the prior operator who has the Drilling Unit under contract to allow Company’s representatives and inspectors on the Drilling Unit while operating for that other operator.
 
5.8                                     MaterialSafety Data Sheets. Contractor shall review material safety data sheets (MSDS) pertaining to known toxic and hazardous substances or chemical hazards to which Contractor’s employees or subcontractors are likely to be exposed while performing any particular or individual work task on behalf of Company. To this end, Company shall provide to Contractor or cause its other contractors to provide MSDSs for chemicals which Company or its other contractors bring on board the Drilling Unit. Such MSDSs shall be provided in a timely manner to allow Contractor to comply with the requirements of this Section 5.8. Contractor will and shall be solely responsible for notifying its personnel working at the well location of all health and safety hazards to which they will be exposed.
 
5.9                                     Emergency Evacuation Plan. Contractor agrees to provide Company with information necessary for Company to submit an Emergency Evacuation Plan consistent with the requirements of all applicable regulations issued by the applicable regulatory body.
 
5.10                               WasteDisposal. Contractor agrees that it will use the prudent, accepted and approved standards of care and diligence in use by international drilling contractors to prevent, to take care of, and to prepare for shipment all its waste oil, waste water, and other waste material, including but not limited to waste
 
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paint cans, waste drilling pipe dope, etc., that may accumulate from Contractor’s Operations. Contractor will use prudent, accepted, and approved standards of care in use by drilling contractors to prevent pollution of all nature or kind resulting from the Services performed under this Contract. Company shall be responsible for all cost and the hauling to shore and disposal of all wastes from the Drilling Unit.
 
5.11                               Contractor’s Subcontractor’s. The requirements of this Section 5 of this Contract arc applicable to all subcontractors hired by Contractor and Contractor shall require its subcontractors’ compliance thereto.
 
6.             CONTRACTOR’S PERSONNEL AND EQUIPMENT; IMPORT AND EXPORT OBLIGATIONS
 
6.1                                     Contractor’s Personnel. Contractor shall provide the personnel identified in Attachment A3 to Exhibit A - Scope of Work and comply with all of the following:
 
(A)          Qualifications and Number of Personnel.
 
(1)                       The personnel assigned by or on behalf of Contractor Group must be qualified, competent, sufficiently experienced and in a sufficient number to perform the Services. All such personnel must have the qualifications, classifications, experience, and training required under all applicable health, environmental and safety practices, procedures, regulations, certifications and any other requirements of applicable law and this Contract.
 
(2)                       Inaddition to the rights and remedies provided elsewhere in this Contract, Contractor shall promptly replace any member of the Contractor Group who fails to meet these qualifications and Contractor shall furnish any personnel necessary to fulfill the requirements of this Contract. During the time any positions arc unfilled, Contractor shall credit Company an amount equal to the Personnel rates shown in Attachment A3 of Exhibit A - Scope of Work for the unfilled positions. Should rates for Contractor personnel not be listed, then the rates shall be calculated as actual costs for salary (plus Payroll Burden) for those unfilled Contractor personnel positions.
 
(3)                       If the Parties agree to reduce the number and/or qualifications of personnel specified in this Contract, any resulting savings from this reduction must be credited to Company.
 
(4)                       If Company requests additional personnel, Contractor shall furnish the requested additional personnel (in addition to those required in Attachment A3 to Exhibit A - Scope of Work) and Company shall reimburse Contractor for this added cost as set out in Section 9.3.
 
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(5)                       Contractor shall handle all industrial relations matters involving members of the Contractor Group in accordance with applicable law, labor contracts, customs, rules and regulations. The settlement of any labor disturbance affecting Contractor’s personnel shall be wholly within the discretion of Contractor and at Contractor’s sole expense, without prejudice to Section 8.3.3.
 
(6)                       Each of Contractor’s personnel in the following classifications shall be fluent in English; Contractor Representative, drilling superintendent/rig supervisor, senior toolpusher, assistant toolpusher, drillers and assistant drillers, Offshore Installation Manager (OIM), Crane Operators, medic, safety captain/HES specialist, or their equivalent job classifications. Contractor must have at least one person who can both speak and write English on site at all times who is capable of communicating both orally and in writing with other personnel at the well location who do not understand oral or written English. On Attachment A3 to Exhibit A - Scope of Work additional Contractor Drilling Unit crew positions may be identified which must be filled with individuals who must be fluent in English.
 
(7)                       If Contractor fails to furnish the numbers and/or classifications of the personnel specified in Attachment A3 to Exhibit A - Scope of Work, Contractor shall at its own cost promptly replace such missing personnel. Contractor shall credit Company an amount equal to Contractor’s Personnel Rate for each person during the time the position is unfilled and keep Records of the presence and absence of all personnel.
 
(B)            Training, Supervision, Well Pressure Control Certification and Fire Fighting Survival Certification. Contractor shall provide or cause to be provided all necessary training, education, instruction and supervision of Contractor Group personnel that is necessary to carry out the duties required in this Contract.
 
(l)                          Contractor warrants that all drill crew personnel specified in Attachment A3 to Exhibit A - Scope of Work who arc required to hold well control certificates by either industry, government or Contractor standards are properly certified in well control operations to the appropriate industry and government standards and have valid well control certificates from the certification authority recognized by Company, and can understand and properly perform their duties. National crew members shall receive well control training at Contractor’s cost commensurate with the position they hold. The costs associated with obtaining and maintaining the required well control certificates shall be for Contractor’s account.
 
(2)                       Contractor shall ensure that Contractor’s personnel comply with all applicable statutory regulations and requirements regarding the attendance at and satisfactory completion of fire fighting and survival courses.
 
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(C)            Disciplineand Replacement of Personnel.Contractor shall maintain discipline and lawful and orderly behavior among Contractor Group personnel during the performance of the Services. If instructed by Company in writing, Contractor shall replace or remove Contractor Group personnel as follows:
 
(1)                       Contractor shall remove and replace, at Contractor’s sole expense, any personnel who Company determines in its sole and considered judgment, is or are unsatisfactory because of non-compliance with the requirements of this Contract or because of being likely to jeopardize the relationship between Company and host, state or local governments or others in the Country or any political subdivision thereof.
 
(2)                       Contractor shall remove and replace any of its personnel, if requested by Company without specifying any reason and in this event, Company’s obligations for payment to Contractor shall be limited to travel costs incurred by such removal and replacement.
 
(3)                       Contractor shall handle all industrial relations matters involving Contractor’s personnel subject to applicable law, labor contracts, customs, rules and regulations. The settlement of any labor disturbance affecting Contractor’s personnel will be wholly within the discretion of Contractor.
 
(D)           Key Personnel.Key Personnel identified in Attachment A3 to Exhibit A - Scope of Work must not be removed or replaced by Contractor or its Subcontractors without Company’s prior written consent.
 
(E)             Requirements of Personnel. Contractor isresponsible, at its own expense, for providing all of the requirements of Contractor Group personnel, including all of the following:
 
(1)                       Benefits, including salaries, wages, bonus payments, sick pay, insurance (including Workers’ Compensation Insurance or similar insurance), termination payments, local income taxes, rest leave, overtime, allowances, social benefits, medical benefits, relocation expenses, indemnities, compensations and fringe benefits of whatever nature, and any benefits payable under applicable law or collective labor contracts;
 
(2)                       All hours worked, including any overtime or other premiums for hours worked;
 
(3)                       Any offshore safety training/medical; certification cost, including costs related to permit to work and induction courses;
 
(4)                       Personnel mobilization and demobilization costs to Point of Origin;
 
(5)                       Overheads and profits;
 
(6)                       Medical attention, except as provided in Section 7.2;
 
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(7)                       Immigration requirements, including passports, visas, work permits, exit and re-entry permits, medical examinations, personal customs duties and all other applicable governmental authorizations or documentation required in connection with the employment of or the entry into, presence in or exit of Contractor Group personnel from the Area of Operations or the Country or any political subdivision thereof;.
 
(8)                       Training, Food, lodging and transportation, except as otherwise provided in Exhibit D - Compensation;
 
(9)                       Life saving and personal protective equipment, and
 
(10)                 All other costs of Whatsoever nature incurred by Contractor in the administration of this Contract.
 
(F)             Personnel Work Schedule.Contractor’s personnel shall work according to the schedule as set forth in Exhibit A — Scope of Work.
 
(G)            Local Content & Workforce Nationalization. ForWork outside the U.S. and Canada, Company may require Contractor to commit to targets or specific requirements relative to local content and workforce nationalization. Any such targets or requirements shall be set forth in Attachment A2 to Exhibit A — Scope of Work for materials and supplies and Attachment A3 to Exhibit A — Scope of Work for personnel. As to Ghana, any such targets or requirements shall be identified to Contractor as part of the process to obtain a Permit To Operate As Petroleum Service Company In Ghana set forth in Attachment A10 to Exhibit A — Scope of Work
 
6.2                                     Contractor’s Drilling Unit, Services and Supplies.
 
(A)          General Provision.Except for  those items specifically provided in Section 7.1 to be furnished by Company, Contractor shall provide at its sole cost and expense the Drilling Unit and all Services, equipment, machinery, Drill Strings, tools, spare parts, consumables, maintenance, all onshore support costs, materials, supplies, insurance, overhead and profit, and all other reasonable costs incurred by Contractor in the administration of this Contract, including the items listed as Contractor’s responsibility on Exhibit A - Scope of Work and its Attachments. Replenishment of items furnished by Contractor shall be arranged by Contractor at its expense, and Contractor shall also be responsible for maintaining adequate stock levels to ensure prompt and efficient performance of Services.
 
(B)            NotUsed.
 
(C)            Company’s Rights of Inspection and Rejection of the Drilling Unit and the Services.
 
(1)                       Right of Inspection and Rejection. Company shall at its expense, before the Commencement Date of the Contract or anytime during the
 
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Contract, have the right but not the obligation to inspect any equipment, machinery, drill strings, spare parts, tools, materials and supplies furnished by Contractor as well as check all records, measurements and tests prior to the Commencement Date and at any time thereafter. Company or its authorized representative(s) may inspect the Drilling Unit at sites owned or controlled by members of Contractor Group, their contractors or other operators upon reasonable notice during normal business hours (subject to the prior operator’s consent and schedule). Any equipment or other items that do not conform to the specifications of this Contract may be rejected by Company and must be repaired or replaced by Contractor, at its own expense, with equipment or items that are acceptable to Company.
 
(2)                       No Waiver of Company’s Rights. Company’s inspection of the Drilling Unit and/or Contractor’s performance of the Services does not excuse Contractor from any obligations under this Contract. Company’s failure to inspect, witness, test, discover defects, raise issues concerning or reject Services performed by Contractor that are not in accordance with this Contract does not relieve Contractor from the liabilities and obligations set out in this Contract or raise any defense to the insufficiency of Contractor’s performance.
 
(D)           Maintenance of the Drilling Unit and Ancillary Equipment.
 
(1)                       Contractor shall ensure that the Drilling Unit and all other items of Contractor’s equipment are properly maintained in good working order and repair throughout the Contract. Qualified service technicians shall be retained as necessary at Contractor’s sole cost to perform any maintenance, repair, or replacement required for the Drilling Unit. Unless as otherwise agreed by the Parties in writing, all costs related to any repairs or replacements of the Drilling Unit shall be effected by Contractor at its sole cost and expense as speedily as reasonably practical.
 
(2)                       Contractor must have a demonstrable Preventative Maintenance System (PMS). The repair and maintenance of all equipment located on the Drilling Unit including all Contractor equipment, and Company equipment subject to Contractor’s available personnel and capability shall be covered in the said PMS. Accordingly Contractor will develop and implement a Preventative Maintenance Procedure for all equipment and shall inform Company of the Preventative. Maintenance Schedule. Contractor must provide Company with a minimum of seventy-two hours notice for any proposed shutdown of equipment which will directly impact on the Operations. Company shall have the right to postpone any such planned shutdown of key equipment for a period of up to seventy-two hours. Thereafter Contractor will then have the right to shutdown the key equipment involved in order to carry out the required maintenance thereon.
 
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(3)                       Contractor will be allowed a maximum of twenty-four (24) hours per calendar month for repair and maintenance of surface (surface equipment having the meaning provided in Section 8.2) and thirty-six (36) hours per calendar month for Subsea Equipment (Subsea Equipment having the meaning provided in Section 8.2) for which payment will be made at the Operating Rate stated in Exhibit D - Compensation. Thereafter the Zero Rate shall he applicable. This allotment of time allowed for repair and maintenance of drilling items shall not be cumulative from month to month and may not be carried forward, rolled-over or banked to any future month.
 
Provided such maintenance operations do not impede the progress of normal operations, the time spent in changing mud pump fluid end components, replacement of swivel packing, slipping and cutting of drill line and other similar routine inspections and maintenance operations shall not be counted against the time period in the maintenance and repairs provisions of this Section 6.2(D)(3), Exhibit A, or elsewhere in this Contract.
 
(4)                       Contractor shall provide, store and maintain at all times a reasonable stock of spare parts and operating supplies sufficient to ensure the continuous and efficient operation of the Drilling Unit. If Operations are interrupted due to the non-availability of spare parts or operating supplies provided by Contractor, the applicable rate shall be the Zero Rate and Contractor shall be responsible for any additional logistical or other costs to deliver such spare parts or operational supplies to the Company’s designated shore base, until the Operations return to the status prior to such interruption.
 
(5)                       Contractor shall be responsible for arranging delivery of all spare parts and operating supplies necessary to replenish stocks from the Point of Origin to Company’s shorebase by the most expeditious means and all costs and expenses relating to the importation and/or exportation and the transportation thereof, including but without limitation all customs duties, clearing and brokerage charges, value added tax and other taxes and charges, shall be borne or handled by Contractor (in accordance with Section 6.3), who shall also wherever practicable supervise all activities of the packing company and its forwarding agent in order to expedite delivery and ensure proper documentation as required by applicable laws and regulations or the requirements of applicable government and certification authorities.
 
(E)             Certification of the Drilling Unit.
 
(1)                       With respect to suitability of use thereof for offshore Operations, the Drilling Unit shall be classed and certified by Lloyds, the American Bureau of Shipping, or Det Norske Veritas “DNV”. Contractor shall keep the Drilling Unit properly classed and certified throughout the Contract, a copy of the latest class survey, along with an estimated
 
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drydock schedule for the Drilling Unit, shall be provided to Company prior to the Commencement Date of the Contract.
 
(2)                       Contractor shall be permitted three and one-half (3.5) calendar days per contract year (i.e. 365 days from the Commencement Date) to conduct classification and other regulatory inspections to the Drilling Unit for which payment will be made at the Standby with Crews Rate stated in Exhibit D — Compensation. This allotment of time allowed for the Drilling Unit classification and other regulatory inspection shall be cumulative from Contract year to Contract year, and may be carried forward, rolled-over, and banked to any future year as specified immediately hereinbelow:
 
(a)          The timing for the conduct of the Drilling Unit classification and regulatory inspection shall be determined in consultation with Company. Once such an inspection has been conducted during this Contract, any excess of days accrued beyond the time required to complete the subject inspection shall be carried forward. If the time required to conduct the inspection exceeds the number of inspection days accrued, all such additional time utilized by Contractor shall be at Zero Rate. Following the completion of the Drilling Unit inspection, the Parties shall again start to accrue inspection days hereunder. In the event that the Operating Term has expired or this Contract has otherwise been terminated, Contractor may invoice Company for the pro-rata share of the inspection time accrued hereunder.
 
(3)                       Contractor shall carry out as required by the appropriate authorizing authorities, at Contractor’s sole expense, a structural inspection of the Drilling Unit by qualified surveyors.             Contractor will report the inspection results to Company prior to commencing or recommencing drilling Operations.
 
(4)                       The estimated schedule for the inspections to he carried out in Section 6.2 shall be as specified in Exhibit A – Scope of Work and shall be updated periodically throughout the Contract.
 
(5)                       Contractor warrants that the Drilling Unit is physically capable of drilling, completing, working over, and abandoning wells for oil and/or gas to the drilling depth(s) specified in Attachment Al to Exhibit A - Scope of Work.
 
(6)                       Contractor further warrants that, to the extent required under the law of the Country or any political subdivision thereof, the Drilling Unit either is certified under the laws of the Country or any political subdivision thereof for the conduct of drilling Services or will be so certified before the Commencement Date of the Contract. Contractor shall maintain such certification at its sole expense. If this warranty is breached with respect to any location within the Area of Operations, Company may
 
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terminate the Contract in accordance with the provisions of Section 3.4(A) and Contractor will be entitled only to compensation at the applicable rate set forth in Exhibit D - Compensation for all Services satisfactorily completed prior to such termination.
 
(F)             Contractor’s Drill String Components.Contractor shall initially supply a new or used string of internally coated drill pipe, HWDP, drill collars and subs (“Drill String”) and handling equipment in accordance with the requirements of Attachment A1 to Exhibit A – Scope of Work. In either case, a complete inspection in accordance with Attachment A5 to Exhibit A - Scope of Work shall be performed by a competent and reliable service company at Contractor’s sole expense prior to the Commencement Date of the Contract. Inspection results shall be made available to Company before the Commencement Date. Once the Drilling Unit has been fully accepted, then Contractor shall cause the Drill String to be inspected in accordance with the following:
 
(1)                       Contractor shall cause the Drill String components to be fully re-inspected at Contractor’s sole expense after the string has been in use for the time periods specified in Attachment A5 of Exhibit A - Scope of Work. The Drill String may be inspected at any other time at Company’s request and expense. Company, at its cost, may engage an independent inspector to observe inspections undertaken by Contractor.
 
(2)                       Any Drill String Components discarded as a result of inspections or re-inspection pursuant to this Section 6.2(F) shall be promptly replaced by Contractor at Contractor’s sole cost and expense (subject to any contrary provisions in the Contract) by an equal amount of new or used (or a combination of both) Drill String Component which meets the technical requirements set forth in Attachment A5 to Exhibit A – Scope of Work.
 
(3)                       Any drill pipe, drill collars, pup joints or subs furnished by Contractor which do not pass an inspection pursuant to this Section 6.2(F) shall be promptly replaced by like drill pipe, drill collars, pup joints or subs that meet Company’s requirements set forth in Table 1 of Attachment A5 to Exhibit A – Scope of Work or shall be re-cut to meet specifications set forth Attachment A5 to Exhibit A – Scope of Work. Such remedial work or replacement under this Section shall be for Contractor’s account, subject to any contrary provisions in the Contract. Cost of the replacement items shall be in accordance with Attachment 2 to Exhibit A – Scope of Work.
 
The cost obligation of the Contractor in Sections 6.2(F)(1) through (3) above are based on the use of the Category inspection standard in Attachment A5 to Exhibit A — Scope of Work. If the Company requires the use of Category 5 inspection standard then the Contractor remains obligated for the costs associated to Category 4 inspection standards; however the Company will pay the incremental difference between a Category 4 and Category 5 inspection including the cost of the rejected Drill String Components passing a Category 4 inspection but failing a Category 5 inspection.
 
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(G)            Hoisting Equipment.Once the Drilling Unit has been fully accepted in accordance with Attachment A4 then Contractor shall cause the hoisting equipment to be inspected in accordance with the following:
 
(1)                        Contractor shall provide and maintain all hoisting equipment in accordance with industry standards and as provided in this Section 6.2(G) and the specifications set forth in Attachment A6 to Exhibit A — Scope of Work.
 
(2)                        This hoisting equipment must meet or exceed the requirements set out in regulations promulgated by the American Petroleum Institute (“API”) and referred to as Specifications 8A and 8B and that all derricks meet the requirements of API Specification 4E and API Standard 4A. As stated in API Specification 8A: “Modifications, including welding, can be detrimental and substantially reduce the rating of the equipment and shall not be done without the approval of the manufacturer.”
 
(3)                        Elevators shall have no repairs or modifications of any kind, including, welding, heat treatment or changes in dimensions. Replacement parts, such as new springs or pins, must be certified by an API-approved company for load capacity and model numbers to the standards set by the manufacturer.
 
(4)                        Contractor shall provide written documentation of inspections for wear and defects, including dates, types of inspection, extent and results for all hoisting equipment other than elevators or derricks. Further, Contractor shall provide to Company written documentation for all repairs and modifications, including all welding and heat treatments. This documentation must also include written approval for these repairs and modifications as required by API Specification 8A.
 
(H)           Contractor’s Marine Riser, BOP and Well Control Systems.
 
(1)                        Upon Company’s request, Contractor must provide Company a copy of Contractor’s marine riser inspection program for Company review. During the Contract, Contractor shall at its own expense re-inspect the riser as provided in Contractor’s marine riser inspection program.
 
(2)                        Contractor shall provide all BOP and Subsea control systems as per Attachment Al to Exhibit A — Scope of Work and maintain the equipment in accordance with industry standards and as provided in this Section 6.2(H) and the specifications set forth in Attachment A6 to Exhibit A — Scope of Work. Contractor shall provide written documentation of inspections for wear and defects, including dates, types of inspection, extent and results for all BOP and Subsea control systems. Further, Contractor shall provide to Company written documentation for all repairs and modifications to the equipment and systems.
 
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(I)                     Additional Materials.   At Company’s written request, Contractor shall provide such additional materials not listed on Exhibit A – Scope of Work or which are not an integral part of the Drilling Unit. Company shall reimburse Contractor for such materials in accordance with the provisions of Section 9.1.
 
6.3                                          Import/Export Obligations.
 
(A)               Definitions Relating to Import/Export Obligations.
 
(1)                                 “Import/Export Charges” means properly and lawfully payable customs or import or export duties or taxes, and all other proper and lawful charges related to port or customs clearances or charged on the import or export of goods including pilotage, agent fees, brokerage fees, handling charges and port dues, which are charged in relation to Import/Export Items under any of the following circumstances:
 
(a)                                 Upon export of the Import/Export Items from the country of origin.
 
(b)                                Upon import of the Import/Export Items into the Country or the Area of Operations.
 
(c)                                 If the Import/Export Items are subsequently exported, upon export of the Import/Export Items from the Country or the Area of’ Operations and upon import of the Import/Export Items into the destination country.
 
(2)                                 “Import/Export Exemptions” means exemptions from or reductions of Import/Export Charges obtained by Company or available to Contractor or Subcontractors.
 
(3)                                   “Import/Export Items” means Property (including intellectual property) that is imported into the Country or the Area of Operations (whether permanently or temporarily) in order for Contractor to perform the Services.
 
(B)                 Imports.Contractor is responsible for exporting all Import/Export Items from their country of origin (including deemed exports of software, technology or other intellectual property) and importing all Import/Export Items into the Country and the Area of Operations, and for obtaining all necessary permits, licenses, authorizations and clearances for the export and import of Import/Export Items. All other charges related to routine port clearances such as pilotage, agent fees, handling charges and port dues shall be for Contractor’s account.
 
(C)                 Import/Export Exemptions.Contractor shall take all actions necessary to ensure that all possible Import/Export Exemptions are obtained, and that all requirements for Import/Export Exemptions are complied with. Contractor shall not take any action that is prejudicial to obtaining any available Import/Export Exemption.
 
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(D)                Payment of Import/Export Charges.     Contractor shall pay all Import/Export Charges, subject to reimbursement under Section 6.3(E), if applicable.
 
(E)                  Reimbursement.If an Import/Export Exemption is not available through no fault of Contractor, then Company shall reimburse Contractor for the actual documented cost of any Import/Export Charges that are paid by Contractor to a duly authorized representative of the government having jurisdiction, provided that Company has approved these costs in writing in advance and Contractor has complied with Sections 6.3(B) and 6.3(C). Contractor’s payment of Import/Export Charges shall be substantiated with each invoice.
 
(F)                  Exports after Completion of the Services.   Contractor is responsible for obtaining all necessary permits, licenses, authorizations and clearances for the export from the Country or the Area of Operations, and the import into the destination country, of any Import/Export Items which are exported from the Country or the Area of Operations. If an Import/Export Exemption includes an obligation to export an Import/Export Item from the Country or the Area of Operations, Contractor shall do so when the Import/Export Item is no longer needed for the Services. If export of Import/Export Items at the conclusion of the Services will result in a credit or lessening of Import/Export Charges reimbursable by Company under Section 6.3(E), Contractor shall do one of the following:
 
(1)                        Elect to export those Import/Export Items which are not permanently installed or consumed as part of the Services, in which case:
 
(a)              If the Import/Export Charge has been reimbursed by Company, Contractor shall pay the credit to Company or pay Company an amount equal to the credit immediately following receipt.
 
(b)             If the Import/Export Charge has not been reimbursed by Company, Contractor has no entitlement to reimbursement for it under Section 6.3(E), and no obligation to pay the credit, or an amount equal to the credit, to Company.
 
(2)                        Elect not toexport those Import/Export Items which could have been exported, in which case:
 
(a)              If the Import/Export Charge has been reimbursed by Company, Contractor shall pay Company an amount equal to the credit which could have been obtained immediately following the election not to export.
 
(b)             If the Import/Export Charge has not been reimbursed by Company, Contractor has no entitlement to reimbursement for it under Section 6.3(E), and no obligation to pay Company an amount equal to the credit that could have been obtained.
 
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7.                                     ITEMS TO BE FURNISHED BY COMPANY
 
7.1                                          Company Items.
 
(A)               Company shall furnish, maintain and replace as necessary, at its expense, the equipment, machinery, tools, supplies, materials, items and services specified in Attachment A2 to Exhibit A – Scope of Work (“Company Items”).
 
(B)                 The Representatives of Company and Contractor shall jointly take an inventory of all Company Items prior to the Commencement Date, after completion or termination of each well, at completion of the Services (or, if this Contract is terminated earlier, the date of termination), during the transfer of the Drilling Unit between Kosmos and Noble during the five (5) drilling program segments outlined in Section 3.2 or any option period of the Contract, and at any other time as requested by either Party.
 
(C)                 Upon receipt of any Company Item, Contractor shall verify receipt and visually inspect same with reasonable diligence expected of an international drilling contractor and shall immediately advise Company of any shortages and defects observed within forty-eight hours of receipt. If Contractor fails to so advise Company of any shortages and defects observed, it shall be presumed that such items were received by Contractor and were in a good state of repair and operating condition, defects not apparent by visual inspection excepted.
 
(D)                Contractor shall properly store, protect and account for Company Items and must maintain records for identification and customs requirements.
 
(E)                  Contractor shall operate all Company Items in conformity with all applicable laws, certifications, licenses, and manufacturer’s requirements.
 
(F)                  Contractor, at its expense, shall provide the routine maintenance required to keep Company Items in good and safe operating condition, that is, such maintenance as Contractor can reasonably provide using Contractor’s personnel and equipment. If such items require repair work beyond the scope of Contractor’s routine maintenance or require replacement, such repair and replacement shall be for Company’s account, subject to prior mutual agreement as to cost. Contractor shall use its best efforts consistent with generally accepted industry standards to make such repairs or replacement and Company shall reimburse Contractor in the manner provided in Section 9.1. If such repairs or replacement are required due to damage or loss arising out of the failure of Contractor to follow generally accepted industry standards with regards to maintenance, then Contractor’s liability for such shall be governed by Section 14.3.
 
(G)                 Company may, on giving reasonable notice and subject to Contractor’s acceptance, instruct Contractor to furnish any of the items listed in Attachment A2 to Exhibit A — Scope of Work which Company is required to furnish and such items shall at all times be considered Company equipment, items and personnel (if applicable) unless otherwise mutually agreed in writing. If items are so furnished, Company shall reimburse Contractor pursuant to Section 9.1.
 
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(H)                All Company Items which are not consumed during the performance of Services must be returned to Company in substantially the same condition that existed at the time such Company Items were furnished to Contractor fair wear and tear accepted. The time to return Company Items is at the termination of this Contract or at any other time requested by Company.
 
(I)                     Company is not entitled to any compensation from Contractor for normal wear and tear of Company Items or for the consumption of any Company Items used by Contractor during the performance of Services. Any damage or deterioration to the Company Items beyond normal wear and tear and caused by Contractor’s negligence must be compensated by Contractor by paying Company either the actual cost to repair or diminution in value, as prescribed by Company. Alternatively, if directed by Company, Contractor may deduct this amount from its final invoice.
 
(J)                    Within thirty (30) days after completion of the Services or, if this Contract is terminated earlier, the effective date of such termination, Contractor shall furnish to Company a fully detailed, complete reconciliation of all Company Items. This reconciliation must include the inventory referred to in Section 7.1(B) and other information required by either the Company Representative or Contractor Representative. The original reconciliation must be signed, dated, and submitted to Company.
 
7.2                                          Emergency Medical Treatment and Emergency Medical Evacuation.Subject to Section 14.7, Company shall make available to Contractor and its subcontractors emergency medical treatment at Company’s medical facilities in or near the Area of Operations and emergency medical evacuation services. Company shall invoice Contractor for such services, provided however, that transportation between the Drilling Unit and Company shore base shall be for Company’s account.
 
8.                                                         COMPENSATION
 
8.1                                          Service Rates.Contractor shall be compensated by Company for performing the Services and meeting all of its obligations under the Contract and the Company shall reimburse the Contractor in accordance with the rates set forth in Exhibit D — Compensation in accordance with the provisions of Sections 8.1(A) through 8.1(H) as full compensation for Services rendered and the Drilling Unit, equipment, personnel, materials, machinery, Drill Strings, tools, spare parts and supplies furnished by Contractor in conformance with this Contract. Daily rates shall be prorated on the basis of a twenty-four hour calendar day to the nearest one-half hour. As provided in Section 6.2(A) any costs to operate in the Country that are normally or legally borne by the Contractor are included in the Service rates indicated below and as specified in Exhibit D — Compensation. No other payments shall be due by Company to Contractor other than those specifically provided for in this Contract.
 
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(A)               Mobilization Fee(the “Mobilization Fee”). Contractor’s Mobilization Fee for the Drilling Unit and crew and for performing all Services, including all Services necessary to otherwise prepare for commencement of actual drilling Operations at the first well location shall be as specified in Exhibit D  — Compensation if one is agreed to be paid. Mobilization shall commence from the mobilization origin point identified in Exhibit A — Scope of Work and shall be completed when the Drilling Unit arrives at the mobilization delivery point identified in Exhibit A — Scope of Work with all anchors tensioned at operational draft and all required equipment on board in full readiness to commence operations when so instructed by Company and Company has issued Acceptance of the Drilling Unit as per Attachment A4 to Exhibit A — Scope of Work. It is noted that the costs of providing the following items are specifically excluded from the Mobilization Fee: towing/transport vessels, anchor handling vessels, safety standby vessel, fuel for all vessels and the Drilling Unit, and rig positioning services which shall be provided by Company. Mobilization Fee shall be invoiced within thirty days after the Commencement Date.
 
(B)                 Operating Rate(the “Operating Rate”). Subject to being superseded by any other Service rate or fee provided for in this Section 8.1, Company shall pay Contractor the Operating Rate specified in Exhibit D —  Compensation per twenty-four hour (subject to pro-ration) day beginning on the Commencement Date and continuing throughout the Contract, including, but not limited to, drilling, suspending or abandoning, sidetracking (which for sake of clarity includes the drilling of multilateral wells), Subsea completions, workovers, or testing, deepening, reaming, coring, drill stem testing, picking up drill pipe, tripping, circulating and conditioning mud, running and cementing casing, waiting for cement, logging, performing routine maintenance, waiting fbr orders (except as provided in Section 8.1(E)), nippling up, running tubing, testing, completing and re-completing the well and swabbing and slipping and cutting the drilling line, except during periods of time when Zero Rate or any other Service rate is applicable as set forth in Exhibit D — Compensation. The Operating Rates specified in Exhibit D are based on the withholding tax rate in Ghana being 5% and the withholding tax rate in Equiatorial Guinea being 6.25%. Zero or other withholding tax rates (as applicable) will apply during mobilization periods.
 
(C)                 Moving Rate(the “Moving Rate”). The Moving Rate shall be in effect during the time when the Drilling Unit is being moved between two Company well locations commencing when the last anchor has been bolstered and the Drilling Unit is underway to the next well location and shall continue to be paid while the Drilling Unit is in transit. The Moving Rate shall cease to be paid when the Drilling Unit has arrived at the next well location, the Drilling Unit is positioned over the next well location and the Drilling Unit is anchored and its anchoring systems are pre-tensioned and all required Contractor equipment, third party equipment and Company equipment is on hand and in full readiness to commence Operations when so instructed by Company. Company shall pay Contractor the Moving Rate specified in Exhibit D — Compensation per twenty- four hour day (subject to pro-ration) if one is agreed to be paid in Exhibit D - Compensation.
 
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(D) Standby with Crews Rate(the “Standby with Crews Rate”). The Standby with Crews Rate shall be in effect at any time after the Commencement Date when the Drilling Unit is on location fully manned and operational and otherwise held in full readiness to proceed with Operations, but is unable to undertake Operations because of the following:
 
(1)          Shutdown for local holidays occurs or, at Company’s request, the drilling Services are shut down.
 
(2)          Contractor’s expatriate crews are not released.
 
(3)          Waiting on instructions from Company or delivery of equipment, materials or supplies to be furnished by the Company, failure or loss of or damage to Company’s Equipment (provided that during such waiting periods Contractor’s Drill String is not in use).
 
(4)          During classification and other regulatory inspections to the Drilling Unit as indicated in Section 6.2(E)(2).
 
For Sections 8.1(D)(1), (2) and (3), the first twenty-four consecutive hours of Standby with Crews Rate, the Operating Rate as specified in Section 8.1(B) shall apply. After the first twenty-four hours of Standby with Crews Rate, Company shall pay Contractor the Standby with Crews Rate specified in Exhibit D — Compensation per twenty-four hour day (subject to pro-ration) until: (a) Services arc recommenced, (b) such rate is superseded by the Extended Standby Rate as provided below or another rate (c)   the Contract terminates or expires, whichever is earlier.
 
For Section 8.1(D)(4), when the Drilling Unit is undergoing classification and regulatory inspections, the Standby with Crews Rate shall apply at all times.
 
(E)  Extended Standby Rate(the “Extended Standby Rate”).
 
(1)          The Extended Standby Rate means the time when Company requires Contractor to hold the Drilling Unit available to Company for a more extended period of time than contemplated during Standby with Crews Rate in accordance with Section 8.1(D) and Company directs Contractor to reduce its crew.
 
(2)          An Extended Standby Rate period may not commence until after ten days of Standby with Crews Rate has passed. Company shall give Contractor notice of commencement of any Extended Standby Rate period.
 
(3)          During Extended Standby Rate periods, Company shall pay Contractor the Extended Standby Rate as stated in Exhibit D — Compensation per twenty-four hour day less any mutually agreed savings, which could include but not be limited to potential reductions in personnel (i.e. salary plus Payroll Burden).
 
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(4)          Company and Contractor shall mutually agree on the number of days of advance written notice that Company shall give Contractor to remobilize its personnel prior to the end of the Extended Standby Rate period.
 
(5)          Company will reimburse Contractor all direct costs, including airfare pursuant to Section 9.4 for returning released personnel to their Point of Origin during Extended Standby Rate periods and again upon returning the personnel to the Area of Operations immediately prior to the recommencement of Services.
 
(F)  Rate During Force Majeure Event(the “Force Majeure Rate”).
 
(1)          If any Force Majeure Event causes the suspension of Services, then:
 
(a)          Contractor shall he entitled to receive the Force Majeure Rate.
 
(b)          Company may extend the Operating Term for any or all of the Force Majeure period, subject to Company’s right to termination set forth in Section 8.1(F)(2).
 
(c)          If such suspension continues beyond thirty (30) days Company will pay Contractor thereafter one-half of the Extended Standby Rate until recommencement of Services or the Contract is terminated as set forth in Section 8.1(F)(2). In addition, if the Zero Rate is applicable for a Force Majeure Event, Contractor shall have the right to terminate the Contract unless Company has agreed to continue to pay the applicable Force Majeure Rate.
 
(2)          Company shall have the right to terminate this Contract, effective at least ninety (90) calendar days after the Force Majeure Event, by giving Contractor at least live calendar days prior written notice of termination. Company shall not be obligated to pay Contractor any further compensation after the effective date of such termination pursuant to this Section 8.1(F) other than for any monies owed for Services performed prior to such date and if applicable, the Demobilization Fee and termination fee as specified in Section 3.7. In addition, if the Zero Rate is applicable for a Force Majeure Event, Contractor shall have the right to terminate the Contract unless Company has agreed to continue to pay the applicable Force Majeure Rate.
 
(G) Redrill Rate(the “Redrill Rate”). If all or part of the hole is lost or damaged due to Contractor’s sole fault or negligence and Company elects that Contractor re-drill a portion of the hole or drill a new hole at a location to be designated by Company, then Company shall pay Contractor at the Redrill Rate as stated in Exhibit D - Compensation from the time of loss or damage until: (a) the new hole has reached the depth at which the original hole was abandoned or (b) the section has been re-drilled to the reasonable satisfaction of Company. If
 
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Contractor is not solely at fault or solely negligent for the loss or damage to the hole, Contractor shall be paid the applicable Service rate.
 
(H) Demobilization Fee(the “Demobilization Fee”). As full compensation for demobilizing the Drilling Unit and Contractor’s expatriate and national personnel on completion or abandonment of the last well to be drilled under this Contract, or upon early termination of the Contract in accordance with the provisions of Section 3.7, Company shall pay Contractor the Demobilization Fee if one is agreed to be paid in Exhibit D — Compensation subject to the provisions below. Demobilization shall commence when the last anchor is bolstered and the Drilling Unit is one (1) nautical mile from the last Company well location. It is noted that the costs of providing the following items are specifically excluded from the Demobilization Fee: towing vessels, anchor handling vessels, safety standby vessel, fuel for all vessels and the Drilling Unit, and rig positioning services which shall be provided by Company until Demobilization is complete.
 
(1)       Demobilization shall be considered complete when all Company’s equipment and personnel have been off-loaded and the Drilling Unit reaches the demobilization point as specified in Exhibit A — Scope of Work.
 
(2)       In the event that Contractor has not removed the Drilling Unit from the last well within the number of days set forth in Exhibit A — Scope of Work and in Sections 2.9 and 2.11, no Demobilization Fee will be paid by Company.
 
(I)   Rate When the Services Are Taken Over by Company.Company shall pay Contractor in accordance with Section 2.13(C)(2) when the Services are taken over by Company.
 
(J)   Service Rate After Reinstatement of the Contract.If Company has terminated the Contract and subsequently reinstates the Contract under Section 3.8, Company shall pay Contractor the rate in effect as of the termination of the Contract for the recommenced Services, unless otherwise agreed by the Parties in writing. Contractor shall not be entitled to any compensation for the period between such termination and reinstatement.
 
(K) Off Weather Rate.At any time one of the rates specified in Sections 8.1(B) or 8.1(C) is in effect, such rate shall continue to apply when normal Operations cannot be carried out due to adverse sea, loop/eddy currents, or adverse weather conditions, such as named tropical storms or inability to move due to weather for up to twenty four consecutive hours. Thereafter, Company shall pay the amount specified in the Contract per twenty-four hour day (“Off Weather Rate”) until Operations are recommenced or the Contract terminates or expires, whichever is earlier. Contractor’s superintendent in charge aboard the Drilling Unit shall make final determination as to when Operations are to be suspended and resumed in the event of these conditions.
 
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(L)  Zero Rate.Zero percent of the Operating Rate.
 
8.2          Effect of Mechanical Failure or Damage to the Drilling Unit.Unless otherwise provided in the Contract if there is a Work stoppage, the following shall apply:
 
(A) Work Stoppage Due to Drilling Unit Surface Equipment.
 
(1)       As used herein, “surface equipment” means Contractor’s drilling equipment that is not defined as “Subsea Equipment” in Section 8.2(C). Except as provided in Section 8.2(A)(2), if there is a Work stoppage due to mechanical failure or damage to the Drilling Unit surface equipment, Contractor is allowed the number of hours per calendar month to effect repairs to the Drilling Unit as set out in Exhibit A - Scope of Work.
 
(2)       If the Work stoppage continues in any calendar month beyond the number of hours allowed as set out in Exhibit A - Scope of Work, the Zero Rate shall apply. If Contractor unreasonably fails to immediately initiate and continue corrective action or fails to repair the surface equipment within ninety (90) calendar days so that the performanceof the Services can be re-commenced, Company may at any time after such ninety (90) day period, suspend or terminate the Contract. Company may give Contractor a written request to furnish a remediation plan including key milestones. Contractor shall provide the remediation plan to Company within a reasonable time after receipt of the written request from Company.
 
(3)       The monthly allotment of downtime allowed under Section 8.2(A)(1) shall not be cumulative from month to month and may not be carried forward, rolled over, or banked to any future month; and is not additional to the provisions of Section 6.2(D)(3).
 
(B)  Mechanical Failure due to Contractor’s Negligence.
 
(1)          If Services stop due to mechanical failure or damage to the Drilling Unit attributable to the sole and gross negligence of Contractor, then there shall be no further payments or other compensation due Contractor from Company until recommencement of drilling Services or the Contract is terminated or expires.
 
(2)          If Contractor unreasonably fails to immediately initiate and continue corrective action or fails to repair the surface equipment within ninety (90) calendar days so that the performance of the Services can be re-commenced, Company may at any time after such ninety (90) day period, suspend or terminate the Contract. Company may give Contractor a written request to furnish a remediation plan including key milestones. Contractor shall provide the remediation plan to Company within a reasonable time after receipt of the written request from Company.
 
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(C)  Work Stoppage Due to Drilling Unit Subsea Equipment.
 
(1)          If the Work stoppage is due to a mechanical failure or damage to the Drilling Unit’s Subsea Equipment then Contractor is allowed the number of hours per calendar month to effect the repairs to the Drilling Unit as set out in Exhibit A – Scope of Work. After such allowance is used up, the Zero Rate shall be applicable until either the recommencement of the Work or the Contract is terminated or expires. As used herein, “Subsea Equipment” means riser, slip joint, Subsea flex joint, flexible and hydraulic hoses, Subsea guidelines, choke and kill lines, LMRP, BOP stack (excluding the riser tensioner system), mooring system components when deployed below the water line (chain, wire, anchors, links, etc.) and BOP pods and associated lines.
 
(2)          If Contractor unreasonably fails to immediately initiate and continue corrective action or fails to repair the surface equipment within ninety (90) calendar days so that the performance of the Services can be recommenced, Company may at any time after such ninety (90) day period, suspend or terminate the Contract. Company may give Contractor a written request to furnish a remediation plan including key milestones. Contractor shall provide the remediation plan to Company within a reasonable time after receipt of the written request from Company.
 
(3)          The monthly allotment of downtime allowed under Section 8.2(C)(1) shall not be cumulative from month to month and may not be carried forward, rolled over, or banked to any future month and is not additional to the provisions of Section 6.2(D)(3).
 
(4)          If the BOP stack has been deployed and functional for a minimum consecutive period of one hundred eighty (180) days (as used herein, the “Extended Period”), the Parties will decide upon an appropriate time to pull the stack and perform preventative maintenance. The pulling, preventative maintenance, and redeployment shall be at the Operating Rate. Any repairs required after pulling the stack and prior to redeployment that at the reasonable opinion of Company and Contractor’s representatives on board the Drilling Unit were caused due to the deferred preventive maintenance during the Extended Period shall be performed at the Operating Rate. All other repairs will be performed at the rate allowed under Section 6.2(D)(3).
 
(5)          Subsea Equipment Work stoppage time includes time when normal Work is suspended to facilitate the recovery, deployment, repair, maintenance or replacement of Subsea Equipment that is lost, damaged, or not functioning as required other than by Force Majeure.
 
8.3          Variation of Service Rates.The Service rates set forth in Exhibit D – Compensation shall be revised to reflect documented changes in payroll related costs and equipment related costs as specified in Exhibit D (II) (8).
 
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8.4          Variation of Rates Due to Changes in Law.If after the Effective Date of this Contract, there occur any changes or amendments to any Ghana or Equatorial Guinea or other country of operation (as appropriate) statute, ordinance, decree or other law or regulation or enforcement change of any local or duly constituted authority, or the introduction of any such Ghana/Equatorial Guinea statute, ordinance, decree, or law which causes additional costs to Contractor in the execution of the Work, such additional costs which can be demonstrated to so significantly impact (One Thousand United States Dollars per day or greater) the profit realized from the Work to Company’s reasonable satisfaction upon submittal of supporting documentation, may be paid by Company and the compensation payable hereunder adjusted accordingly.  If the changes or amendments to any Ghana/Equatorial Guinea statute, ordinance, decree or other law or regulation cause a decrease in costs to Contractor in the execution of the Work, then the compensation will be adjusted accordingly. Notwithstanding the foregoing, if a change in law or change in enforcement of law under this Section 8.4 would result in an increased cost to Company in excess of $25,000.00 per day, Company shall have the right to treat such change in law or enforcement as a Force Majeure under Section 20.
 
9.       REIMBURSEMENTS TO CONTRACTOR
 
9.1          Reimbursement for Additional Materials and Services.If Company elects to have Contractor furnish certain additional materials and services not included on Exhibit A – Scope of Work and Contractor agrees to furnish such materials and perform or arrange for the performance of such Services, Company shall reimburse Contractor for the actual cost including actual documented freight costs incurred in furnishing such items. In addition, except for capital additions or modifications to the Drilling Unit that are agreed to, Contractor shall be entitled to charge Company a handling charge in accordance with the following amounts or percentages of the Contractor’s net final cost for such service and/or materials:
 
(A) Six percent where such cost or price is more than (US$1,000) but less than (US$10,000).
 
(B)  Four percent where such cost or price is equal to or more than (US$10,000) but less than (US$100,000).
 
(C)  Two percent where such cost or price is equal to or more than (US $100,000).
 
In no event shall the Handling Charge payable by Company hereunder exceed Ten Thousand U.S. Dollars (US$10,000) per order. Such additional materials provided under this Section 9.1 are considered materials of Company unless otherwise agreed.
 
9.2          Requirement to Competitively Bid.Unless otherwise mutually agreed in writing, any item purchased at Company’s request under Section 9.1 whose estimated cost is (US$10,000) or more and is available from more than one supplier shall be competitively bid. Contractor shall notify Company of the actual cost of such Service, purchase price or all bids and shall secure the prior
 
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approval of Company’s Representative prior to making any commitments. Invoices for Services under this Section 9.2 shall require the written approval of Company’s Representative and shall be handled in accordance with Section 10. Company shall receive the full benefit of any and all trade or cash discounts or rebates realized by Contractor as to items for which Contractor is seeking reimbursement from Company.
 
9.3          Reimbursement for Additional Personnel. Contractor shall be reimbursed for additional personnel requested by Company at the rates listed on Attachment A3 to Exhibit A — Scope of Work. In the absence of such listed personnel rates for the required positions, Company shall reimburse Contractor for the cost of additional personnel, as provided in Section 6.1(A)(4), on the basis of one of the following:
 
(A) A lump sum amount that is agreed to by the Parties. The Parties agree to incorporate this amount into the applicable daily rates by entering into an amendment of Exhibit D - Compensation.
 
(B)  Anamount equal to Contractor’s cost for salary plus Payroll Burden.
 
9.4          Reimbursement for Contractor’s Personnel Air Transportation.At any time Company is required to reimburse Contractor for personnel air transportation, Company shall reimburse Contractor the cost thereof up to but not to exceed the cost of economy air fare by the most expedient route to and from the Point of Origin identified in Exhibit A – Scope of Work.
 
9.5          Reimbursement for Meals and Lodging.The Service rates set forth in Section 8.1 and Exhibit D – Compensation include meals and lodging for the number of Company Persons and those of Company’s other contractors specified in Exhibit D – Compensation. Meals and lodging for additional persons shall be at the rate or the lump sum specified in Exhibit D - Compensation.
 
10.         FINANCIAL MATTERS
 
THIS SECTION OF THE CONTRACT HAS DIFFERENT FINANCIAL/PAYMENT PROVISIONS FOR EACH OF KOSMOS AND NOBLE WHICH SHALL APPLY EXCLUSIVELY TO EACH OF THESE TWO (2) ENTITIES SEPARATELY AND INDEPENDENTLY.
 
SECTIONS 10.1 THROUGH 10.6 APPLY TO KOSMOS:
 
10.1        Contractor’s Invoices.
 
(A) Contractor shall send original invoices to Company for the expected rates and fees payable under the Contract forty-five (45) days in advance of the first day of each month to which the invoice charges are projected to apply. Contractor shall direct these invoices to the Company address set out in Exhibit D — Compensation.
 
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(B)  Contractor shall include all of the following information in every invoice:
 
(1)       The title and number of this Contract.
 
(2)       The amount due in the Currency.
 
(3)       If applicable, all the following:
 
(a)          The amount of local currency due.
 
(b)          The value added tax, goods and services tax, sales tax or other taxes which Contractor proposes to collect or for which it will seek reimbursement from Company (including a tax assessed against Company but collected by Contractor).
 
(c)          Contractor’s tax registration number(s).
 
(4)       The relevant bank account information of Contractor.
 
(5)       Contractor shall also comply with the Invoicing Procedures of Kosmos attached hereto as Exhibit F.
 
(C)  Within 30 days after each month, Contractor shall provide Company a new, original invoice of actual costs and charges for the month billed in advance pursuant to Section 10.1(a) including a reconciliation of actual charges against the advance payment made by Company.
 
(D) All invoices rendered pursuant to Section 10.1 (C) shall be supported by Company approved timesheets, equipment sheets and shipping manifests where applicable, and shall be submitted in accordance with the provisions set forth in this Section 10.1. Contractor shall provide to Company’s satisfaction a detailed explanation to support the actual charges incurred, including hours worked, itemized expense accounts (with support vouchers), third party invoices, specific details of all other reimbursable costs incurred and any other requested information. To the extent requested by Company (subject to applicable laws and regulations), Contractor shall separately state, re-phrase, combine or separately invoice items in order to minimize the amount of value-added tax, goods and services tax, sales tax or other taxes which Contractor is required by law to collect or for which it will seek reimbursement from Company (including any tax that may be assessed against Company but collected by Contractor) applicable to any transaction under this Contract. In addition, each invoice shall be an original invoice from Contractor and from each vendor whose charges are included in the Contractor invoice as required by the Petroleum Agreement with The Republic of Ghana, Ghana National Petroleum Corporation and Kosmos Energy Ghana HC dated July 22, 2004.
 
(E)  Contractor, by delivering an invoice under Section 10.1(C), represents and warrants that its invoice and all documents submitted in support of its invoice
 
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(including third party invoices, vouchers, financial settlements, billings and reports) are true and correct.
 
(F)  Company may provide to Contractor, and Contractor shall accept and honor, an exemption certificate, a letter from the appropriate authority or a letter from Company agreeing that Company will self-assess and remit taxes, for one or more relevant taxing jurisdictions (instead of payment to Contractor), and Contractor shall not invoice Company for those taxes identified in the exemption certificate or letter. Company shall defend and fully indemnity Contractor from any and all costs arising from any challenges, actions, or assessments arising from Contractor’s reliance on an exemption certificate or similar letter presented by or on behalf of Company.
 
(G)  Right to Withhold Payments
 
(1)          If Company disputes all or part of an invoice rendered under Section 10.1(C) (including a Dispute about whether Contractor has fully complied with Section 10.1), Company shall notify Contractor of the Dispute.
 
(2)          If Company notifies Contractor of a Dispute in relation to part of an invoice, Contractor shall deposit the funds relative to Company’s Dispute in an escrow account until the Dispute is resolved.
 
10.2        Invoice Payments.Company shall pay Contractor’s invoices as follows:
 
Payment Timing.Company shall pay the invoice amounts at least fifteen (15) days in advance of the first day of the month to which the invoice applies. In the event of late payment, the parties must reach agreement within fifteen (15) days in order to avoid a suspension of operations. If payment resolution is not reached timely, Contractor may suspend operations at the Standby With Crews Rate until all outstanding amounts owed by Company to Contractor are paid in full. All invoices shall thereafter be substantiated by appropriate supporting documentation satisfactory to Company (such as Company-approved time sheets showing the applicable rates, third party invoices and other documentation of costs incurred by Contractor) to substantiate amounts chargeable to Company, consistent with the terms and conditions of the Contract. On a monthly basis, the Parties agree to review the total of the advance invoice(s) presented and paid relative to the proper charges for the goods and services actually provided by Contractor hereunder. Following this reconciliation, appropriate credit or supplemental invoices shall be prepared by Contractor for presentation to Company. Any resulting supplemental invoice or credit request shall be paid/issued within ten (10) days of receipt of the supplemental invoice or credit request as appropriate. In the event that Company fails to pay the supplemental invoice within ten (10) days of receipt, Contractor may provide written notice of the delinquency to Company. If Company fails to then make payment in full to Contractor within five (5) days of receipt of the delinquency notice, Contractor may suspend operations at the Standby With Crews Rate until all outstanding amounts owed by Company to Contractor are paid in full. Contractor may also opt to terminate this Contract for Company’s failure to make full payment hereunder. In
 
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the event of such termination, Company shall remain liable to pay Contractor eighty percent (80%) of the Operating Rate for the balance of days of dayrate operations remaining in the Kosmos’ designated segments of the Contract or until the Drilling Unit commences dayrate operations with another operator, whichever occurs first. In the event that substitute operations with another operator are secured, Kosmos shall be given credit for the dayrate payments made to Contractor for such substitute work. In the event that the dayrates paid to Contractor under such substitute work are less than the dayrates payable by Kosmos under this Contract, Kosmos shall remain liable to pay Contractor the full difference between the two (2) rates.
 
10.3                                    No Waiver of Company’s Rights.The payment of, objection to or failure to object to any invoice, or any payment or settlement in resolution of any Dispute, or any combination of these matters does not constitute acceptance by Company of the accuracy or justification of Contractor’s invoices. Any payment by Company is made on the condition that Company reserves the right to challenge, at a later time, the validity of any invoiced amount.
 
10.4                                    Liens and Subcontractor Payments.
 
(A)               Contractor’s Obligation.Contractor shall pay (or procure the payment of) any valid Claims owed by Contractor or Subcontractors for personnel, materials and equipment used in the performance of the Services as they become due. Except as may arise by operation of law, no Lien may become fixed upon any property of Company Group or Contractor as a result of Contractor failing to pay (or to procure the payment of) its debts or the debts of Subcontractors when due.
 
(B)                 Company’s Right to Pay.If Contractor fails to pay (or fails to procure the payment of) valid Claims owed by Contractor or Subcontractors, Company has the right to pay these Claims and to offset these payments against amounts due or which become due to Contractor under this Contract. Except as required by law, court order or other lawful authority, Company shall not pay Claims that Contractor is actively contesting if Contractor has taken all actions necessary (including the posting of a bond or other security to remove Liens on any property of Company Group) to protect the interests of Company Group.
 
(C)                 Contractor’s Certificate of Payment.BeforeCompany pays any of Contractor’s invoices, Company may require Contractor to certify that there is no unsatisfied Claim for personnel or equipment payable by Contractor in relation to the Services provided under this Contract.
 
10.5                                    Overpayments.Contractor shall pay to Company any money paid to Contractor by Company under this Contract to which Contractor was not entitled, as soon as Contractor becomes aware of that overpayment or repayment is requested in writing by Company.
 
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10.6                                    Electronic Procurement
 
(A)               Company may implement an electronic procurement process to enhance the management of this and other commercial transactions from requisition through payment.
 
(B)                 If an electronic procurement process applicable to this Contract is implemented by Company during the effectiveness of this Contract, Contractor agrees to coordinate with Company to support implementation in a manner agreed to by Company and Contractor.
 
SECTIONS 10.7 THROUGH 10.12 APPLY TO NOBLE:
 
10.7                                    Contractor’s Invoices.
 
(A)               Contractor shall send invoices each month to the Company address set out in Exhibit D – Compensation. All invoices shall be supported by Company approved timesheets, equipment sheets and shipping manifests where applicable, and shall be submitted in accordance with the provisions set forth in this Section 10.7.
 
(B)                 Contractor shall include all of the following information in every invoice:
 
(1)                                 The title and number of this Contract.
 
(2)                                 The amount due in the Currency.
 
(3)                                 If applicable, all the following:
 
(a)                                 The amount of local currency due.
 
(b)                                The value added tax, goods and services tax, sales tax or other taxes which Contractor proposes to collect or for which it will seek reimbursement from Company (including a tax assessed against Company but collected by Contractor).
 
(c)                                 Contractor’s tax registration number(s).
 
(4)                                 The relevant bank account information of Contrator.
 
(C)                 With each invoice, Contractor shall provide to Company’s satisfaction a detailed explanation to support its charges, including hours worked, itemized expense accounts (with support vouchers), third party invoices, specific details of all other reimbursable costs incurred and any other requested information. To the extent requested by Company (subject to applicable laws and regulations), Contractor shall separately state, re-phrase, combine or separately invoice items in order to minimize the amount of value-added tax, goods and services tax, sales tax or other taxes which Contractor is required by law to collect or for which it will seek reimbursement from Company (including any tax that may be assessed against Company but collected by Contractor) applicable to any transaction under this Contract.
 
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(D)                Contractor, by delivering an invoice, represents and warrants that its invoice and all documents submitted in support of its invoice (including third party invoices, vouchers, financial settlements, billings and reports) are true and correct.
 
(E)                  Company may provide to Contractor, and Contractor shall accept and honor, an exemption certificate, a letter from the appropriate authority or a letter from Company agreeing that Company will self-assess and remit taxes, for one or more relevant taxing jurisdictions (instead of payment to Contractor), and Contractor shall not invoice Company for those taxes identified in the exemption certificate or letter. Company shall defend and fully indemnity Contractor from any and all costs arising from any challenges, actions, or assessments arising from Contractor’s reliance on an exemption certificate or similar letter presented by or on behalf of Company.
 
(F)                  Contractor shall submit all invoices to Company as soon as possible, but no later than three (3) months after completion of the Services on each well under this Contract. Company will not pay invoices submitted after this date unless otherwise agreed to by the Parties.
 
10.8       Invoice Payments.   Provided Contractor’s invoices comply with Section 10.7, Company shall pay Contractor’s invoices as follows:
 
(A)               Payment Timing.Company shall pay undisputed invoice amounts within thirty (30) days from Company’s receipt of the invoice.
 
(B)                 Right to Withhold Payments.
 
(1)                                 If Company disputes all or part of a paper invoice (including a Dispute about whether Contractor has fully complied with Section 10.7), Company shall notify Contractor of the Dispute and pay the undisputed portion.
 
(2)                                 If Company notifies Contractor of a Dispute in relation to part of a paper invoice, Company may withhold the disputed portion until the Dispute is resolved.
 
(3)                                 If Company disputes an electronic invoice, Company may reject the invoice and Contractor shall correct all deficiencies and errors before resubmitting that invoice. If Company pays a disputed electronic invoice, Contractor shall reimburse Company for the disputed items (including those resulting from pricing, discount calculation or sales tax calculation errors) after payment is made.
 
(4)                                 If Company notifies Contractor of Contractor’s failure to comply with any obligation of this Contract, and Contractor remains in non-compliance for a period of five (5) days after receiving Company’s notice of non-compliance, Company may withhold payment of any outstanding invoice until Contractor is in full compliance.
 
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(C)                 Notification of Non-Payment of an Undisputed Invoice.If Contractor has not received payment of any undisputed invoice amount that otherwise complies with Section 10.7 for more than thirty (30) days after Company’s receipt of that invoice, Contractor may notify Company of this non-payment. Interest shall accrue on all undisputed past due invoices at the rate of one percent (1%) per month or the maximum legal amount, whichever is less, until paid in full. Company will immediately make reasonable efforts to resolve the issue. If full payment is not received within thirty (30) days of receipt of the notice of non-payment, Contractor may suspend its performance of the Contract and remain of the Standby With Crews Rate until all outstanding amounts owed by Company to Contractor are paid in full. Contractor may also opt to terminate this Contract for Company’s failure to make full payment hereunder. In the event of such termination, Company shall remain liable to pay Contractor eighty percent (80%) of the Operating Rate for the balance of days of dayrate operations remaining in the Noble designated segments of the Contract or until the Drilling Unit commences dayrate operations with another operator, whichever occurs first. In the event that substitute operations with another operator are secured, Noble shall be given credit for the dayrate payments made to Contractor for such substitute work. In the event that the dayrates paid to Contractor under such substitute work are less than the dayrates payable by Noble under this Contract, Noble shall remain liable to pay Contractor the full difference between the two (2) rates.
 
(D)                Banking Regulations and Currency Requirements.Subject to all applicable laws, including banking and currency laws, Company shall pay undisputed Contractor’s invoices as follows:
 
(1)                                 Company shall pay funds to Contractor by check to the address set in the signature page to this Contract or by wire transfer to the account of Contractor as set out in Exhibit D - Compensation.
 
(2)                                 Company shall make all payments in the Currency (including expenses paid in other currencies that Contractor has converted as required by this Contract and invoiced in the Currency). Contractor shall provide documentary evidence of the conversion rate from the other currency into the Currency to the satisfaction of Company.
 
10.9                No Waiver of Company’s Rights.The payment of, objection to or failure to object to any invoice, or any payment or settlement in resolution of any Dispute, or any combination of these matters does not constitute acceptance by Company of the accuracy or justification of Contractor’s invoices. Any payment by Company is made on the condition that Company reserves the right to challenge, at a later time, the validity of any invoiced amount,
 
10.10          Liens and Subcontractor Payments.
 
(A)               Contractor’s Obligation.Contractor shall pay (or procure the payment of) any valid Claims owed by Contractor or Subcontractors for personnel, materials and equipment used in the performance of the Services as they become due.
 
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Except as may arise by operation of law, no Lien may become fixed upon any property of Company Group or Contractor as a result of Contractor falling to pay (or to procure the payment of) its debts or the debts of Subcontractors when due.
 
(B)                 Company’s Right to Pay.If Contractor fails to pay (or fails to procure the payment of) valid Claims owed by Contractor or Subcontractors, Company has the right to pay these Claims and to offset these payments against amounts due or which become due to Contractor under this Contract. Except as required by law, court order or other lawful authority, Company shall not pay Claims that Contractor is actively contesting if Contractor has taken all actions necessary (including the posting of a bond or other security to remove Liens on any property of Company Group) to protect the interests of Company Group.
 
(C)                 Contractor’s Certificate of Payment.Before Company pays any of Contractor’s invoices, Company may require Contractor to certify that there is no unsatisfied Claim for personnel or equipment payable by Contractor in relation to the Services provided under this Contract.
 
10.11          Overpayments.Contractor shall pay to Company any money paid to Contractor by Company under this Contract to which Contractor was not entitled, as soon as Contractor becomes aware of that overpayment or repayment is requested in writing by Company.
 
10.12          Electronic Procurement
 
(A)               Company may implement an electronic procurement process to enhance the management of this and other commercial transactions from requisition through payment.
 
(B)                 If an electronic procurement process applicable to this Contract is implemented by Company during the effectiveness of this Contract, Contractor agrees to coordinate with Company to support implementation in a manner agreed to by Company and Contractor.
 
11.                              CONFLICT OF INTEREST, IMPROPER INFLUENCE AND DATA PRIVACY
 
11.1                                    Conflict of Interest.
 
(A)               Contractor shall not, either directly or indirectly, pay any commission or fees or grant any rebates or other remuneration or gratuity to any employee, agent or officer of Company. Contractor shall cause its subcontractors (and all of Contractor Group) to be bound by the same obligations as Contractor under this Section.
 
(B)                 Reporting Violations and Reimbursement.Contractor shall immediately notify Company of any violation of Sections 11.1, 11.2 or 12 or of the occurrence
 
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of any event prior to the Effective Date which, if it had occurred after the Effective Date would constitute a violation of Section 11.1, 11.2 or 12, and shall defend, indemnify, and hold Company and Company Group harmless from and against any and all fines and penalties arising from or related to, any breach of such representation and warranty. This indemnity obligation shall survive termination or expiration of this Contract. Contractor shall respond promptly, and in reasonable detail, to any notice from Company, some other member of the Company Group or their respective auditors pertaining to the above stated representation, and shall furnish documentary support for such response upon request from Company.
 
(C)                 Termination.Company may, at its sole option, terminate this Contract with immediate effect for any violation of Sections 4.1(E), 11.1, 11.2 or 12. If Company terminates this Contract for violation of Sections 4.1(E), 11.1, 11.2 or 12, Company is not obligated to pay compentsation or reimbursement to Contractor for any Services performed or expenses incurred after the date of termination.
 
11.2                                    Improper Influence.
 
Contractor makes the following representations and warranties and undertakes to perform the covenants set out below:
 
(A)               Contractor is familiar with, and has reviewed and understands, the provisions of the United States Foreign Corrupt Practices Act of 1977, as amended (“FCPA”);
 
(B)                 None of the Contractor Group has made and will not make, directly or indirectly, in connection with this Agreement, any offer, payment, loan, or gift of anything of value to a Government Official, to an immediate relative of a Government Official, or to any other person while knowing or having reasons to suspect that any part of such offer, payment, loan or gift will be given or promised to a Government Official, the offer, payment, loan or gift of which would (1) violate any statute, law or regulation of any federal, state, municipal, or other governmental body, agency, authority, department, commission, or instrumentality of any country; (2) be contrary to or in violation of the principles set forth in the United Nations Convention Against Corruption that entered into force on December 14, 2005, and the African Union Convention on Preventing and Combating Corruption that entered into force on August 5, 2006; (3) violate the FCPA; or (4) cause any of the Parties or any of their Affiliates (or any of their officers, directors, employees or agents) to be in violation of the FCPA. As used in this Contract, Government Official means: (i) any official, employee, agent, advisor or consultant of a non-U.S. government or any federal, regional or local department, agency, state-owned enterprise or corporation or any other instrumentality thereof, (ii) any official or employee or agent of a public international organization, or (iii) any official or employee or agent of a political party or candidate for political office.
 
(C)                 No ownership interest in Contractor, other than an immaterial one, is or will be directly or indirectly held or controlled by a Government Official, or any
 
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immediate relative of a Government Official. None of the Contractor Group is or will be a Government Official, or an immediate relative of a Government Official and no ownership interest in any member of Contractor Group, other than an immaterial one, is or will be directly or indirectly held or controlled by a Government Official, or any immediate relative of a Government Official.
 
(D)                Contractor will comply with Exhibit G.
 
(E)                  In the event of any breach by Contractor or any member of Contractor Group of this Section 11.2; (i) Company will have no further obligation to pay the compensation provided for in the Contract after termination of the Contract; (ii) Company shall be entitled to compensation from Contractor equal to the extent of the amount of funds or value paid by Contractor in breach of this Section; and (iii) Contractor shall hold harmless and indemnify Company and Company Group from and against any and all fines and penalties arising from or related to, any breach of such representation and warranty (including attorneys’ fees and court costs if a breach is ultimately confirmed through a legal or judicial process). Upon reasonable prior written notice, Company or its designated agents shall be permitted access to all books and records of Contractor reasonably related to compliance with this Section, any payment made in connection with provision of the Work, and/or the performance by Contractor of the Work, including for the purpose of auditing such books and records, all at the expense of Company.
 
11.3                                    Data Privacy. Contractor will comply with all reasonable requests of Company with respect to protecting personal data of Company employees, customers, and suppliers it receives in connection with its performance of the Services, including the following Company’s instructions in connection with processing such personal data; implementing adequate security measures to protect such personal data; not disclosing such personal data to any third party without Company’s written permission; and complying with all applicable data privacy laws.
 
12.                              CONTROLS, RECORDS AND INSPECTION
 
12.1                                    Controls.  Contractor shall establish and maintain, and ensure that other members of Contractor Group establish and maintain, all Controls which are necessary and appropriate in accordance with good management practice (under the circumstances of this Contract) to ensure:
 
(A)               Theaccuracy and completeness of Contractor’s invoices under this Contract and of the Records required to be kept by Section 12.2.
 
(B)                 Compliance with Sections 11.1 and 11.2 of this Contract, and detection of any other improper conduct by members of Contractor Group.
 
(C)                 Compliance with all other obligations of Contractor under this Contract, including Exhibit B Independent Contractor Health, Environmental and Safety Guidelines and Exhibit C Drug, Alcohol and Search Policy.
 
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12.2                                    Records. Contractor shall establish and maintain, and ensure that other members of Contractor Group establish and maintain, all Records which are necessary and appropriate in accordance with good management practice (under the circumstances of this Contract) to record accurately and completely all of the following:
 
(A)               The performance by Contractor of its obligations under this Contract, including well records and reports required under Section 2.14.
 
(B)                 The liability for and calculation of all amounts payable by Company to Contractor under this Contract.
 
(C)                 All amounts payable by Contractor or Subcontractors to other members of Contractor Group or other Persons in connection with the performance by Contractor of its obligations under this Contract.
 
(D)                The Controls adopted by members of Contractor Group in accordance with Section 12.1.
 
(E)                  Compliance with Sections 11.1 and 11.2.
 
12.3                                    Retention of Records. All Records required to be kept by Section 12.2 shall be maintained and retained by Contractor Group until at least three years from the end of the calendar year in which this Contract is completed or terminated. All Records required to be kept by Section 12.2 shall be maintained in either paper or unalterable electronic format; if in electronic format, then the Record must be reproducible onto a printed paper copy. If any Dispute arises under this Contract then all Records relevant to the Dispute shall be retained at least until the Dispute is finally resolved and all obligations arising out of the resolution of the Dispute are satisfied.
 
12.4                                    Inspection of Records. Company may, at any time, at its own cost, inspect all Records pertaining to Section 12.2(E). Company may also inspect all Records held by Contractor Group which relate to Sections 12.2(A) through 12.2(D) until at least three (3) years from the end of the calendar year in which this Contract is completed or terminated. Where Company inspects Records under this Section 12.4:
 
(A)               The inspection shall take place following reasonable notice at the premises of the Contractor Group member where those Records are kept, during normal business hours.
 
(B)                 The inspection may be carried out by Company or by any Person engaged by Company for that purpose.
 
(C)                 The Company may conduct the inspection only for the purpose of determining any of the following:
 
(1)                                 Whether Contractor has complied with this Contract.
 
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(2)                                 The veracity of invoices and support documents.
 
(3)                                 Whether Contractor and Subcontractors have satisfied their payment obligations to other Contractor Group members or other Persons arising out of this Contract.
 
(D)                Company (or its representatives conducting the inspection on Company’s behalf) may, at its own cost, make copies of any of the Records. Contractor shall, if requested by Company, make copying facilities available at a reasonable cost to Company or its representatives at the time of the inspection in the place where the inspection is taking place.
 
(E)                  Company is not responsible for any costs of Contractor Group incurred in conducting the inspection other than copying costs referred to in Section 12.4(D). Contractor is not responsible for any costs of Company incurred in conducting the inspection.
 
12.5                                    Access and Assistance.Contractor shall provide, and shall ensure that other members of Contractor Group provide, all of the following:
 
(A)               Access to all relevant sites to enable Company or its representatives to carry out inspections under this Contract, including access to all relevant material, equipment and personnel used in the provision of the Services.
 
(B)                 All Records requested by Company or its representatives for the purposes of inspection under this Section 12, and full assistance in performing the inspection and accessing those Records.
 
12.6                                    Use of Information.Company may only use information obtained from inspections under Section 12.5 for the administration or enforcement of this Contract, for tax or audit purposes, or for the resolution of Disputes.
 
12.7                                    Confidentiality. Company shall keep all information obtained from inspections under Section 12.4 confidential, except that Company may disclose the information in each of the following circumstances:
 
(A)               To the extent necessary for the uses permitted by Section 12.6.
 
(B)                 Where disclosure is required by applicable law, court order, stock exchange regulations, or government order, decree, regulation or rule, or where failure to disclose could reasonably result in sanctions or increased sanctions against a member of Company Group.
 
13.                              TAXES
 
13.1                                    Contractor’s Taxes.Other than taxes payable by withholding, Contractor shall be fully reimbursed by Company for all liabilities or Claims for taxes of the Country or Area of Operations that any taxing authority (including any political subdivision of the Country) claiming jurisdiction over this Contract, or the Area
 
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of Operations or any part of the Country, may assess or levy against Contractor relating to the Services or this Contract, including all of the following:
 
(A)               Income.Income, excess profit or other taxes, charges and imposts assessed or levied on account of Contractor’s earnings or receipts.
 
(B)                 Personnel.Taxes assessed or levied against or on account of compensation or other benefits paid to Contractor’s employees.
 
(C)                 Property.Taxes assessed or levied against or on account of, or by reference to the value of, any property or equipment (including materials and consumable supplies) of Contractor except Import/Export Charges reimbursable by Company under Section 6.3(E).
 
(D)                Services.Taxes assessed or levied against or on account of, or by reference to the value of the Services or this Contract.
 
13.2                                    Company’s Taxes.Company is responsible for all liabilities or Claims for taxes that any taxing authority (including taxing authorities of any political subdivisions of the Country) claiming jurisdiction over this Contract, or the Area of Operations or any part of the Country, may assess or levy against Company relating to the Services or this Contract (except for erroneous assessments or levies of taxes described in Section 13.1).
 
13.3                                    VAT, GST, Sales and Similar Taxes.If any value added tax (VAT), goods and services tax, sales tax, other excise taxes and/or other similar taxes are required to be paid by the Contractor, these taxes shall be separately itemized and identified on Contractor’s invoices as provided in Section 10; collected by Contractor from payments made by Company hereunder and paid over by Contractor to the appropriate governmental agency in accordance with the law in the relevant jurisdiction (except to the extent Company advises Contractor that in accordance with applicable law, Company will be responsible for self- assessing and paying these taxes); and Contractor shall provide Company on a timely basis with invoices, tax receipts and any other documentation that may be required for Company to obtain tax reimbursement, credit, abatement or refund of any taxes assessed against Company and collected by Contractor.
 
13.4                                    Subcontractor Taxes.As between Company and Contractor, Contractor is solely responsible for all liabilities or Claims for taxes of any kind that any taxing authority may assess or levy with respect to actions (or omissions to act) of any Subcontractor, its directors, officers, employees or agents in relation to this Contract or the Services.
 
13.5                                    Reports and Withholding.Contractor shall comply with all applicable tax rules and requirements on a timely basis, including submitting all tax reports, filing all registrations and taking all actions necessary to make its tax payments. Contractor must provide Company with written proof that it has made all registrations required by the preceding sentence if requested by Company. Subject to applicable laws and regulations, Contractor shall cooperate with
 
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Company to correctly report the amount of applicable taxes (including without limitation actions described in Section 10.1 and Section 6.3(C)), and Contractor shall not take any action that is prejudicial to obtaining an available tax exemption. Company will provide Contractor with tax receipts (or other proof of payment if receipts are unavailable) for any withheld taxes. Consistent with Section 10, Contractor will report, withhold and pay to the tax authorities any tax required by applicable law to be withheld on account of any Services performed by Subcontractors. Contractor shall claim any available exemption from value added tax as well as the benefit of any exemption from, or reduction in, any tax, fee, or other charge which may be available to Company or Contractor, under the terms of the law of the country of operations, or with any written agreements with the country of operations as amended, modified or supplemented from time to time. Company is entitled to withhold any taxes required to be withheld under applicable law. The tax withholding rate at the Efiective Date is understood by the Parties to be 5% for operations in Ghana and 6.25% for operations in Equatorial Guinea. The withholding tax rate on mobilization periods is understood to be zero or other rate, as applicable.
 
13.6                               Tax Records.In addition to the requirements of Sections 12.2, 11.3 and 13.5:
 
(A)     Contractor shall maintain Records sufficient to substantiate all taxes, Import/Export Charges, fees, indemnities or other payments that may affect any obligations of Company for so long as the longest applicable statute of limitations (including any waivers of a statute of limitations by Contractor) remains open, under which a taxing authority may institute audit, assessment or collection procedures for taxes paid or allegedly due in connection with this Contract.
 
(B)       Contractor shall provide at Company’s request and in the format requested by Company, all schedules, summaries or other data available to Contractor or any of its Subcontractors that Company requires to prepare tax returns, refunds, claims and credits or for use in external tax audits in connection with this Contract.
 
13.7                               Cooperation.Company and Contractor shall cooperate and assist each other in securing any beneficial tax treatment and in fully minimizing tax obligations resulting from this Contract and the performance of the Work hereunder.
 
14.          CLAIMS, LIABILITIES AND INDEMNITIES
 
14.1                               INTENT OF INDEMNITY PROVISIONS. The Parties agree to allocate between them responsibility for all Claims as set out below.
 
14.2                               PROPERTY.
 
(A)      Subject to the provisions of Section 14.2(B), if damage is suffered or loss is incurred in relation to Property of any Person where that damage or loss arises out of this Contract, Contractor (a) releases Indemnitees from Claims by Contractor for that damage or loss, and (b) indemnifies Indemnitees against that damage or loss and
 
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against Claims against the Indemnitees by other Persons for that damage or loss, subject to Section 14.3. Losses contemplated by this Section 14.2(A) include the cost of removal of wreckage.
 
(B)      Damage or Loss to Downhole Equipment. Company shall reimburse Contractor for damage to or loss of the Drill String and other downhole equipment (“Downhole Equipment”) while in the hole caused by other than Contractor’s negligence or normal wear and tear. Company shall pay Contractor the lesser of its repair cost or the replacement cost in accordance with the provisions below:
 
(1)                           If the Downhole Equipment component is new attheCommencement Date of the Contract, ninety percent of the replacement cost:
 
(2)                           If the Downhole Equipment component is used at the Commencement Date of the Contract or at time of replacement of damaged components – seventy-five percent (75%) of replacement cost.
 
(3)                           If used Downhole Equipment component is replaced during the Contract with new Drill String components, ninety percent of the replacement cost:
 
(4)                           Reimbursement under this Section 14.2(B) is based on Contractor’s actual documented cost to repair or replace the damaged component(s), plus, if shipped to the Area of Operations, actual documented freight, duties (reimbursement of duties being subject to Section 6.3) and handling costs incurred by Contractor for transport of the replacement component(s) to the Company’s shore base.
 
(5)                           Any reimbursement hereunder shall be reduced by any amount recoverable from Contractor’s insurance.
 
(C)      Damage to Subsea and Mooring Equipment.
 
(1)                           Damage to Subsea Equipment.
 
(a)                            Company shall reimburse Contractor for damage or loss to Contractor’s Subsea Equipment as defined in Section 8.2(C)(1) as a result of a loop, eddy or other adverse current that causes such equipment to exceed its technical capabilities subject to the following:
 
(i)            Contractor shall, as soon as reasonably practical, notify Company in the event operating conditions exceed the technical limitations of the
 
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equipment or in the event operating conditions are anticipated to exceed such limitations.
 
(ii)                               In the event such currents are unknown to Contractor or such damage is unknown to Contractor, Contractor shall advise Company of such currents or damage once known, but Contractor shall nevertheless be entitled to reimbursement under this Section 14.2(C).
 
(iii)                           In the event Contractor advises Company of such condition and Company requires Contractor to proceed with Operations or the state of Operations precludes any mitigating action on the part of Contractor, refusal by Contractor to proceed with Operations will not be considered a breach of any provision of the Contract and will not be considered Drilling Unit downtime.
 
(b)                                 Contractor shall, as soon as reasonably practical, notify Company in writing in the event Contractor is of the opinion that the bathymetry supplied to Contractor by Company reflects unsafe conditions in which to operate the Drilling Unit. In the event that Contractor advises Company in writing of such unsafe conditions and Company requests Contractor to proceed with Operations, refusal by Contractor to proceed with Operations will not be considered a breach of any provision of the Contract and will not be considered Drilling Unit downtime.
 
(2)                                Damage to Mooring Equipment. Company shall reimburse Contractor for damage to or loss of Contractor’s mooring equipment while in use caused by other than Contractor’s negligence, manufacturer’s defects or damage existing prior to the Commencement Date. Equipment covered hereunder includes fairleaders, anchors, anchor wires and chains, tripping lines, shackles, pendant lines, jewelry and buoys. Company’s responsibility hereunder shall however be limited to Contractor’s insurance deductible actually suffered in respect of such claims.
 
(3)                                Company shall reimburse Contractor for damages incurred to Contractor’s equipment as set forth in Sections 14.2(C)(1) and (2) in an amount equal to the then current replacement cost of such equipment delivered to the Drilling Unit, or the repair cost, whichever is the lesser amount. Furthermore,
 
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Company’s liability under Section 14.2(C)(1) is capped at Contractor’s insurance deductible or US$6,000,000 per occurrence, whichever is less.
 
(D)           If the Property referred to in this Section 14.2 is Property of a Third Party, then each Party will indemnify the other Party to the extent the damage or loss was caused by each Party’s fault or negligence.
 
14.3                                                  INDEMNITEES’ PROPERTY. If the Property referred to in Section 14.2 is Property of an Indemnitee, all of the following apply:
 
(A)                             Contractor shall indemnify Indemnitees against any damage or loss to the extent any member of Contractor Group was at fault or negligent up to the maximum amount per occurrence of US$1,000,000 or its Currency equivalent. Company shall release and indemnify Contractor Group for any damage to or loss of Property of Indemnitees in excess of US$1,000,000 or its Currency equivalent per occurrence.
 
(B)                               Subject to the limits of liability in Sections 14.3(A) above, at Company’s option, Contractor shall where possible repair or replace the damaged or lost property.
 
14.4                                                  ILLNESS, INJURY OR DEATH.    Contractor (a) indemnifies Indemnitees against, and (b) indemnifies Indemnitees from Claims made against the Indemnitees by other Persons for, injury to or death of any Person (including Contractor Group’s employees and Indemnitees’ employees) where that injury or death arises out of this Contract.
 
(A)                             If the Person referred to in Section 14.4 is an employee of an Indemnitee, Contractor shall indemnify Indemnitees to the extent the injury or death was caused by the fault or negligence of any member of Contractor Group up to a maximum amount of US$1,000,000 or its Currency equivalent per Person. Company shall indemnify Contractor Group for any Claims for injury to or death of an employee of an Indemnitee in excess of US$1,000,000 or its Currency equivalent per Person.
 
(B)                               If the Person referred to in Section 14.4 is a Third Party, then each Party will indemnify the other Party to the extent the injury or death was caused by each Party’s fault or negligence.
 
14.5                                                  POLLUTION DAMAGE.    Contractor indemnifies Indemnitees against all Claims arising out of this Contract in relation to pollution, seepage or contamination, including cleanup costs which originates above the surface of the sea and from Contractor’s equipment or equipment under Contractor’s care, custody and/or control.
 
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14.6                                                  LIMITATION ON LIABILITY FOR WELL EVENT CONTROL COSTS AND WELL EVENT POLLUTION COSTS. If a Well Event arises out of this Contract, the following limitations on liability apply:
 
(A)          For Well Event ControlCosts, both ofthe following apply:
 
(1)                   Company releases each member of Contractor Group from Claims by Company for Well Event Control Costs.
 
(2)                   Company indemnifies each member of Contractor Group against Claims for Well Event Control Costs.
 
(B)            For Well Event Pollution Costs and for pollution originating below the surface of the water, all of the following apply:
 
(1)                                 Contractor’s liability for Well Event Pollution Costs and for pollution originating below the surface of the water is limited to US$250,000 or its Currency equivalent per Well Event occurrence.
 
(2)                                 Company releases each member of Contractor Group from Claims by Company for Well Event Pollution Costs and for pollution originating below the surface of the water to the extent that total recoveries by Company against Contractor Group members exceed US$250,000 or its Currency equivalent per Well Event occurrence or per event of pollution originating below the surface of the water.
 
(3)                                 Company indemnifies each member of Contractor Group against Claims for Well Event Pollution Costs and for pollution originating below the surface of the water to the extent that total recoveries against Contractor Group members exceed US$250,000 or its Currency equivalent per Well Event occurrence or per event of pollution damage originating below the surface of the water.
 
14.7                                                  USE OF MEDICAL FACILITIES OR MEDICAL EVACUATION. Contractor indemnifies Indemnitees against Claims for illness, injury to or death of members of Contractor Group, or for damage to or loss incurred in relation to members of Contractor Group Property, that arise out of or in connection with the recovery, diagnosis, treatment or medical evacuation of personnel, or the provision of pharmaceutical products or medical supplies furnished or rendered by Company Group, Company’s other contractors or subcontractors or by the facility used by Company.
 
14.8                                                  INTELLECTUAL PROPERTY. Contractor agrees to fully defend, protect, indemnify and hold harmless Indemnitees against claimed or actual infringement or contributory infringement of any patent,
 
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or infringement of any copyright or trademark, or misappropriation of any trade secret arising out of or in connection with the work performed by Contractor under this Contract or the implementation by Indemnitees of the work results. Company shall promptly notify Contractor if Company is threatened with a Claim or becomes aware of any actual or potential third party Claim against it or any Indemnitees concerning the matters addressed in this Section 14.8, based in whole or in part on the Services or the implementation by Indemnitees of the results of the Services. In addition to other obligations relating to the defense of any such Claim, neither Party shall settle or compromise any such Claim without the written consent of the other Party. In the event of any such Claim, Contractor shall perform one of the following actions at its own expense to avoid future infringement:
 
(A)                        Modify or replace any equipment that Contractor has built or provided or any process that Contractor is using based on the results of the Services in order to avoid the patent infringement or trade secret violation. Such modification or replacement must be accomplished in a manner that is acceptable to Company and that does not detrimentally impact the performance of the affected equipment or process.
 
(B)                          Secure for the benefit of Company irrevocable and fully paid licenses for the equipment or operation of the process in order to avoid any future infringement without the need to modify or replace equipment or modify processes based on the work results provided to Company. Such licenses must be obtained at no cost to Company and on terms acceptable to Company.
 
(1)                                 Likewise and vice versa, Company shall release, defend and indemnify Contractor from any actual or alleged violation of any intellectual property rights arising from any equipment or processes provided by Company Group and shall replace such infringing equipment or process or provide a license for its use as appropriate.
 
14.9                                             FINES AND ASSESSMENTS.   To the fullest extent permitted by law, Contractor indemnifies Indemnitees against the imposition of fines, fees, orders of restitution or penalties where the event which led to that imposition arises out of Contractor’s actions or inactions under this Contract.
 
14.10                                       CONFLICT OF INTEREST AND IMPROPER INFLUENCE.   Contractor indemnifies Indemnitees against Claims that arise out of or in connection with any inaccuracy of the representations set out in Section 4.1(E) or any violation of Sections 11.1 or 11.2.
 
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14.11                                            BREACH OF APPLICABLE LAW.   Contractor indemnifies Indemnitees against Claims that arise out of or in connection with any breach by any member of Contractor Group of applicable law.
 
14.12                                            INDEMNITY FOR LIENS. Contractor indemnifies Indemnitees against any and all losses,costs, damages, liabilities or Claims that arise out of or in connection with a Lien becoming fixed upon or asserted against any Property of Company Group or Contractor as a result of Contractor failing to pay (or to procure the payment of) its debts or the debts of Subcontractors when due in violation of Section 10.4. This indemnity is in addition to the rights and remedies specified in Section 10.4(B). Likewise and vice versa, Company shall indemnify Contractor Group from any Liens being placed upon the Property of Contractor Group as a result of the actions of Company Group hereunder.
 
14.13                                            INDEMNITY FOR IMPORT AND EXPORT OBLIGATIONS.   If Contractor’s failure to comply with any requirement of Section 6.3 results in Company not receiving the full benefit of or otherwise prejudices any available Import/Export Exemption or results in failure to obtain any necessary permits, licenses, authorizations or customs clearances, Contractor indemnifies Indemnitees against any damages, losses, costs, taxes, duties, interest, charges, fines or penalties relating to Contractor’s action or failure to act, and any taxes imposed on Indemnitees as a consequence of receiving payment under this Section 14.13.
 
14.14                                            LIMITATION ON DAMAGES.
 
(A)                                       Company and Contractor mutually waive and release to the fullest extent permitted by applicable law, all of the following Claims for damages arising out of this Contract, whether such Claims are made in connection with an indemnity specified in this Section 14, a breach of any obligation under this Contract or otherwise, except for Claims arising from the obligation of a Party to indemnify the other Party for third party Claims:
 
(1)         Indirect or consequential loss, including:
 
(a)   Loss of expected production, including production of petroleum or petroleum products.
 
(b)   Loss of prospective economic advantage or benefit.
 
(c)   Loss of business opportunity.
 
(d)   Loss of revenue.
 
(e)   Loss of expected savings.
 
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(f)    Loss of business (including loss or reduction of goodwill) and damage to reputation.
 
(g)   Loss of spread costs for third-party supplied items or services.
 
(2)                       Punitive or exemplary damages.
 
(3)                       Lost profits (whether direct, indirect, anticipated or otherwise).
 
14.15                                            APPLICATION OF RELEASE AND INDEMNITY OBLIGATIONS; EXCLUSION FOR GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.
 
(A)                                       The release and indemnity obligations set out in this Contract apply regardless of the active, passive, contributory or sole or concurrent negligence, strict liability, unseaworthiness, pre-existing conditions, and other fault of any Person indemnified and regardless of whether liability of any kind is imposed or sought to be imposed on any person indemnified, except as provided otherwise in any release or indemnity obligations in this Contract or in Section 14.15(B).
 
(B)                                         The release and indemnity obligations of Contractor and/or Company in this Contract do not apply to the extent the death, illness, injury, damage or loss in relation to which a Claim is made is the result of the gross negligence or willful misconduct of the Person seeking indemnity or release.
 
(C)                                         Any Dispute regarding the application of the exclusions provided in Section 14.15(B) will be resolved in accordance with Section 21 except that Section 21.6(H) is modified so that the non-prevailing Party pays all arbitration fees and costs as well as all of the prevailing Party’s costs of conducting the arbitration on that issue, including the costs of legal representation, depositions, witnesses and the time of management and other personnel engaged in relation to that issue.
 
14.16                                            DEFENSE OF CLAIMS.
 
(A)                                        Contractor shall, at its sole cost and expense, be responsible for Defense Costs relative to Claims which may be brought against it or against Indemnitees for Claims for which Contractor wholly releases and/or indemnifies Indemnitees. Contractor shall accept and initiate such defense within thirty (30) days of written request by Company.
 
(B)                                        Company shall, at its sole cost and expense, be responsible for Defense Costs relative to Claims which may be brought against it or
 
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Contractor Group for Claims for which Company wholly releases and/or indemnifies Contractor Group. Company shall accept and initiate such defense within thirty (30) days of written request by Contractor.
 
(C)                                      In instances where a Party’s liability is limited or a Party’s release, defense and indemnity obligations are limited to a certain amount, the following provisions shall govern:
 
(1)                           The Party having the initial monetary exposure for any settlement or judgment (“Primary Party”) shall, at its sole cost and expense, be responsible for Defense Costs relative to Claims brought against it and the other Party (“Secondary Party”). The Secondary Party shall have the right to approve the defense counsel chosen by the Primary Party, such approval not to be unreasonably withheld.
 
(2)                           The Primary Party may settle a Claim for an amount within its indemnity obligation without first obtaining consent from the Secondary Party. The Primary Party may not settle a Claim for an amount which would obligate the Secondary Party to pay any monetary amount without prior written consent of the Secondary Party to such settlement.
 
(3)                           Defense Costs shall be borne by the Parties in proportion to their respective obligation to contribute to any settlement or judgment related to the underlying Claim. The Primary Party shall bear all Defense Costs until such time as a settlement is finalized or judgment is rendered, with the reconciliation between the Parties being conducted thereafter.
 
(4)                           Notwithstanding any other provision herein, any Party, at its sole cost and expense, may be represented or defended by separately retained counsel if it so desires upon the inception of a Claim.
 
(D)                                      Subject to the provisions of Section 14.16(C), Contractor shall promptly pay:
 
(1)                           To any Indemnitee all Defense Costs incurred by such Indemnitee resulting directly from any Claim for which Contractor is obligated to release, defend and/or indemnify such Indemnitee.
 
(2)                           Exclusive of Defense Costs incurred in connection with arbitration under Section 21.2, Indemnitees’ Defense Costs incurred in enforcing the provisions of this Contract, or in any legal action in which Company or any Indemnitee prevails, in whole or in part, against Contractor based on the breach of this Contract or to enforce an arbitration award.
 
(E)                                        Subject to the provisions of Section 14.16(C), Company shall promptly pay:
 
(1)                           To a member of Contractor Group all Defense Costs incurred by such member of the Contractor Group resulting directly
 
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from any Claim for which Company is obligated to release, defend and/or indemnify Contractor Group.
 
(2)                                Exclusive of Defense Costs incurred in connection with arbitration under Section 21.2, a member of Contractor Group’s Defense Costs incurred in enforcing the provisions of this Contract, or in any legal action in which the member of Contractor Group prevails, in whole or in part, against Company based on the breach of this Contract or to enforce an arbitration award.
 
(F)                                As used in this Section 14.16, “Defense Costs” includes but is not limited to, attorneys’ fees, court costs, expert fees and mediation and arbitration expenses. Defense Costs as used herein do not include costs of mediation and arbitration incurred by the Parties under Section 21.2.
 
14.17                DURATION OF INDEMNITY, RELEASE AND DEFENSE OBLIGATIONS.
 
(A)                              The release, defense and indemnity obligations in this Contract, including those contained in this Section 14 shall be effective as of the Effective Date of this Contract and shall remain in effect until termination.
 
(B)                              Notwithstanding the provisions of Section 14.17(A), it is understood and agreed that the release, defense and indemnity obligations in this Contract shall continue to be in effect during:
 
(1)                                suspension of the Services;
 
(2)                                the period between termination of the Contract under Section 3.4(B) and reinstatement of the Contract under Section 3.8; and
 
(3)                                Company’s taking over the Drilling Unit pursuant to Section 2.11.
 
(C)                              Notwithstanding the provisions of Section 14.17(A), the release, defense and indemnity obligations in this Contract shall continue to be in effect after termination of the Contract for:
 
(1)                                Claims arising during the Contract regardless of whether such claims are initiated during the Contract or after the Contract has been terminated; or
 
(2)                                Claims arising during salvage operations under Section 2.12.
 
15.      MUTUAL RELEASE AND INDEMNITY BETWEEN CONTRACTOR AND RELEASED CONTRACTORS; INSURANCE.
 
15.1                         DEFINITION OF RELEASED CONTRACTOR. “Released Contractor” means a contractor or subcontractor of any tier (other

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than Contractor or its subcontractors) that has entered into a contract with Company (either before or after the Effective Date) that includes, or is supplemented by, a separate agreement that includes, release, defense and indemnity provisions that are substantially similar to those set out in this Section 15 or are in any other form or wording, so long as the substantive nature of the provisions is similar to this Section 15.
 
If a contractor or subcontractor of any tier of Company does not qualify as a Released Contractor, such contractor or subcontractor of Company shall be included as a member of the Company Group.
 
In the event that Company engages the services of another contractor or subcontractor of any tier for work to be performed on the Drilling Unit and such entity presents itself at the Drilling Unit and is unable to verify its status as a Released Contractor, Contractor may deny such contractor/subcontractor access to the Drilling Unit without recourse. If Company then directs Contractor to permit such contractor/subcontractor to board the Drilling Unit, any such contractor/subcontractor that does not qualify as a Released Contractor shall be included as a member of Company Group.
 
Any release, indemnity, defense or insurance protection owed to Contractor or any member of Contractor Group by a Released Contractor shall be primary to any indemnity obligation owed by Company, and any liability of Company shall be secondary.
 
15.2                         DEFINITION OF RELEASED CONTRACTOR GROUP.  “Released Contractor Group” means a Released Contractor and any subcontractor (of every tier) that the Released Contractor engages to provide services or work or equipment under the contract referred to in Section 15.1.
 
15.3                         RELEASE, DEFENSE AND INDEMNITY OBLIGATIONS.
 
(A)               Contractor defends and indemnifies each member of each Released Contractor Group from any Claim for injury to or death of a member of Contractor Group where the injury or death directly or indirectly arises out of performance of this Contract or the Released Contractor’s contract referred to in Section 15.1.
 
(B)                 Contractor releases, and defends and indemnifies, each member of a Released Contractor Group from any Claim by Contractor Group for damage to or loss (including the cost of removal of wreckage) of Contractor Group’s Property, where the damage or loss arises out of performance of this Contract or the Released Contractor’s contract referred to in Section 15.1.

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15.4                         APPLICATION OF RELEASE AND INDEMNITY OBLIGATIONS; EXCLUSION FOR GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.
 
(A)               The release, defense, and indemnity obligations set out in this Section 15 apply regardless of the active, passive, contributory or sole or concurrent negligence, strict liability, unseaworthiness, preexisting conditions, and other fault of any Person indemnified and regardless whether liability of any kind is imposed or sought to be imposed on any person indemnified, except as provided in Section I4.15(B).
 
(B)                 The release and indemnity obligations set out in this Section 15 do not apply to the extent the death, illness, injury, damage or loss in relation to which a Claim is made is the result of the gross negligence or willful misconduct of the Person seeking indemnity or release.
 
15.5                         INSURANCE. Contractor agrees that all insurance benefits owed to Indemnitees under Section 16 shall also extend each member of a Released Contractor Group to the extent such Released Contractor has extended similar benefits to Contractor Group.
 
15.6                         SUBCONTRACT REQUIREMENTS.
 
Contractor shall include a provision substantially similar to this Section 15 in its subcontracts with Subcontractors whereby Subcontractors assume similar release, defense and indemnity obligations in favor of each member of a Released Contractor Group.
 
16.      INSURANCE
 
16.1                         Effect of Insurance on Contractor’s Liability and Indemnity Obligations.  Neither the minimum policy limits of insurance required of Contractor under this Section 16 nor the actual amounts of insurance maintained by Contractor under its insurance program limit or reduce Contractor’s liability and indemnity obligations in this Contract.
 
16.2                         Insurance Required of Contractor. Contractor shall maintain the following insurance and all other insurance required by applicable law:
 
(A)               Workers’ Compensation Insurance as prescribed by applicable laws where the Services are performed and, if applicable, the states, provinces and/or countries of residence of Contractor Group personnel performing the Services including Alternate Employer and Voluntary Compensation endorsement, if applicable, and coverage under the Longshoremens’ and Harbor Worker’s Compensation Act, the Jones Act, Death on the High Seas Act and the Outer Continental Shelf Lands Act, if applicable, with coverage amended to provide that a claim In Rem shall be treated as a claim against Contractor. Contractor shall maintain
 
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Employer’s Liability Insurance and maritime Employer’s Liability with policy limits of not less than US$1,000,000 per occurrence, which insurance may be maintained under Section 16.2(B) or 16.2(D)(2).
 
(B)                 Commercial General Liability (Bodily Injury and Property Damage) Insurance, including the following supplemental coverages: Contractual Liability to cover the liabilities assumed in this Contract; Products and Completed Operations; Explosion, Collapse and Underground Hazards; and Sudden and Accidental Pollution. The policy territory coverage must include all areas where the Services are to be performed.  The policy limits must not be less than US$10,000,000 combined single limit per occurrence or its Currency equivalent combined single limit per occurrence.
 
(C)                 Automobile Bodily Injury and Property Damage Liability Insurance extending to all vehicles provided by Contractor in the performance of the Services. The policy limits for this insurance must be the higher of the amount required by applicable law or US$1,000,000 combined single limit per occurrence or its Currency equivalent combined single limit per occurrence.
 
(D)                Marine Insurance. Contractor shall maintain or require the owners of the Drilling Unit, if different from Contractor, to maintain:
 
(1)                                 Full Form Hull and Machinery insurance, including terrorism, sabotage and war coverage, Removal of Wreck and Debris as required by Section 2.14(A) and Collision Liability, with the sistership clause unamended, with limits of liability at least equal to $200,000,000.00 and with navigational limits adequate for Contractor and /or Subcontractors to perform the Work and Services hereunder. Said policy shall be endorsed to provide that additional assureds may, but shall not be obligated to, sue and labor. This insurance may exclude coverage for Collision Liability and Tower’s Liability, provided such risks are covered under the Full Form Protection and Indemnity Liability insurance as described below.
 
(2)                                 Full Form Protection and Indemnity insurance on the Drilling Unit including, but not limited to, providing coverage for injuries to or death of masters, mates and crews of vessels with limits equal to the replacement cost value of the Drilling Unit but not less than US$25,000,000 combined single limit per occurrence or its Currency equivalent per occurrence, including insurance for contractual removal of wreck and/or debris, and liability for seepage, pollution, containment and cleanup for all drilling units, vessels and barges used in the performance of the Services. There shall be no exclusion for war, sabotage and terrorism. This insurance shall be equivalent to Form SP-23, including coverage for crew, Collision and Liability (with the sistership clause unamended), sue and labor and salvage charges, and Contractual Liability. The policy territory coverage must include all areas where the Drilling Unit is used. Coverage shall be amended to
 
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provide that any claim In Rem shall be treated as a claim against Contractor.
 
(3)                                 All policies under this Sections I6.2(D) shall be endorsed, to the extent of the risks and liabilities assumed by Contractor under this Contract, as follows
 
(a)               to provide full coverage to each indemnitee as additional insured without limiting coverage to liability “as owner of the vessel” and to delete any “as owner” clause or any other language purporting to limit coverage to liability of an insured “as owner of the vessel”; and
 
(b)              to delete any language limiting coverage for any Indemnitee in the event of the applicability of any law allowing limitation of liability.
 
(E)                  Aircraft Liability Insurance. If performance of the Services requires Contractor to provide aircraft (including helicopters), Contractor shall require owners or providers of aircraft to maintain Aircraft Liability (Bodily Injury (including liability to passengers) and Property Damage) Insurance with a combined single limit of not less than US$25,000,000, to be met with any combination of primary or excess coverage.
 
16.3                         Policy Endorsements.
 
(A)               Contractor shall, or shall cause its insurer to, provide Company with thirty days notice before canceling or making a material change to an insurance policy required by Section 16.2.
 
(B)                 Waivers of subrogation in all of Contractors insurance policies to the extent of the risks and liabilities assumed by Contractor under this Contract.
 
(C)                 The insurance required in Sections 16.2(B), I6.2(C), and 16.2(D) must include all of the following:
 
(1)                                 The Indemnitees shall be named as additional insureds to the extent of the liabilities assumed by Contractor under this Contract, without restriction as to sole or concurrent negligence, vicarious liability, or completed operations. The coverage provided to Indemnitees as additional insureds must expressly include liability imposed or sought to be imposed upon Indemnitees for the sole or concurrent fault or negligence of Indemnitees to the extent that Contractor has assumed such liabilities of Indemnitees under the Contract.
 
(2)                                 A provision that the insurance is primary with respect to all insureds, including additional insureds, and that no other insurance carried by lndemnitees will be considered as contributory insurance for any loss to
 
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the extent of the risks and liabilities assumed by Contractor under this Contract.
 
(3)                                 A cross liability or severability of interest clause which has the effect of insuring that each insured (including additional insureds) is covered as a separate insured.
 
16.4                         Evidence of Insurance.  Before performing any of the Services, Contractor shall provide Company with certificates or other documentary evidence satisfactory to Company of the insurance and endorsements required under this Section 16. Company’s acceptance of this certificate does not constitute a waiver, release or modification of any of the insurance coverages and endorsements required under this Section 16. Contractor shall provide copies of insurance policies required under this Contract if requested by Company. Contractor acknowledges that failure to provide a certificate or a copy of a policy or other evidence as required by this Section 16.4 may lead to non-payment of Contractor’s invoices or termination of this Contract.
 
16.5                         Deductibles or Self-Insured Retentions.  Contractor is solely responsible for payment of all deductibles (without prejudice to Company’s obligations to reimburse Contractor under Section 14) or self-insured retentions that are applicable to any Claims made against Indemnitees covered by Contractor’s insurance policies. The level of these deductibles or retentions must be reasonable and compatible with that expected of a pruden contractor in similar circumstances.
 
16.6                         Waiver of Subrogation for Contractor’s Property Damage Insurance.  Contractor shall obtain a written waiver of subrogation in favor of Indemnitees from its insurers who provide property damage insurance with respect to the Drilling Unit and any other Contractor Property used in the performance of the Services.
 
16.7                         Insurance Required from Subcontractors.  Without limiting Contractor’s liability under Section 14, Contractor shall require Subcontractors, if any, to waive subrogation and name the Indemnitees as additional insureds and be primary under the insurance carried by Subcontractors, all as required by this Contract with respect to the Services performed by Subcontractors and to the extent of the liabilities assumed by Contractor and/or its Subcontractors under this Contract. Any deficiencies in such coverage shall be the sole responsibility of Contractor.
 
16.8                         Insurance Provided by Company.  Excluding Hull & Machinery and Protection and Indemnity coverage, Company shall provide a full range of insurance coverages which are at least of the range and scope provided by Contractor as set forth in Section 16. Such insurance procured by Company shall also contain all relevant provisions as required of Contactor including, but not limited to, and only to the extent of the risks and liabilities assumed by Company, waivers of subrogation, in favor of and naming of Contractor Group as additional insureds to the extent of the liabilities assumed by Company in the
 
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Contract; notice of cancellation or material change; Company insurance will be primary respecting Contractor Group regarding matters where Company has agreed to indemnify Contractor Group in the Contract; and cross liability provisions.
 
17.      CONTRACT INFORMATION
 
17.1                         Confidentiality of Contract Information.Contractor shall treat Contract Information as valuable, proprietary and confidential information and shall not disclose, and shall ensure that all members of Contractor Group do not disclose, any Contract Information to any other Person without the prior written consent of Company, except as permitted in Section 17.2.
 
17.2                         Permitted Disclosure.Contractor may disclose (and may permit other members of Contractor Group to disclose) Contract Information to any of the following recipients who are bound by confidentiality and use obligations at least as stringent to those in this Section 17:
 
(A)               To Subcontractors and employees of Contractor or Subcontractors, but only to the extent that those Persons need to know the Contract Information for the performance of the Services.
 
(B)                 To professional advisors of Contractor or Subcontractors, but only to the extent necessary for the provision of professional advice needed by Contractor or Subcontractors for the performance of the Services or by Contractor in relation to this Contract.
 
17.3                         Required Disclosure.If Contractor or any other Person who receives Contract Information (directly or indirectly) through Contractor is required by law or by lawful order of any administrative or judicial proceeding to disclose any Contract Information, or any Person applies for an order against them for the disclosure of Contract Information, Contractor shall provide Company with prompt notice of this requirement or application so that Company may seek a protective order. If a protective order or other remedy is not obtained, Contractor will furnish, and will ensure that the other Person required to disclose Contract Information will furnish, only that portion of the Contract Information which, in the reasonable opinion of Company, is required to be disclosed.
 
17.4                         Use of Contract Information.Contractor shall use, and shall ensure that all other Persons who receive Contract Information (directly or indirectly) through Contractor use, Contract Information (including Contract Information which is learned, discovered, developed or created by Contractor Group) only for the purpose of providing the Services. Contractor shall not, and shall ensure that all other members of Contractor Group do not, disassemble, decompile or otherwise reverse engineer or attempt to derive the composition or underlying information, structure or ideas of any Contract Information, except to the extent required to provide the Services, without the prior written consent of Company. Contractor shall abide by all instructions given or restrictions stipulated by Company with respect to Contract Information.
 
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17.5                         Ownership of Property Rights.All intellectual property rights and all other property and other rights in relation to Contract Information are owned by Company. To the extent that Contract Information is discovered, developed or created by Contractor or other members of Contractor Group and copyright or intellectual property rights arise in relation to that Contract Information, those works and rights are not considered work for hire under this Contract and are the exclusive property of Contractor. To the extent that Contract Information is jointly discovered, developed or created by i) Contractor or other members of Contractor Group and ii) Company or other members of Company Group and copyright or intellectual property rights arise in relation to that Contract Information, those works and rights are considered jointly owned by both Contractor and Company. If Contractor is not able to provide the products and/or perform the Services required under this Contract resulting in the termination of this Contract, Contractor grants to Company a royalty-free, non-exclusive, non-transferable license to all such Contractor-owned copyrights or intellectual property rights to use, make or have made on its behalf for the purposes of the operation, installation, maintenance and repair of the products and services covered under this Contract, if such Contractor-owned copyrights or intellectual property rights are required to enable Company to complete Company’s operations contemplated hereunder.
 
17.6                         Equitable Relief.Contractor acknowledges and agrees that due to the unique nature of the Contract Information there may be no adequate remedy at law for any breach of the obligations set out in this Section 17, and that any breach of these obligations may allow Contractor or another Person to compete unfairly with Company resulting in irreparable harm to Company. Accordingly, Contractor agrees that upon a breach (or threat of a breach), Company is entitled to immediate equitable relief, including a restraining order and preliminary injunction, and Company may seek indemnification from Contractor for any loss or harm in connection with any breach or enforcement of Contractor’s obligations provided in this Section 17 or for the unauthorized use or release of Contract Information. Contractor shall notify Company immediately upon the occurrence of any unauthorized release of Contract Information or other breach of this Section 17.
 
17.7                         No License.Other than the rights to use the Contract Information to perform the Services required to be performed under this Contract and except as provided in Section 17.5, nothing in this Contract shall be construed as conferring to Contractor or Company by implication, estoppel, or otherwise, any right, title or interest in, or any license under, any patent, patent application, trade secret, or other intellectual property now or subsequently owned by Company or Contractor as appropriate or their Affiliates. Any cost that Contractor must bear to license or otherwise access any intellectual property right required for the performance of the Services is included in Contractor’s compensation unless otherwise provided in this Contract.
 
17.8                         Return of Contract Information.All copies, extracts, drawings and other materials or Records that, in whole or in part, contain, incorporate, embody or reflect any Contract Information must be returned or delivered to Company or
 
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destroyed within five business days of the first to occur of termination of this Contract or completion of the provision of the Services, if such return or destruction is requested by Company in writing. If Contract Information has been copied onto computer systems or other data storage systems used by Contractor or other members of Contractor Group, Contractor’s obligations under this Section 17.8 are satisfied if all data recordings of Contract Information (including back-up data) are destroyed in a manner which makes it unrecoverable, provided that such data is kept confidential in accordance with this Contract for so long as that Contract Information is retained.
 
18.      BUSINESS RELATIONSHIP
 
18.1                         Contract for Services.Thisis a Contract for Services and is not a charter or lease of Contractor’s equipment.
 
18.2                         Independent Contractor.The Services arc provided by Contractor as an independent contractor, and Contractor and the members of Contractor Group arc not employees, agents or representatives of Company or Company Group. Company shall have no direction or control of Contractor Group except in the results to be obtained.
 
18.3                         Contractor’s Responsibility for Obligations of the Contractor Group.Contractor is responsible for all legal and contractual obligations of all members of Contractor Group that arise out of the performance of the Services, including those imposed by Country or any of its political subdivisions. The requirements of this Contract apply to Subcontractors’ services, property and personnel as if they were Contractor’s services, property and personnel. Contractor is not relieved from any liability or obligation under this Contract as a result of Contractor’s use of Subcontractors or Company’s approval of Subcontractors.
 
18.4                         Control over Performance.As an independent contractor, Contractor has complete control, supervision and direction over its equipment and personnel and over the manner and method of the performance of the Services. Any instructions or directions of any kind given by Company do not relieve Contractor of its duties and obligations as an independent contractor.
 
19.      ASSIGNMENT
 
19.1                         Assignment by Contractor.Contractor may assign this Contract to an Affiliate or subsidiary and shall provide written notice thereof to Company. Contractor may not assign or transfer in whole or part its rights and obligations under this Contract to any other entity or, in the event of a reorganization, merger, consolidation or asset sale, to any other entity which assumes the assets of Contractor under that reorganization, merger, consolidation or asset sale without the prior written consent of Company. Any attempted assignment or transfer in breach of this obligation is void as between Company and Contractor.
 
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19.2                         Assignment by Company.Company may assign or transfer all or part of its rights or obligations under this Contract as follows:
 
(A)               without Contractor’s consent to an Affiliate of Company, or a Joint Interest Owner;
 
(B)                 without Contractor’s consent to any other Person in the event of a reorganization, merger, consolidation or asset sale, to any other entity which assumes the assets of Company under that reorganization, merger, consolidation or asset sale;
 
(C)                 without Contractor’s consent to any other Person if Company agrees to remain liable for the performance of all obligations by such assignee or transferee; or
 
(D)                to any other Person with Contractor’s consent, which consent shall not be unreasonably withheld.
 
19.3                         Successors and Assigns.This Contract upon assignment will be binding and will insure to the benefit and obligation of the successors and assigns of the assigning Party.
 
20. FORCE MAJEURE
 
20.1                         Definition of Force Majeure Event.“Force Majeure Event” means any of the events or circumstances described in Section 20.1(A) that are beyond the control of an affected Party and which prevents the performance of any of the affected Party’s obligations under this Contract after that Party has taken every reasonable step, including reasonable expenditures of money, to remedy the impact of the event:
 
(A)               Events or circumstances that may give rise to a Force Majeure Event are limited to the following:
 
(1)                                 Earthquakes, hurricanes, fires, storms, tidal waves, tsunami, floods or other physical natural disasters, exclusive of adverse sea, loop, eddy or other adverse current conditions or other adverse weather conditions.
 
(2)                                 Acts of war (whether declared or undeclared), terrorism, riot, civil war, blockade, insurrection or civil disturbances.
 
(3)                                 Acts of a governmental entity, agency or other local authority that prevent or make unlawful a Party’s performance under this Contract.
 
(4)                                 Strikes or labor disputes at the national level, but excluding any strike or dispute which is specific to the performance of the Services under this Contract.
 
(B)                 The Parties confirm that Force Majeure Events do not include any of the following events or circumstances:
 
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(1)       The mere shortage of or inability to obtain labor, equipment, materials or transportation which is not itself caused by a Force Majeure Event.
 
(2)       The insolvency or change in economic circumstances of the affected Party.
 
(3)       Change in market conditions.
 
20.2             Excuse of Performance due to a Force Majeure Event.Subject to compliance with Section 20.3, neither Party is liable for any delay in performing or failure to perform its obligations under this Contract (excluding release, indemnity and defense obligations and the obligation to pay undisputed invoices) if and to the extent that the delay or failure is caused by a Force Majeure Event. A Party is excused from its performance obligations that are prevented by a Force Majeure Event for as long as the Force Majeure Event continues.
 
20.3             Notice and Mitigation.If a Party seeks relief from its obligations to perform under this Contract under Section 20.1, it shall:
 
(A)         Give prompt notice to the other Party, which must include all of the following information:
 
(1)       The event that the Party considers constitutes a Force Majeure Event and its likely effect on the performance of obligations under this Contract.
 
(2)       A good faith estimate of the duration of the Force Majeure Event.
 
(3)       The actions being taken (or proposed to be taken) to satisfy Section 20.3(B).
 
(B)          Make all reasonable efforts, including expenditure of money, to overcome the Force Majeure Event and to mitigate its effects. Should a Force Majeure Event relate to a specific Area of Operations, Kosmos and Noble will make all reasonable efforts to alter the sequence of the initial Operating Term segments referred to in Section 3.2(A) to mitigate such Force Majeure Event.
 
(C)          If the Force Majeure Event continues, give periodic notices in accordance with Section 20.3(A), with a frequency as directed by Company Representative.
 
(D)         Give the other Party prompt notice of the conclusion of the Force Majeure Event and resume performance of the Services as soon as reasonably possible after its conclusion.
 
20.4             Termination of the Contract due to a Force Majeure Event.This Contract may be terminated due to a Force Majeure Event in accordance with Section 3.3(C).
 
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21.     GOVERNING LAW AND RESOLUTION OF DISPUTES
 
21.1             Governing Law.This Contract is governed by and interpreted under the laws of England and Wales, without regard to its choice of law rules. The United Nations Convention on Contracts for the International Sale of Goods, 1980 (known as “the Vienna Sales Convention”) does not apply to this Contract.
 
21.2             Resolution of Disputes.The Parties shall exclusively and finally resolve any Dispute between them using direct negotiations, mediation and arbitration as set out in Section 21, except as permitted in Section 17.6.
 
21.3             Direct Negotiations.If a Dispute arises, a Party shall initiate the resolution process by giving notice setting out in writing and in detail the issues in Dispute and the value of the Claim to the other Party. A meeting between the Parties, attended by individuals with decision-making authority, must take place within thirty days from the date the notice was sent in an attempt to resolve the Dispute through direct negotiations.
 
21.4             Mediation.If the Dispute cannot be settled by direct negotiations within thirty days of initiation of the resolution process, either Party may initiate mediation by giving notice to the other Party. The place of mediation shall be London, England. Each Party to the mediation shall pay one-half the cost of the mediator.
 
21.5             Arbitration.If the Dispute is not resolved by mediation within thirty days from the date of the notice requiring mediation, or if the Dispute is unresolved within sixty days from the date of the notice requiring direct negotiations, then the Dispute shall be finally settled by binding arbitration and either Party may initiate such arbitration by giving notice to the other Party. The arbitration shall be conducted in accordance with the following arbitration rules (as then in effect): Rules of Arbitration of the International Chamber of Commerce (ICC) except to the extent of conflicts between those rules and the provisions of this Contract, in which event the provisions of this Contract prevail. The place of arbitration shall be London, England.
 
21.6             Additional Arbitration Provisions.The following provisions shall apply to any arbitration proceedings commenced pursuant to Section 21.5:
 
(A)         The number of arbitrators shall be one if the monetary value of the Dispute is USD$5,000,000 or less. The number of arbitrators shall be three if the monetary value is greater than USD$5,000,000. Each Party shall select one (1) arbitrator and these two (2) arbitrators shally jointly select the third who shall serve as the presiding arbitrator.
 
(B)          If the arbitration is to be conducted by three arbitrators and there are only two parties to the Dispute, then each party to the Dispute shall appoint one arbitrator within thirty (30) Days of the filing of the arbitration, and the two arbitrators so appointed shall select the presiding arbitrator within thirty (30) Days after the latter of the two arbitrators has been appointed by the parties to the Dispute. If a
 
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party to the Dispute fails to appoint its party-appointed arbitrator or if the two party-appointed arbitrators cannot reach an agreement on the presiding arbitrator within the applicable time period, then the ICC shall appoint the remainder of the three arbitrators not yet appointed.
 
(C)          If the arbitration is to be conducted by three arbitrators and there are more than two parties to the Dispute, then within thirty (30) Days of the filing of the arbitration, all claimants shall jointly appoint one arbitrator and all respondents shall jointly appoint one arbitrator, and the two arbitrators so appointed shall select the presiding arbitrator within thirty (30) Days after the latter of the two arbitrators has been appointed by the parties to the Dispute. If either all claimants or all respondents fail to make a joint appointment of an arbitrator or if the party-appointed arbitrators cannot reach an agreement on the presiding arbitrator within the applicable time period, then the ICC shall appoint the remainder of the three arbitrators not yet appointed.
 
(D)         The arbitrator or arbitrators must be fluent in the English language and the language of the arbitral proceeding shall be in English.
 
(E)          The arbitrator or arbitrators must remain neutral, impartial and independent regarding the Dispute and the Parties. If the number of arbitrators to be appointed is one, that arbitrator or the presiding arbitrator if the arbitrators are three, must be a lawyer experienced in the resolution of disputes with experience relating to the issues in dispute.
 
(F)          A Party producing, submitting or offering any document which is not in the English language shall also provide an English translation of the document by a qualified, independent third party translator at that Party’s sole expense. If the testimony of a witness must be translated, the Party proffering the witness shall bear the cost of translation.
 
(G)          The Parties waive any Claim for, and the arbitrator has or arbitrators have no power to award, the damages waived and released under Section 14. The arbitrator has or arbitrators have no authority to appoint or retain expert witnesses for any purpose unless agreed to by the Parties. The arbitrator has or arbitrators have the power to rule on objections concerning jurisdiction, including the existence or validity of this arbitration clause and existence or the validity of this Contract.
 
(H)         All arbitration fees and costs (with the exception of translation costs as specified above) shall be borne equally regardless of which Party prevails. Each Party shall bear its own costs of legal representation and witness expenses.
 
(I)           The arbitrator is or arbitrators are authorized to take any interim measures as the arbitrator considers or arbitrators consider necessary, including the making of interim orders or awards or partial final awards. An interim order or award may be enforced in the same manner as a final award using the procedures specified below. Without limiting the generality of the foregoing, any Party to the Dispute may have recourse to and shall be bound by the Pre-arbitral Referee
 
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Procedure of the International Chamber of Commerce in accordance with its rules then in effect.
 
(J)           The arbitrator or arbitrators must render a reasoned award in writing. The award is final and binding.
 
(K)         The Dispute will be resolved as quickly as possible. The arbitrator’s or arbitrators’ award must be issued within three months from completion of the hearing, or as soon as possible thereafter.
 
21.7             Enforceability.
 
(A)         The Parties waive irrevocably their right to any form of appeal, review or recourse to any court or other judicial authority, to the extent that such waiver may be validly made.
 
(B)          Proceedings to enforce judgment entered on an award may be brought in any court having jurisdiction over the person or assets of the non-prevailing Party. The prevailing Party may seek, in any court having jurisdiction, judicial recognition of the award, or order of enforcement or any other order or decree that is necessary to give full effect to the award.
 
21.8             Confidentiality.
 
(A)         The Parties agree that any Dispute and any negotiations, mediation and arbitration proceedings between the Parties in relation to any Dispute shall be confidential and will not be disclosed to any third party.
 
(B)          The Parties further agree that any information, documents or materials produced for the purposes of, or used in, negotiations, mediation or arbitration of any Dispute shall be confidential and will not be disclosed to any third party.
 
(C)          Without prejudice to the foregoing, the Parties agree that disclosure may be made:
 
(1)       In order to enforce any of the provisions of this Contract including without limitation, the Parties agreement to arbitrate, any arbitration order or award and any court judgment.
 
(2)       To the auditors, legal advisers, insurers and Affiliates of that Party to whom the confidentiality obligations set out in this Contract shall extend.
 
(3)       Where that Party is under a legal or regulatory obligation to make such disclosure, but limited to the extent of that legal obligation.
 
(4)       With the prior written consent of the other Party.
 
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22.     NOTICES, REPRESENTATIVES AND CONTACT INFORMATION
 
22.1             Notices.
 
(A)         All notices required or permitted under this Contract must be in writing and delivered by mail (postage prepaid) or by hand delivery to the address of the receiving Party set out in the signature page to this Contract. Notice may also be delivered by facsimile sent to the facsimile number of the receiving Party set out in the signature page to this Contract provided that the original notice is promptly sent to the recipient by mail (postage prepaid) or by hand delivery. Notices sent by email are ineffective.
 
(B)          Notices are effective when received by the recipient during the recipient’s regular business hours.
 
(C)          Notices which do not comply with the requirements of this Contract are ineffective, and do not impart actual or any other kind of notice.
 
22.2             Representatives and Contact Information.
 
(A)         The representatives and contact information of each Party are as set out in the Exhibit A — Scope of Work.
 
(B)          Each Party may change its representative or contact information by giving notice to the other Party. If a notice is given under this Section 22.2(B), the replacement representative or contact information which is set out in the notice replaces the representative or contact information as set out in the Exhibit A — Scope of Work.
 
23.     PUBLIC ANNOUNCEMENTS
 
Contractor shall not issue any public announcement or statement concerning this Contract without obtaining Company’s prior written consent except for public disclosures which may be legally required by any relevant stock exchange authority.
 
24.     THIRD PARTY RIGHTS
 
24.1             Except as otherwise provided in Section 24.2, the Parties intend that no provision of this Contract shall, by virture of the Contracts (Rights of Third Parties) Act 1999 (the “Act”) confer any benefit on, or be enforceable by, any Person who is not a Party to this Contract, and no Person who is not a party to this Contract has any rights under this Contract or may enforce any provision in this Contract, except as permitted in Section 24.2.
 
24.2             To the fullest extent permitted by law, each member of Company Group, Contractor Group, or a Released Contractor Group has the right to enforce benefits provided by this Contract to such member.
 
25.     GENERAL PROVISIONS
 
25.1             Prior Agreements.This Contract comprises the complete and exclusive agreement between the Parties regarding the subject matter of this Contract, and
 
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supersedes all oral and written communications, negotiations, representations, or agreements in relation to that subject matter made or entered into before the Effective Date.
 
25.2             Amendment.No amendment to this Contract is effective unless made in writing and signed by authorized representatives of both Parties.
 
25.3             Waiver.Company’s or Contractor’s failure to pursue remedies for breach of this Contract, or payment by Company of invoices, does not constitute a waiver by Company or Contractor (as applicable) of any breach of this Contract by Contractor/Company or raise any defeuse against Claims against Contractor or Company for breach of this Contract. The waiver or failure to require the performance of any covenant or obligation contained in this Contract or pursue remedies for breach of this Contract does not waive a later breach of that covenant or obligation.
 
25.4             Severability.Each provision of this Contract is severable and if any provision is determined to be invalid, unenforceable or illegal under any existing or future law by a court, arbitrator of competent jurisdiction or by operation of any applicable law, this invalidity, unenforceability or illegality does not impair the operation of or affect those portions of this Contract that are valid, enforceable and legal.
 
25.5             Survival.Despite completion of the Services or termination of this Contract for any reason, all provisions in this Contract containing representations and warranties, and all provisions relating to audit, confidentiality, insurance, disclaimer of certain remedies, ownership or use or return of Contract Information, retention and inspection of Records, dispute resolution and governing law, and all Claims which arose prior to completion or termination, survive indefinitely until, by their respective terms, they are no longer operative or are otherwise limited by an applicable statute of limitations.
 
25.6             Time of the Essence.Contractor and Company acknowledge that time is of the essence with respect to this Contract. By executing this Contract, Contractor confirms that the timeframes for performing the Services under this Contract are reasonable for all periods of time provided in this Contract.
 
25.7             Counterparts.  This Contract may be executed in any number of counterparts, each of which will be deemed an original of this Contract, and which together will constitute one and the same instrument; provided that neither Party will be bound to this Contract unless and until both Parties have executed a counterpart.
 
25.8             Drafting.Preparation of this Contract has been a joint effort of the Parties and the resulting Contract must not be construed more severely against one of the Parties than against the other.
 
25.9             Parent Company Guarantee.The Parties each agree to execute a Parent Company Guarantee in the applicable form attached hereto as Exhibit H.
 
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26.     CHANGE OF LOCALE FOR OPERATIONS
 
26.1             Company may request, and Contractor will reasonably consider, changing the locale of the Operations requiring a change in the Area of Operations and/or the Country provided:
 
(A)      that such change does not result in a breach of Contractor’s trading warranties with its insurance underwriters or violate the laws, rules and regulations applicable to Contractor or its Affiliates; and
 
(B)      that Contractor is able to obtain all insurance required by the Contract, and any other insurance typically carried by Contractor, for Operations in the new Area of Operations.
 
26.2             In conjunction with a request from Company for a change of locale for the Operations, Company and Contractor shall review the Scope of Work and its Attachments to determine if changes are needed due to:
 
(A)      changes in financial impact arising from the requested change in locale, which for the sake of clarity shall include the financial impact on Contractor (either increase or decrease) as regards differences in taxes, labor rates, operating costs, shore base office costs, Contractor’s corporate operating structure, agency fees, etc.;
 
(B)      a change in the demobilization point for the Drilling Unit;
 
(C)      changes in the terms of the Scope of Work and its Attachments appropriate for the new locale.
 
It is intended that the changes to the Scope of Work and its Attachments for the purposes of this Section 28 shall be structured such that Contractor’s financial situation should not be adversely affected nor advantaged by the change of locale.
 
26.3             Notwithstanding any other provision of this Contract, Contractor acknowledges that Noble or its Affiliate may elect to use the Drilling Unit in waters offshore Cameroon during the drilling segment(s) referenced in Section 3.2(A)(4), with such election to be made on or before October 01, 2010, and such a change in the Area of Operations/Country to include Cameroon is hereby authorized by Contractor, with any additional costs under Section 26.2 to be borne by Noble or its Affiliate.
 
26.4             Any mutually agreed changes shall be included in an amendment to this Contract, as mutually agreed by the Parties, prior to the start of Operations in the new locale.
 
26.5             The form of Contract may need to be varied as required under laws, rules, custom or practice in the new Country of Operations.
 
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Operations/Country to include Cameroon is hereby authorized by Contractor, with any additional costs under Section 26.2 to be borne by Noble or its Affiliate.
 
26.4             Any mutually agreed changes shall be included in an amendment to this Contract, as mutually agreed by the Parties, prior to the start of Operations in the new locale.
 
26..5            The form of Contract may need to be varied as required under laws, rules, custom or practice in the new Country of Operations.
 
IMPORTANT NOTICE: THIS CONTRACT CONTAINS PROVISIONS REGARDING INDEMNITIES AND WARRANTIES THAT EXPRESS THE AGREEMENT OF THE PARTIES CONCERNING CLAIMS ARISING OUT OF THIS CONTRACT.
 
The Parties have executed this Contract in duplicate as evidenced by the following signatures of authorized representatives of the Parties:

COMPANY:	 	CONTRACTOR:	
Kosmos Energy Ghana HC	 	Alpha Offshore Drilling Services Company	
 	 	 	
Signature:	/s/ Marvin Garrett	 	Signature:	/s/ A.H. Dyne	
 	 	 	 	 	
Name:	Marvin Garrett	 	Name:	A.H. Dyne	
Title:	Vice President	 	Title:	Director	
 	 	 	
ADDRESS FOR NOTICES TO KOSMOS:	 	ADDRESS FOR NOTICES TO ALPHA:	
 	 	 	
c/o 8401 N. Central Expressway, Suite 280	 	332A-11C, 11thFloor, Plaza Ampang City	
Dallas, Texas 75225	 	Jalan Ampang	
 	 	50450 Kuala Lumpur, MALAYSIA	
Attention: Marvin Garrett	 	Attention: Tony Dyne	
Facsimile: 214-363-9024	 	Facsimile: 603-4257-9208	
 	 	With Correspondence copied to :	
 	 	Name: Glen Kelley	
 	 	Fax: 1-281-578-3253	
COMPANY:	 	 	
 	 	 	
Noble Energy EG Ltd.	 	 	
Signature:	 	 	
/s/ David L. Stover	 	 	
Name: David L. Stover	 	 	
Title: Executive Vice President & COO	 	 	

 
ADDRESS FOR NOTICES TO NOBLE:	 	 	
 	 	 	
100 Glenborough Drive, Suite 100	 	 	
Houston, Texas 77067	 	 	
Attention: Ron Jordan	 	 	
Facsimile: 281-872-2511	 	 	

 
EXHIBIT A
 
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EXHIBIT A TO OFFSHORE DRILLING CONTRACT
SCOPE OF WORK
 
Company:	 	Contractor:	
 	 	 	
Kosmos Energy Ghana HC	 	Alpha Offshore Drilling Services Company	
&	 	 	
Noble Energy EG Ltd.	 	Contractor’s place of incorporation:	
 	 	Cayman Islands, BWI	
 	 	 	
Area of Operations:	Country:	 	Well Location(s):TBA	 	
Offshore Ghana and Equatorial Guinea	Ghana and Equatorial Guinea	 	 	
Company Representative:	 	Contractor Representative:	
For Kosmos:	 	 	
Name:	Marvin Garrett	 	Name:	Butch Darnell	
Email:	mgarrett@Kosmosenergy.com	 	Email:	bdarnell@atwd.com	
Phone:	972-739-7707	 	Phone:	TBA	
Fax:	214-363-9024	 	Fax:	TBA	
For Noble:	 	 	
Name:	Ron Jordan	 	With correspondence copied to:	
Email:	rjordan@nobleenergy.com	 	 	
Phone:	281-874-6718	 	Name:	Glen Kelley	
Fax:	281-872-2511	 	Email:	gkelley@atwd.com	
 	 	Phone:	1-281-749-7805	
 	 	Fax:	1-281-578-3253	

Name of Drilling Unit: Atwood Hunter
 
Mobilization origin point for the Drilling Unit per Sec 8.1(A): once the Drilling Unit has its last anchor bolstered at the preceding operator’s (Noble Energy, Inc. or its relevant Affiliate) last well location offshore Israel and the Drilling Unit is under tight tow and is one (1) nautical mile from that preceding location
 
Port of Entry for the Drilling Unit (if applicable): Company’s/Kosmos’ first well offshore Ghana, to be more fully-specified in writing prior to the Commencement Date
 
Mobilization delivery point for the Drilling Unit: Company’s/Kosmos’ first well offshore Ghana, to be more fully-specified in writing prior to the Commencement Date
 
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Demobilization point for the Drilling Unit per Sec 8.1(H)(1): one (1) nautical mile from the last well location of the Contract.
 
Party Responsible for providing permissions necessary to enter the Area of Operations to operate at the well location,per Section 2.3(B)(2):
 
Company:  x                                             Contractor:  o
 
·                 Initial Operating Term of the Contractper Section 3.2(A):
·                 1,240 days
·                 Number of wells to be drilled: Not Applicable
Estimated duration to drill such well(s): NA
 
Optional Extension of Initial Operating Term,per Section 3.2(B):
 
Applicable:  x                                      Not Applicable:  o
 
Option to extend the Contract,per Section 3.2(C):
 
Option Available:  x                             Not Available:  o
 
The option to extend the initial or extended Operating Term of the Contract for one (1) year may be agreed at rates and terms mutually agreeable to the Parties with written notice from Company prior to 1 October 2010.
 
Number of days after completion of the Services by which Drilling Unit must be removed to a minimum of one nautical mile from Company’s last well location in the Area of Operations , per Secs. 2.11 and 8.1(H): Zero days
 
Estimated Schedule for Inspection(s) of the Drilling Unit,as per Sec 6.2(E)(4):
 
Certification of Drilling Unit: Complete and permanent. Renewal not required
 
Structural Inspection of Drilling Unit: Next special survey hull due Aug. 2012
 
Estimated UWILD/Drydock Schedule of Drilling Unit: Due Sept. 2009
(Two inspections within first five years; no more than three years apart. These inspections shall be confirmed prior to Mobilization of the Drilling Unit)
 
No of days per contract year to effect classification and regulatory requirements and to survey the equipment per Section 6.2(E)(2): three and one-half (3.5) calendar days per contract year (i.e. 365 days from the Commencement Date)
 
Local HSE policy attached,per Sec. 5.2:
No additional requirements beyond those already appended.	 	Local Drug/Alcohol/ Search policy attached,per Sec. 5.2:
No additional requirements beyond those already appended.	
 
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Local Content and/or Workforce Nationalization requirements, as per Sec 6.1(G): Attachment A10	Port of Entry for Contractor’s Personnel,
per Sec 1.1 (if applicable):
For Kosmos: Accra
For Noble: Malabo	
 	 	 	
Contractor’s Personnel Rotation Schedule,per Sec. 6.1(F): TBA	 	No. of days notice required under Section 8.1(E)(4) for Contractor to remobilize its personnel: To be mutually agreed by the Parties	
 
No. of hours allowed per month to effect repairs and maintenance of surface equipment and/or Subsea Equipment at the Operating Rate shall be based on the provisions of Section 6.2(D)(3)   and 8.2.
 
Repairs Downtime and Maintenance Allowance:
 
All repairs and maintenance conducted shall be based on the provisions of Section 6.2(D)(3) and 8.2.
 
·                 Per Sec. 8.2(A)(1), 24 hours per month for surface equipment; after which compensation will revert to zero.
·                 Per Sec. 8.2(C)(1), 36 hours per month for Subsea Equipment; after which compensation will revert to zero.
 
Surface equipment and Subsea Equipment have the meanings defined in Section 8.2.
 
Force Majeure Event,per Sec. 3.3(C): 30 Days
 
Transportation arrangements for contractor’spersonnel, if different from those set forth in Section 6.1(E)(4): Not Applicable
 
95

 
The Drilling Unit, Ancillary Equipment and Personnel to be furnished by Contractor are detailed in the following Attachments:
 
Attachment Al – Drilling and Ancillary Equipment Specifications
Attachment A2 – Equipment, Supplies, Materials & Services to be Furnished by Company & Contractor
Attachment A3 – Personnel to be Furnished by Contractor
Attachment A4 – Commissioning, Inspection and Acceptance Requirements of the Drilling Unit
Attachment A5 – Drill String Component Inspection Requirements
Attachment A6 – Drilling Hoisting Equipment Inspection Requirements
Attachment A7 – BOP Acceptance, Inspection and Testing
Attachment A8 – Environmental, Safety, Fire and Health Systems Audit and Inspection
Attachment A9 – Contractor’s Safety Management System
Attachment A10 – Application for Permit to Operate in Ghana
 
96

 
EXHIBIT Al TO EXHIBIT A
 
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Attachment Al to Exhibit A – Scope of Work
 
RIG DESCRIPTION AND EQUIPMENT INVENTORY
“ATWOOD HUNTER”
 
1.	DESCRIPTION	 	Atwood Oceanics Pacific Limited	
 	A.	Owner	 	 	
 	 	 	 	 	
2.	CAPABILITIES	 	 	
 	A.	Maximum Water Depth	 	4,000’ (1,219m) Harsh Environment
5,000’ (1,524m) Mild Environment	
 	 	 	 	 	
 	B.	Minimum Water Depth	 	150’(45 m)	
 	 	 	 	 	
 	C.	Maximum Drilling Depth	 	28,000’ (8,535m)	
 	 	 	 	 	
 	D.	Mild Environment (10 yr storm):	 	(i.e. West Africa, Mediterranean, Indonesia)	
 	 	(i)	Maximum VDL	 	3,559 tons	
 	 	(ii)	Wind Speed	 	35.0 knots	
 	 	(iii)	Wave Height ft/Period sec	 	11.2/6.5	
 	 	(iv)	Current (surface)	 	2.33 knot	
 	 	 	 	 	 	
 	E.	Harsh Environment (10 yr storm):	 	(i.e. Brazil)	
 	 	(i)	Maximum VDL	 	3,559 tons	
 	 	(ii)	Wind Speed	 	46.7 knots	
 	 	(iii)	Wave Height ft/Period sec	 	19.7/8.7	
 	 	(iv)	Current (surface)	 	2.72 knots	
 	 	 	 	
3.	REGISTRATION and CLASSIFICATION	 	 	
 	A.	Construction	 	Catamaran with two (2) lower hulls braced by four (1) transverse trusses. Upper hull supported by eight (8) cylindrical columns	
 	 	 	 	 	
 	B.	Classification	 	ABS Maltese Cross Al Column Stabilized Drilling Unit	
 	 	 	 	 	
 	C.	Flag	 	Marshall Island	
 	 	 	 	 	
 	D.	Year Built	 	1981, Upgraded 1997 and 2001	
 	 	 	 	 	
4.	DIMENSIONS and CHARACTERISTICS	 	 	
 	A.	Lower Hulls	 	 	
 	 	(i) 	Length Overall	 	290’	
 	 	(ii) 	Beam Overall	 	246.77’	
 	 	(iii) 	Width	 	52’	
 	 	(iv) 	Depth	 	25’	

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 	B.	Stability Columns	 	Four (4) 26’ diameter, one (1) on each corner Four (4) 16’ diameter at upper deck flaring to 26’ diameter at pontoons, at each port and starboard side
Two (2) 15’ diameter, one (1) at each aft corner for additional buoyancy	
 	 	 	 	 	
 	C.	Platform/Main Deck	 	 	
 	 	(i) 	Length	 	268’/230’	
 	 	(ii) 	Beam	 	237’/237’	
 	 	 	 	 	
 	D.	Heights	 	 	
 	 	(i)	Keel to Main Deck	 	95’	
 	 	(ii)	Keel to Pipe Deck	 	108’	
 	 	(iii)	Keel to Helideck	 	126.9’	
 	 	(iv)	Keel to Drill Floor	 	128.4’	
 	 	(v)	Keel to top of Derrick	 	340.8’	
 	 	 	 	 	 	
 	E.	Natural Period	 	 	
 	 	(i)	Heave (sec)	 	21	
 	 	(ii)	Pitch (sec)	 	32	
 	 	(iii)	Roll (sec)	 	41	
 	 	 	 	 	 	
5.	DRAFTS and LOADING	 	 	
 	A.	Drafts	 	 	
 	 	(i) 	Lightship	 	18.6’	
 	 	(ii) 	Transit draft	 	24’	
 	 	(iii) 	Drilling	 	55’	
 	 	(iv) 	Station Keeping	 	55’	
 	 	(v) 	Survival	 	40’	
 	 	 	 	 	 	
 	B.	Displacement 	 	 	
 	 	(i) 	Lightship	 	13,330.05 tons	
 	 	(ii) 	Ocean Move	 	18,545.3 tons	
 	 	(iii) 	Field Move	 	19,811.2 tons	
 	 	(iv) 	Drilling	 	26,670.4 tons	
 	 	(v) 	Survival	 	23,907.6 ions	
 	 	 	 	 	 	
 	C.	Maximum VDL	 	 	
 	 	(i) 	Ocean Move	 	2,300 tons	
 	 	(ii) 	Field Move	 	2,300 tons	
 	 	(iii) 	Drilling	 	3,559 tons	
 	 	(iv) 	Survival	 	3,880 tons	
 	 	 	 	 	 	
6.	STORAGE CAPACITIES	 	 	
 	A.	Hulls	 	 	 	
 	 	(i) 	Fuel Oil	 	7,548 barrels	
 	 	(ii) 	Drillwater	 	21,328 barrels	
 
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 	 	(iii)	Potable Water	 	1,966 barrels	
 	 	(iv)	Ballast Water	 	10,714.06tons	
 	 	(v)	Base Oil	 	3,304 barrels	
 	 	(vi)	Total Compartments	 	11 per hull	
 	 	(vii)	Brine	 	1,000 barrels in aft stability columns	
 	 	 	 	 	 	
 	B.	Main Deck	 	 	
 	 	(i) 	Bulk Mud Storage Pods	 	Four (4) each at 1,250 ft3,total 5,000ft3	
 	 	(ii) 	Bulk Cement Storage Pods	 	Four (4) each at 1,250 ft3,total 5,000ft3	
 	 	 	 	 	 	
 	C.	Decks	 	 	
 	 	(i) 	Active and Reserve Mud	 	3,247 barrels	
 	 	(ii) 	Slugpit, sand traps, trip tank	 	324 barrels	
 	 	(iii) 	Sack Mud Storage	 	5,120 sacks	
 	 	(iv) 	Riser/Casing Rack Areas	 	One (1) 83’x56’ area, and one (1) 83’ x 52’ area	
 	 	(v) 	Pipe/Casing Rack Areas	 	One (1) 40’x 38’ area	
 	 	 	 	 	One (1) 40’x 28’area	
 	 	 	 	 	One (1) 40’x 25’area	
 	 	 	 	 	 	
7.	DRILLING EQUIPMENT	 	 	
 	A.	Derrick	 	Pyramid	
 	 	(i)	Height	 	185’	
 	 	(ii)	Static Hook Load Capacity	 	1,200,000 pounds	
 	 	(iii)	Base / Top	 	40’ x 40’ / 18’ x 18’	
 	 	(iv)	Maximum Setback	 	550 tons: 308 stands 5-7/8” drill pipe plus 10	
 	 	 	 	 	stands 10” drill collars	
 	 	 	 	 	 	
 	B.	Crown Block	 	Pyramid	
 	 	(i)	Capacity	 	600 tons	
 	 	(ii)	Lines	 	12	
 	 	 	 	 	 	
 	C.	Traveling Block	 	Western Gear	
 	 	(i)	Capacity	 	650 tons	
 	 	(ii)	Guide System	 	Two (2) rail system	
 	 	 	 	 	 	
 	D.	Top Drive	 	Varco TDS-4S, driven by GE752 shunt motor, 45,500 foot pounds continuous torque, 50,100 foot pounds intermittent torque, equipped with PH 85 pipe handler	
 	 	 	 	 	
 	E.	Swivel	 	Oilwcll PC-650	
 	 	(i) 	Capacity	 	650 tons	
 	 	 	 	 	 	
 	F.	Drawworks	 	Oilwell E3000	
 	 	(i)	Motors	 	Three(3) GE752 DC series	
 	 	(ii)	HP	 	800 HP each (continuous)	
 	 	(iii)	Electric Brake	 	Baylor 7838 with battery backup	
 	 	(iv)	Disc Brake	 	National ME 3000	
 
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 	 	(v) 	KEMS	 	Drillers Control Unit	
 	 	 	 	 	 	
 	G.	Crown BlockProtector	 	Crown-o-Matic	
 	 	 	 	 	
 	H.	Drill Line	 	1-1/2” diameter IWRC EIPS wire rope	
 	 	 	 	 	
 	I.	Wireline Anchor	 	National EB	
 	 	 	 	 	
 	J.	Motion Compensator	 	Western Gear pipermaster single cylinder
Model 600-20/25C (upgraded)	
 	 	(i) 	Stroke	 	25’	
 	 	(ii)	Capacity	 	600,000 pounds	
 	 	(iii) 	Static Load Lockout	 	1,200,000 pounds	
 	 	 	 	 	 	
 	K.	Rotary Table	 	Oilwell 49-1/2”	
 	 	(i) 	Motor	 	One (1) GE752 DC series	
 	 	(ii) 	HP	 	800 (continuous)	
 	 	(iii) 	Rated Capacity	 	800tons	
 	 	 	 	 	 	
 	L.	Master Bushing	 	Varco MPCH 37-1/2”	
 	 	 	 	 	 	
 	M.	Pipe Spinner	 	 	
 	 	(i) 	Model	 	Varco SSW-40	
 	 	(ii) 	Size Range	 	2-7/8” 9”	
 	 	(iii) 	Drive	 	Pneumatic	
 	 	 	 	 	 	
 	N.	Iron Roughneck	 	Varco ST-80 Tubular OD Range 41/4 to 81/2 in. - Nominal Drill Pipe Sizes 3 1 / 2  to 5 1 / 2  in. Max. Make up Torque 60,000 ft-lb. Max Break-out Torque 80,000 ft-lb.
SpinSpeed 100 RPM Spin Torque 1,750 ft-lb.	
 	 	 	 	 	
 	O.	Drill floor ManipulatorArm	 	MHPyramid Model MH 3009-01 for handling riser and tubulars	
 	 	 	 	 	
 	P.	Rotating Mouse Hole	 	International Oil Tools - Phantom Mouse Model 1994 for tool joint sizes 2-7/8” to 10-3/4”
Twister Torque tool Model TT-98 make-up and break-out tool joint sizes 3” to 8-l/2”up to 108,000 ft-lbs torque. Allows make-up and break-out off the critical path	
 	 	 	 	 	
 	Q.	Pipe Handling	 	Elevated Catwalk - for transporting tubulars/riser on to drill floor	
 	 	 	 	 	
 	R.	WirelineUnit	 	MatheyRetriever 15,000’	
 	 	(i)	Wire Size	 	0.092”	
 
101

 
8.	DRILL STRING	 	 	
 	A.	Drill Pipe	 	 	
 	Range 2 quenched and tempered with NC-50, 18° taper, 6-5/8” OD tool joints except as specified.	 	 	
 	 	(i) 	Grade S-135	 	5” OD, 19.5 pounds/foot 	
 	 	 	Joints	 	Fourhundred & Eighty (480)	
 	 	 	Plastic Coated	 	Yes	
 	 	 	 	 	 	
 	 	(ii) 	Grade S-135	 	3-1/2” OD, 13.3 pounds/foot, with 5” OD NC-38 tool joints	
 	 	 	Joints	 	One hundred thirteen (112) (One Mule shoe Joint)	
 	 	 	 	 	 	
 	B	Hevi-WaleDrill Pipe	 	 	
 	 	(i) 	 Size	 	5”OD, 50pounds/foot	
 	 	 	Joints	 	Thirty-two (32)	
 	 	 	Connections	 	NC-50, 6 5/8” OD	
 	 	(ii) 	Size	 	3-1/2” OD,25.3 pounds/foot	
 	 	 	Joints	 	Ten (10)	
 	 	 	Connections	 	NC-38, 5” OD	
 	 	 	 	 	 	
 	C.	Drill Collars
Drill collars are 30’ spiral zip grooved, API stress relieved box and pin, cold rolled thread roots with anti-galling treatment	 	 	
 	 	(i) 	Size	 	9” OD x 3” ID	
 	 	 	Joints	 	Ten(10)	
 	 	 	Connections	 	7-5/8” Reg	
 	 	 	 	 	 	
 	 	(ii) 	Size	 	8 1/4” OD x 2-13/16” ID	
 	 	 	Joints	 	Twenty (20)	
 	 	 	Connections	 	6-5/8” Reg	
 	 	 	 	 	 	
 	 	(iii) 	Size	 	8” OD x 2-13/16” ID	
 	 	 	Joints	 	Nine (9)	
 	 	 	Connections	 	6-5/8” Reg	
 	 	 	 	 	 	
 	 	(iv) 	Size	 	6-1/2” OD x 2-13/16” ID	
 	 	 	Joints	 	Thirty-five (35)	
 	 	 	Connections	 	NC-50	
 	 	(iv) 	Size	 	4-3/4” OD x 2-1/4” ID	
 	 	 	Joints	 	Twenty-four (24)	
 	 	 	Connections	 	NC-38	
 	 	 	 	 	 	
 	D.	Pup Joints	 	 	
 	 	(i) 	5” OD Drill Pipe, NC-50,	 	Grade S-135:	
 	 	 	6 5/8” OD tool joints	 	Two (2) x 20’	
 	 	 	 	 	One (1) x 15’	
 	 	 	 	 	One (1) x 14.65’	
 	 	 	 	 	One (1) x 10’	
 	 	 	 	 	One (1) 9.7’	
 
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 	E.	Miscellaneous Subs	Cross-overs and bit subs as required to fit contractor supplied tubulars.	
 	 	 	 	
 	F.	Safely Valves	 	
 	 	(i)	Inside BOP	Two (2) 5” Gray, Two (2) 3-1/2” OMSCO	
 	 	 	Working Pressure	10,000 psi	
 	 	 	Connections	NC-50	NC-38	
 	 	(ii)	Lower Kelly Valves	Two (2) 5” TIW, One (1) 5” OMSCO , Two (2) 3-1/2”	
 	 	 	 	OMSCO	
 	 	 	Working Pressure	10,000psi	
 	 	 	Connections	NC-50	NC-50	NC-38	
 	 	(iii)	Upper Kelly Valves	One(1) Omsco	
 	 	 	Working Pressure	10,000psi	
 	 	 	Connections	6-5/8” reg	
 	 	 	 	 	
 	G.	Circulating Head with 1502	Manufactured from 6-1/2” drill collar with 18 degree lifting	
 	 	Weco side outlet	neck sub	
 	 	(i)	Connection	NC-50	
 	 	 	 	 	
9	DRILL STRING HANDLING TOOLS	 	
 	A.	Tongs	 	 	
 	 	(i)	100,000 foot pounds.	Two (2) eachFoley Type 1600 3-1/2” to 17”	
 	 	(ii)	65,000 foot pounds.	Two (2) each Varco HT 65, 3-1/2” thru 13-3/8”	
 	 	 	 	 	
 	B.	Slips	 	 	
 	 	(i)	Varco SD XL	Two (2) sets for 5” drill pipe	
 	 	 	 	Two (2) sets for 3-1/2” drill pipe	
 	 	(ii)	Bash Ross	One (1) set for 3-1/2” drill pipe	
 	 	(iii)	Varco SDML	Two (2) sets for 3-1/2” drill pipe	
 	 	(iv)	Varco DCS-L	One (1) setfor 9” - 10” drill collars	
 	 	 	 	One (1) setfor 7-3/4” - 8-1/4” drill collars	
 	 	(v)	Varco DCS-R	Two (2) setsfor 6-1/2” drill collars	
 	 	 	 	Two (2) sets for4-3/4” drill collars	
 	 	 	 	 	
 	C.	Elevators	 	
 	 	(i)	750 ton	One (1) set Blohm & Voss type VES-CL-75 center latch for 8-	
 	 	 	 	5/8” riser running tool	
 	 	(ii)	500 ton	One (1) set BJ type HGG center latch for 5” drill pipe	
 	 	 	 	(running riser)	
 	 	 	 	 	
 	 	(iii)	350ton	One (1) set Varco “bottle neck” center latch for 5” drill pipe	
 	 	 	 	One (1) set Varco BNC type for Top Drive	
 	 	(iv)	250 ton	One (1) set BJ type MGG center latch for 5” drill pipe	
 	 	 	 	Two (2) sets Web Wilson center latch for 3-1/2” drill pipe	
 	 	(v)	150 ton	Two (2) sets BJ type PA-150 for 8” drill collars	
 	 	 	 	One (1) set of BJ type PA 150 for 6-1/2” drill collars	
 	 	(vi)	100 ton	Two (2) sets BJ type TA-100 for 4-3/4” drill collars	
 
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 	D.	Elevator Links	 	
 	 	(i)	750 ton	One (1) set Blohm & Voss 4-3/4” x 144”	
 	 	(ii)	500 ton	One (1) set BJ 3-1/2” x 180”	
 	 	(iii)	350 ton	One (1) set Varco 2-3/4” x 108”	
 	 	 	 	One (1) set BJ 2-3/4” x 132”	
 	 	(iv)	150 ton	One (l) set BJ1-3/4” x 36”	
 	 	 	 	 	
 	E.	BreakerPlates	For 26”, 17-1 /2”, 12-1 /4”, 8-1/2” and 6” bits	
 	 	 	 	
 	F.	Drill Collar Torque Unit	Varco HC 26 Hydraulic Cathead	
 	 	(i)	Line Pull	4,000 pounds- 32,500 pounds at 2,500 psi.	
 	 	 	 	
 	G.	Miscellaneous	One (1) Varco type MP-R for 5” - 7”	
 	 	(i)	Safety Clamps	One (1) Varco type MP-R for 6-3/4” - 8-1/4”	
 	 	 	 	One (1) Varco type MP-R for9-1/4” - 10-1/2”	
 	 	 	 	 	
10.	FISHING TOOLS	As required to fish Contractor supplied drill string excluding mills, magnets.	
 	 	 	
11.	CASING HANDLING EQUIPMENT	 	
 	A.	Tongs	Two (2) each Foley Type 1600 for 7” to 13-3/8” casing	
 	 	 	Two (2) eachVarco Type B for 9-5/8” to 20” casing	
 	 	 	 	
 	B.	Power Tongs	One(1) Weatherford Lamb Model 16000 with hydraulic	
 	 	 	 	power unit, for sizes 2-3/8” through 16”	
 	 	 	 	 	
 	C.	Elevators	Two (2) 500 ton BJelevator slip/spider with inserts for 13-	
 	 	 	 	3/8”, 9-5/8” and 7” casing	
 	 	(i)	20” casing	One (1) set BJ 150 Ton side door	
 	 	(ii)	13-3/8” casing	One (1) set BJ 150 Ton side door	
 	 	(iii)	9-5/8” casing	One (1) set BJ 150 Ton side door	
 	 	(iv)	7” casing	One (1) set BJ 150 Ton side door	
 	 	(v)	Single Joint	One (1) set for 7”, 9-5/8” and 13-3/8” and 20” casing	
 	 	 	 	 	
 	D.	Slips and Bushings	Varco CMS-XL Casing Slips	
 	 	 	 	One (1) set for 6-5/8” to 7-5/8”	
 	 	 	 	One (1) set for 9-5/8”	
 	 	 	 	One (1) set for 13-3/8”	
 	 	 	 	One (1) set for 20”	
 	 	 	 	 	
 	E.	Casing Protectors	Klepo, three (3) each casing size, 13-3/8”, 9-5/8” and 7”	
 	 	 	 	 	
12.	MUD CIRCULATING SYSTEM	 	
 	A.	Mud Pumps	Three (3) Oilwell A1700 PT triplex pumps,beltdrive, with	
 	 	 	maintenance free pulsation dampners on discharge/suction.	
 	 	 	Each equipped with:	
 	 	(i)	Motors	Two (2) GE 752 DC 800 HP (continuous) series	
 
104

 
 	 	(ii)	Charge Pump	One (1) 6” x 5” centrifugal	
 	 	(iii)	Charge Pump Motor	One (l) 100 HP electric	
 	 	(iv)	Discharge Lines	5” schedule 160	
 	 	(v)	Liners	6-1/2”	
 	 	 	 	 	
 	B.	Rotary Hoses	 	
 	 	(i)	Working Pressure	Two (2) 3” x 120’ wire braided	
 	 	(ii)	Test Pressure	5,000 psi	
 	 	 	 	7,500 psi	
 	 	 	 	 	
 	C.	Standpipes	Two (2) x 5”, 5,000 psi working pressure	
 	 	 	 	
 	D.	Mud Tanks	 	
 	 	(i)	Active Pits	Three (3) with 928 barrels total capacity	
 	 	(ii)	Reserve Pits	Seven (7) with 2,319 barrels total capacity	
 	 	(iii)	Slug Pit	One (1), 72 barrels capacity	
 	 	(iv)	Sand Traps	Two (2), 202 barrels total capacity	
 	 	(v)	Trip Tank	One (1), 50 barrels capacity	
 	 	 	 	 	
 	E.	Mud Mixing Pumps	Three (3) Mission 6” x 5” centrifugal each driven by 100 HP electric motor	
 	 	 	 	
 	F.	Mud Mixing System	 	
 	 	(i)	Agitators	Fifteen (15) Lightnin	
 	 	(ii)	Mud Guns	Twenty (20) Demco	
 	 	 	 	Sixteen (16) Brandt	
 	 	(iii)	Hoppers	Two (2) Demco standard model units	
 	 	 	 	 	
 	G.	Desander	Fluid Systems Model 132X-NP	
 	 	(i)	Size	Six (6) each 8” cones	
 	 	(ii)	Capacity	900 GPM	
 	 	 	 	 	
 	H.	Degassers	One (1) Brandt Model DG 10	
 	 	(i)	Capacity	1,000 GPM	
 	 	 	 	 	
 	I.	Shale Shakers	Four (4) Brandt Dual Tandem over Four (4) Brandt	
 	 	 	Flow Line Cleaners	
 	 	 	 	
 	J.	Mud Cleaner/Desilter	Fluid Systems Model CXP200-6	
 	 	(i)	Size	Sixteen (16) each 4” cones	
 	 	(ii)	Capacity	1,280 GPM	
 	 	 	 	 	
 	K.	Mud Gas Separator	48” diameter x 17’ tall with 10” vent line to derrick top, 2 each 5” lines from choke manifold, internal bafiles and liquid seal system	
 	 	 	 	
 	L.	Gumbo Box	One (1) Alwood design	
 
105

 
13.	BULK STORAGE/ TRANSFER SYSTEM	 	
 	A.	Storage Tanks	Eight (8) Halliburton	
 	 	(i)	Size	1,250ft3 each, total10,000 ft3 	
 	 	(ii)	LoadCells	None- manually sounded	
 	 	 	 	 	
 	B.	Surge Tank	One(l) Halliburton	
 	 	(i)	Size	70ft3	
 	 	(ii)	Load Cell	Martin Decker 10,000 pound capacity	
 	 	 	 	 	
 	C.	Air System	 	
 	 	(i)	Compressors	One (1) Quincy Model QSP-100	
 	 	(ii)	Motors	One (1) 100 HP electricmotor	
 	 	(iii)	Capacity	712 ACFM	
 	 	(iv)	Working Pressure	38 psi	
 	 	(v)	Dryer	One (1) Quincy PNC-2000 @ 2000 SCFM Dryer	
 	 	(vi)	Receiver	One (l) x 39 ft3	
 	 	 	 	 	
14.	CEMENT SYSTEM	 	
 	A.	Cementing Unit	Operator supplied.Presently equipped with BJ RAM SCP 348 with ACC-II, backup recire pump, two (2) Caterpillar 3406C diesel engines, 3305 Mini Monitor and Liquid Additives System.	
 	 	 	 	
 	B.	Discharge Lines	Two (2) 3-1/2” OD X 2” ID, 10,000 psi working pressure, H 2 S certified.	
 	 	 	 	
 	C.	Cement Standpipe	2”ID x 10,000 psi workingpressure, 38’ high, complete with 2” x 45’ long x 10,000 psi working pressure hose with 2” 1502 connections.	
 	 	 	 	
15.	SUB-SEA BOP STACK, RISER and RELATED EQUIPMENT	
 	A.	BOP Stack	 	
 	 	(i)	Annular Preventers	Two (2) Shaffer 18-3/4”	
 	 	 	Working Pressure	5,000psi	
 	 	(ii)	Ram Preventers	Two(2) Cameron 18-3/4” double type “U”	
 	 	 	Working Pressure	10,000 psi	
 	 	(iii)	Preventer Inventory	Two (2) sets 5” pipe rams	
 	 	 	 	One (1) set 3-1/2” pipe rams	
 	 	 	 	One (1) set blind shear rams	
 	 	 	 	Two (2) sets Variable 3-1/2” - 7-5/8” pipe	
 	 	 	 	rams	
 	 	 	 	Two (2) sets Annular Elements	
 	 	(iv)	H2S Service	Yes	
 	 	 	 	 	
 	 	(v)	Control Pods	NL Shaffer with Pressure Bias System	
 	 	 	 	 	
 	B.	Choke and KillValves	 	
 	 	(i)	Master VaIves	Three (3) Cameron right-angle fail-safe type	
 	 	 	 	hydraulic assist	
 
106

 
 	 	 	Size	3-1/16” ID	
 	 	 	Operation	Hydraulic open, spring assist close	
 	 	 	Working Pressure	10,000psi	
 	 	(ii)	Operating Valves	Three (3) Cameron straight through type fail-safe hydraulic assist	
 	 	 	Size	3-1/16” ID	
 	 	 	Operation	Hydraulic open, spring assist close	
 	 	 	Working Pressure	10,000 psi	
 	 	 	 	 	
 	C.	Choke and Kill Hoses	 	
 	 	(i)	Lines	Two (2) 3” ID x 45’ long, 10,000 psi WP hoses	
 	 	(ii)	Oil States Flex Joint	Two (2) 4” 10,000 psi stainless steel armored hoses	
 	 	 	Jumper Connection	 	
 	 	 	 	 	
 	D.	Connectors	 	
 	 	(i)	Riser	Vetco H-4 Style “E” 18-3/4” (stud top)	
 	 	 	Working Pressure	10,000 psi	
 	 	(ii)	Wellhead	Veteo H-4 Style “E” 18-3/4” (hub top)	
 	 	 	Working Pressure	10,000psi	
 	 	 	 	 	
 	E.	Marine Riser	Veteo with two each 2.575” ID / 4.375”OD,
15,000 psi integral kill and choke lines,one
2.350” ID/ 2.875” OD hydraulic supply line,
one 3.364” ID / 4.0” OD mud circulating line	
 	 	(i)	Quantity/OD/Length/Wall	Sixty eight (68) each 21” x 75’ x 5/8” wall (22
with 2,000’ buoyed, 23 with 3,500’ buoyed, 20
with 5,000’ buoyed, and 3 slick.)	
 	 	(ii)	Connections	Veteo HMF (flanged connections)	
 	 	(iii)	Pup Joints	One (1) each 25’, 31.5’, 37.5’, 43.75’, 50’.	
 	 	 	 	 	
 	F.	Telescopic Joint	Two (2) Vetco with dual packers, and HMF
connections	
 	 	Stroke	55’	
 	 	 	 	
 	G.	Flex Joint	One (1) Oil States 10° Single Flex 18-3/4”
with Vetco HMF connections and jumper
hoses,	
 	 	 	 	One (1) spare 18-3/4” Oil States 10° Single
FlexJoint	
 
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 	H.	Choke Manifold	Control Flow
10,000 psi working pressure H2S trimmed
Two (2) 3-l/16”hydrau!ic chokes, Control
Flow Multi-Flow
Two (2) 3-I/16”manuaI adjustable chokes
Flocon type LH-94
Sixteen (16) 3-1/16” gate valves, Flocon type
BW
Two (2) 2-1/16” gate valves, Flocon type BW
Four (4) 4-1/16” 5,000 psi working pressure,
Flocon type BW gate valves	
 	 	 	 	
 	I.	Test Stump	Two (2) Vetco 18-3/4” 10,000 psi working
pressure MSP stumps	
 	 	 	 	
 	J.	Diverter and Diverter Ball Joint	Regan KFDS-500 with 12” diverter lines to
port and starboard, with DR-1 Ball Joint.
Fitted for SDL ring (tensioner hangoff)	
 	 	 	 	
 	K.	Accumulator Unit	NL Shaffer	
 	 	(i)	Working Pressure	3,000 psi	
 	 	(ii)	Usable Bank Capacity	591 gallons	
 	 	(iii)	Accumulator Bottles	91 x 6.5 gallons	
 	 	(iv)	Pumps	Two (2) electric triplex, two (2) air driven	
 	 	 	 	 	
 	L.	Master Control Board	Rig floor	
 	 	 	 	
 	M.	Remote Control Board	Toolpusher’s office	
 	 	 	 	
 	N.	Hydraulic Control Pods	Two (2) NL Shaffer fully redundant, with
Pressure Bias system for one (1) Annular, one
(1) Pipe Ram, one (1) Blind Shear Ram and
one (1) H4 Connector	
 	 	 	 	
 	O.	Hydraulic Control Hoses	Two (2) bundles each 5,750’ long with sixty-five (65) x 3/16” diameter pilot hoses and one (1) x 1” supply hose	
 	 	 	 	 	
16.	SUB-SEA SUPPORT SYSTEM	 	
 	A.	Riser Tensioning System	Two (2) Western Gear Control Flow dual
tensioners at 160 kips each line.
Two (2) Western Gear dual tensioners at 80
kips each line
Four (4) Western Gear single line tensioners at
80 kip each	
 	 	(i)	Line Travel	48’	
 	 	(ii)	Number of Lines/Idler	Twelve (12)	
 	 	 	Sheaves	 	
 	 	(iii)	Total Tension Capacity	1,280,000 pounds.	
 
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 	 	(iv)	Control Panel	Western Gear	
 	 	(v)	Compressors	Two (2) Hamworthy Units	
 	 	 	Working Pressure	2,400 psi	
 	 	 	Dryers	Two (2) refrigerated type	
 	 	 	 	 	
 	B.	Guideline Tensioning System	Four (4) Western Gear single line tensioning
units	
 	 	(i)	Line Travel	40’	
 	 	(ii)	Single Line Load Capacity	16,000 pounds	
 	 	(iii)	Number of Lines/Idler Sheaves	Four (4)	
 	 	 	 	 	
 	C.	Pod Line Tensioning System	Two (2) Western Gear single line tensioning
units	
 	 	(i)	Line Travel	40’	
 	 	(ii)	Single Line Load Capacity	16,000 pounds	
 	 	(iii)	Number of Lines/Idler	Two (2)	
 	 	 	Sheaves	 	
 	 	 	 	 	
 	D.	Air Hoists for Guideline and Podline Tensioners	Guideline - Four (4) Ingersoll Rand Model FA7TPL42XK1, 25, HP, 7800 pounds rated pull at first layer and 4000 lbs. pull top layer (100 fpm).
Podline - Two (2) Ingersoll Rand Model FA7TPL42XX1 16,000 lbs. line pull first layer and 8000 lbs. pull top layer @ a line speed of 50-60 ft/min.
Capacity for 6,300’ of3/4” wire rope.	
 	 	 	 	
 	E.	BOP Handling System	Two (2) Houston System Gearmatic Model 44 60 ton hydraulic bridge cranes. BOP Transporter System with cart tracks and four (4) handling carts for port and starboard skidding of BOP/LMRP/Sub Sea Trees	
 	 	 	 	
 	F.	Hole Position Indicator	Kongsberg Simrad Model HPR 410D Acoustic Positioning System complete with differential tilt transponder with two (2) sets of inclinometers and transducers	
 	 	 	 	
 	G.	Underwater Camera	Kongsberg Simrad Fiber Optic Subsea TV
System with hydraulic winch unit	
 	 	(i)	Cable Length	5,700’	
 	 	(ii)	Camera	One (I) Zoom color camera	
 	 	(iii)	Pan and Tilt Assembly	One (1) Heavy duty stainless steel assembly	
 
109

 
17.	WELL TESTING EQUIPMENT	 	 	
 	A.	Burner Booms	 	(Operator furnished)	
 	 	 	 	 	
 	B.	Well test piping permanently installed on the rig	 	None	
 	 	 	 	 	
18.	MOORING	 	 	
 	A.	Chain	 	Eight (8) x 2-3/4”ORQ+20%	
 	 	(i)	Length	 	4,500’ (4,000’ usable)	
 	 	(ii)	MinimumBreaking Strength	 	1,060,000 pounds	
 	 	 	 	 	 	
 	B.	Wire	 	 	
 	 	(i)	Size/Length	 	3-1/4”x 8,500’ (8,000’ usable length)	
 	 	(ii)	Minimum Breaking Strength	 	1,224,000 pounds	
 	 	 	 	 	 	
 	C.	Anchors – Main	 	Six (6) 10 tonne MK5 High Holding Stevpris
Two (2) 12 tonne MK5 High HoldingStevpris	
 	 	Anchor –Spare	 	One(1) 30,000 pound Moorfast
One (1) 10 tonne MK5 High Holding Stevpris	
 	 	 	 	 	
 	D.	Permanent Chain Chasers	 	Eight (8) Bruce Ring cast steel	
 	 	 	 	 	
 	E.	Mooring Winch System	 	Four (4) Skagit TMWW-325/44 combination traction winch/windlass	
 	 	 	 	 	
 	F.	Tension Indicator System	 	One (1) remote tension recorder, Chessel Corp. located in Ballast Control Room 
Two (2) local Martin Decker tension gauge at each console	
 	 	 	 	
19.	POWER	 	 	
 	A.	DC System	 	Ten (10) bay IPS SCR system connected by common buss bar. Each SCR bay is 600 VAC/750 VDC	
 	 	(i)	Drilling	 	Five (5) bays,each 0 - 2,000 AMPS One (1) bay, 0-3,000 AMPS	
 	 	(ii)	Windlasses	 	Four (4) bays, each 0 - 1,200 AMPS	
 	 	(iii)	Harmonic Fi1ter/PowerFactor Corrector	 	To reduce harmonic distortion to less than 5%	
 	 	 	 	 	 	
 	B.	AC System	 	600 VAC distribution center connected to six (6) motor control centers for all AC rig power	
 	 	(i)	Generators	 	Two (2) General Electric AB20-6, 2,625 KVA	
 	 	 	Voltage	 	600 VAC	
 	 	 	Engines	 	Two (2) EMD diesel engines	
 	 	 	Model	 	16-645-E9B	
 	 	 	Output	 	Each 2,925 HP,Turbo-charged	
 	 	(ii)	Generator	 	One (1) General Electric AB20-6, 2,625 KVA	
 	 	 	Voltage	 	600 VAC	
 
110

 
 	 	 	Engine	 	One (1) EMD diesel engine	
 	 	 	Model	 	l6-645-E8	
 	 	 	Output	 	2,200 HP, Roots blown	
 	 	 	 	 	 	
 	C.	Emergency AC System	 	One (1) 550 KW 600 VAC generator with independent motor control center for essential services	
 	 	(i)	Engine	 	One (1) Caterpillar 3412 diesel engine, 800 HP	
 	 	 	 	 	 	
20.	SAFETY EQUIPMENT	 	 	
 	A.	Life Boats	 	Three (3) Watercraft 44 person	
 	 	 	 	 	
 	B.	Fast Deploy Rescue Craft	 	One (1) Schat Harding MOB17 Rigid rescue boat, integrated steering column, six (6) person capacity, 40 HP outboard motor, launched by rig crane.	
 	 	 	 	 	
 	C.	Life Rafts	 	Six (6) 25 person B.F. Goodrich davit launched	
 	 	 	 	 	
 	D.	Life Jackets/ Vests	 	Per ABS / Marshall Islands Regulations	
 	 	 	 	 	
 	E.	Ring Buoys	 	Per ABS / Marshall Islands Regulations	
 	 	 	 	 	
 	F.	Sick Bay	 	Six (6) beds plus examination table	
 	 	 	 	 	
 	G.	Stretchers	 	One (1) wire with orange floatation stretcher
One (1) wire stretcher
One (1) Sea Jay lift stretcher
One (1) Billy Pugh stretcher
One (1) Zee wooden body stretcher	
 	 	 	 	 	
 	H.	Breathing Air	 	Nine (9) SCBA units complete with 30 minute air bottles and six (6) spare bottles	
 	 	 	 	 	
 	I.	Fire Pumps and Hydrants	 	 	
 	 	(i)	Centrifugal Pumps	 	Two (2) 3x4 with 75 HP motors
One (1) 3x4 with 100 HP motor	
 	 	(ii)	Hose Stations	 	Thirty-five (35)	

 	J.	Extinguishers	 	One (1) lot portable as per ABS / Marshall Islands Regulations	
 	 	 	 	 	
 	K.	Fixed Fire System	 	CO2 fire suppression system for engine room, emergency generator room, control room, SCR room, and paint locker	
 	 	 	 	 	
 	L.	Gas Detection Systems	 	One (1) Detcon System Model FP624 and TP624 with (28) LEL sensors and (31) H2S sensors	
 
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 	 	 	 	Four (4) portable MSA Micro-guard detectors - LEL and Oxygen
Two (2) portable H2S detectors- Biosystems	
 	 	 	 	 	
 	M.	Fire and Gas Detection Panels	 	One (1) Sola Comm / Motorola Moscad 136 points of addressable fire notification, UPS system (4.3 KVA) with 2 touch screen displays, 78 strobe lights, and 3 outputs for alarm over the PA system. One Mimic panel located in the Drillers console One (1) Henschel twelve stations located in quarters for monitoring outside quarters	
 	 	 	 	
21.	VESSEL SYSTEMS	 	 	
 	A.	Ballast Pumps	 	Two (2) in each hull	
 	 	(i)	Type	 	Johnston, 13.375” Impeller	
 	 	(ii)	Motors	 	Four (4) USElectric 100 HP, 1,780 RPM	
 	 	 	 	 	 	
 	B.	Bilge Pumps	 	Four (4), two (2) in each hull	
 	 	(i)	Type	 	Crane Deming Model 3131, size 3 x 2 x 10” Marcon SZHEL-76	
 	 	(ii)	Motors	 	Four (4) Marathon 5 HP, 3,440 RPM	
 	 	 	 	 	 	
 	C.	Sanitary System	 	Omnipure I2MS	
 	 	 	 	 	 	
 	D.	Salt Water Service Pump	 	One (l)	
 	 	(i)	Type	 	Mission Magnum 5 x 4	
 	 	(ii)	Motor	 	USElectric 100 HP, 1,750 RPM	
 	 	 	 	 	 	
 	E.	Brake Cooling Pumps	 	Two (2)	
 	 	(i)	Type	 	Mission Magnum 2x3x13”	
 	 	(ii)	Motors	 	Two (2) US Electric 20 HP, 1,760 RPM	
 	 	(iii)	Tank Capacity	 	3,500 gallons	
 	 	 	 	 	 	
 	F.	PotableWater Pumps	 	Two (2) in each hull	
 	 	(i)	Type	 	Howard Model 1512	
 	 	(ii)	Motors	 	Four (4) 5 HP, 3,450 RPM	
 	 	 	 	 	 	
 	G.	Fire Pumps	 	SeeSafety Section 20.I	
 	 	 	 	 	 	
 	H.	Fuel OilTransfer Pumps	 	Two (2) in engine room	
 	 	(i)	Type	 	Ropermodel 2AP32	
 	 	(ii)	Motors	 	Two (2) US electric 5 HP, 1,740 RPM	
 	 	 	 	 	 	
 	I.	Fuel Oil Service Pumps	 	One (1) in each hull	
 	 	(i)	Type	 	Roper Model2AP32	
 	 	(ii)	Motors	 	Two (2) US electric 5 HP, 1,740 RPM	
 
112

 
 	J.	Drill Water Pumps	 	One (1) in Mechanical equipment room
Two (2) in lower hulls	
 	 	(i)	Type	 	Mission Magnum 5x4x12” (equipment room) Johnston Type 10AC 7-1/2” impeller (hulls)	
 	 	(ii)	Motor	 	One (1) Marathon Electric 100 HP, 1,775 RPM (equipment room)
Two (2) US Electric 20 HP, 1,750 RPM (hulls)	
 	 	 	 	 	 	
 	K.	Waste Oil Transfer Pump	 	One (1) in engine room	
 	 	(i)	Type	 	Brown & Sharp	
 	 	(ii)	Motor	 	One (1) Marathon electric 5 HP, 1,750 RPM	
 	 	 	 	 	 	
 	L.	Lube Oi1 Transfer Pump	 	N/A - Gravity fed	
 	 	 	 	 	 	
 	M.	Rig Air Compressors	 	 	
 	 	(i)	Main	 	Two (2) Quincy QSI-490	
 	 	 	Capacity	 	490 CFM at 125 psi	
 	 	 	Motors	 	Two (2) electric 125 HP	
 	 	(ii)	Emergency (Cold Start)	 	One (1) Quincy QSI-490	
 	 	 	Capacity	 	490 CFM at 125 psi	
 	 	 	Motor	 	One (1) Detroit 6V-71 diesel	
 	 	(iii)	Receivers	 	Three (3) x 34ft3	
 	 	 	 	 	 	
 	N.	HP Air Compressors	 	Three (3)	
 	 	(i)	Type	 	Hamworthy	
 	 	(ii)	Rating	 	3,000 psi	
 	 	 	 	 	 	
 	O.	Air Dryers	 	 	
 	 	(i)	Type	 	One (1) Quincy PNC-2000 10 hp motor rated @ 2000 scfm
Two (2) Zander refrigerated for HP compressors One (1) Arrow refrigerated for Rig air compressors	
 	 	 	 	 	 	
 	P.	Heliport Foam Unit	 	 	
 	 	(i)	Type	 	Magnum Fire and Safety System	
 	 	(ii)	Maximum Allowable Working Pressure	 	175 psi at 200°F	
 	 	(iii)	Bladder Capacity	 	50 gallons	
 	 	(iv)	Monitors	 	Two (2) Akron 37000 Series Turbo Jet, Style 352 B	
 	 	(v)	Water Pump	 	Mission 3x4	
 	 	(vi)	Motor	 	100 HP, 3,500 RPM	
 	 	(vii)	Hose Reel	 	One (1) with 1-1/2” x 75’ hose and nozzle	
 	 	 	 	 	 	
 	Q.	Helicopter Refueling System	 	One (1) ITT Marlow 2UEVP17A system rated at 60 gpm. Complete with dual filter separator, meter, pump, hose reel complete with 2” x 70’ hose and nozzle, and two (2) skid mounted 600 gallon fuel tank assemblies on quick release platforms.	
 
113

 
 	R.	Water Distillation Unit	 	One (1) Alfa-Laval Model DPU-36-C125	
 	 	(i)	Capacity	 	14,500 gpd	
 	 	 	 	 	 	
 	S.	Lighting	 	General rig lighting and emergency generator	
 	 	 	 	 	
22.	ACCOMMODATIONS	 	 	
 	A.	Rooms	 	Total of 120 beds (excluding sick bay)	
 	 	 	 	 	
 	B.	Galley and Mess	 	One (1) with seating for 60	
 	 	 	 	 	
 	C.	Recreation Room	 	One (1),	
 	 	 	 	 	
 	D.	Reading Room	 	One (1) (Use as Prayer room in required Countries)	
 	 	 	 	 	
 	E.	Break room	 	One (1) (Used as coffee & smoke room)	
 	 	 	 	 	
 	F.	Change Room	 	One (1)	
 	 	 	 	 	
 	G.	Laundry Room	 	One (1)	
 	 	 	 	 	
 	H.	Smoking Room	 	One (1)	
 	 	 	 	 	
 	I.	Conference Room	 	One (1)	
 	 	 	 	 	
 	J.	Heliport Waiting Room	 	One (1)	
 	 	 	 	 	
 	K.	Laboratory Facilities	 	Mud Lab (Positioned Starboard side Main deck)	
 	 	 	 	 	
 	L.	Warehouse and Storage	 	Dry stores, cooler, freezer, paint locker, storeroom, drilling stores	
 	 	 	 	 	
 	M.	Workshops	 	Mechanical, electrical and sub-sea	
 	 	 	 	 	
 	N.	Offices	 	Six (6) — one office fitted with five (5) cubicles (Three (3) designated as Client/Third Party offices)	
 	 	 	 	 	
 	O.	Sick Bay	 	One (I)—six (6) beds plus examination table	
 	 	 	 	 	
23.	HVAC	 	 	
 	A.	Accommodations	 	 	
 	 	(i)	Condensing Units	 	Two (2) units with backup for each quarters level	
 	 	(ii)	Air Handlers	 	Seven (7) units with backup for each quarters level	
 	 	 	 	 	 	
 	B.	SCR Room	 	 	
 	 	(i)	Condensing Units	 	Two (2) Carrier Model 38AH-024-6 (20 ton each), two circuits	
 	 	(ii)	Air Handlers	 	Two (2) Carrier Model 39LD-8 Complete with DX coils, two circuits	
 
114

 
24.	HELIPORT	 	83’ x 83’ rated for 19,000 pounds. Designed to accommodate Sikorsky S-61N helicopter	
 	 	 	 	
25.	CARGO HANDLING	 	 	
 	A.	Cranes	 	One (1) Starboard Seatrax Series 80 Model 8032
One (1) Port Baker Marine Model BMC 2250-C88	
 	 	(i)	Boom Length	 	150’(stbd)
140’ (port)	
 	 	(ii)	Load Rating	 	 	
 	 	 	a)	Static	 	105,061 pounds at 100 feet (stbd)
73,963 pounds at 20 feet (port)	
 	 	 	 	Dynamic (Dynamic coefficient = 2.0)	 	105,061 pounds al 70 feet (stbd)
49,186 pounds at 20 feet (port)	
 	 	 	 	 	 	 	
 	B.	Gantry Crane	 	Cranemann 30 ton capacity (two each 15 ton hoists) for tubular/riser handling	
 	 	 	 	 	
 	C.	Forklift	 	Hyster E80XL2 Electric	
 	 	(i)	Capacity	 	8,000 pounds	
 	 	 	 	 	 	
26.	COMMUNICATIONS and NAVIGATION	 	 	
 	A.	Radio/Telephone	 	 	
 	 	(i)	 	 	Satellite Communications Make: XERA	
 	 	 	 	 	                                          Model: Fleet 77	
 	 	 	 	 	Stabilized Satellite antenna that operates on the International Maritime Satellite (INMARSAT) network originally established for commercial ships traveling around the world in shipping lanes.	
 	 	 	 	 	 	
 	 	(ii)	Equipment included in the RC-1500- IT	 	GMDSS System, Imarsat C MES Felcom 12 complete set, MF/HF radio-telephone FS 1562-15 (150 watt) and FS-1562-25 (250 watt), FS-5000 (400 watt), FS-8000 (800 watt), NBDP Terminal dp-6, MF-HF DSC watch receiver AA-50, DSC terminal DSC-6 complete set printer, PP-510, printer selector	
 	 	 	 	 	 	
 	 	(iii)	VHF	 	Radio telephone with VHF DSC terminal FM-8500	
 	 	(iv)	Power Supply	 	Power supply unit with AC/DC charge over facility PR-300 (20 amp) and PR-850A (60 amp), S-5300 or S-8300 ( with Battery- charger)	
 	 	(v)	Helicopter Radio Beacon	 	Southern Avionics SS-500	
 	 	(vi)	Telex	 	Built in Marisat system	
 	 	(vii)	Communications in Life Boats	 	Three (3) VHF radios with channel selection	
 
115

 
 	B.	Interior/Exterior Communications	 	Gaitronics 5-Channel page/phone system	
 	 	 	 	 	 	
27.	OCEANOGRAPHIC and METEOROLOGICAL INSTRUMENTS	 	Weather station providing wind speed and direction.	
 	 	 	 	
28.	INSTRUMENTATION	 	 	
A.	Drilling Instrumentation	 	Petron drillers cabin containing Petron Networked Distributed Drilling Data (3D) Instrumentation System consisting of:	
 	 	 	 	 	1)	Integrated drilling recorder function	
 	 	 	 	 	2)	Dual rig floor touch screen display with dual master panel capability	
 	 	 	 	 	3)	Drilling data hub monitoring:	
 	 	 	 	 	 	 	a)	Top drive torque	
 	 	 	 	 	 	 	b)	Top drive RPM	
 	 	 	 	 	 	 	c)	Hydraulic hookload	
 	 	 	 	 	 	 	d)	Hydaulic tong torque	
 	 	 	 	 	 	 	e)	Crown sensor depth and ROP	
 	 	 	 	 	 	 	f)	Mud pump pressure (2 each)	
 	 	 	 	 	 	 	g)	Cement pump pressure	
 	 	 	 	 	 	 	h)	Casing/annular pressure	
 	 	 	 	 	 	 	i)	Flow sensor	
 	 	 	 	 	4)	Mud pit data hub monitoring:	
 	 	 	 	 	 	 	a)	Riser boost pressure	
 	 	 	 	 	 	 	b)	Mud pump strokes (3 each)	
 	 	 	 	 	 	 	c)	Mud pit volume 13 sensors in main mud pit system (3 pits have dual sensors) and 2 sensors in trip tank	
 	 	 	 	 	5)	Drilling data hub and Mud pit data hub are networked to workstation in Toolpusher’s office (and Company Representative office optional)	
 	 	 	 	 	6)	Drillers console consisting of controls, gauges, and lights for the control and monitoring of approximately 90 items.	
 	 	 	 	 	
 	B.	Deviation Recorder	 	Totco non-directional drift indicators, one (1) each 0-8 degrees and 0-16 degrees	
 	 	 	 	 	
29.	ADDITIONAL / OTHER	 	 	
 	A.	Storeroom	 	Computerized and air conditioned	

116

 
 	B.	CCTV System	 	Kongsberg Simrad fiber optic color system consisting of eighteen (18) cameras monitoring: eight (8) anchor winches, two (2) loading stations, two (2) ballast pump rooms, moon pool, riser tension ring, rig floor, top drive, monkey board and upper shale shakers, and nine (9) monitors: one (1) at each anchor winch control station, drillers console, Toolpusher office, Company man office, O.I.M. office, and Ballast Control Room.	
 
117

 
EXHIBIT A2 TO EXHIBIT A
 
118

 
Attachment A2 to Exhibit A — Scope of Work
 
Offshore Drilling Contract
 
EQUIPMENT, SUPPLIES, MATERIAL AND SERVICES
TO BE FURNISHED BY COMPANY AND CONTRACTOR
 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
100.	 	Contractor’s Equipment and Personnel	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
101	 	Drilling Unit and auxiliary equipment as listed in Attachment Al to Exhibit A.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
102.	 	Personnel as listed in Attachment A3 to Exhibit A, “Personnel to be Provided by Contractor”.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
103.	 	Subject to the provisions of Section 6.1(A)(4), extra personnel in excess of the normal complement listed in Attachment A3 to Exhibit A., for fully supporting full Drilling Unit operations for both well centers, excluding Operator supplied Third Party personnel. Extra personnel must be requested in writing by Company. Contractor shall provide such additional personnel as provided in Section 9.3.	 	 	 	 	 	X	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
104.	 	Overtime beyond normal work schedule for Contractor’s personnel when requested by Company. Overtime rates arc listed in Exhibit D, the “Compensation Schedule”.	 	 	 	 	 	X	 	 	 	 	
 
119

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
105.	 	Additional cost (i.e. overtime, lodging, transport, etc.) resulting from a required evacuation of the Drilling Unit due to bad weather.	 	 	 	X	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
106.	 	Subject to the provisions of Section 9.1, any additional equipment or modifications to the Drilling Unit requested by Company.	 	 	 	X	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
107.	 	Items replaced or repaired which are found to be defective during inspection and testing as described in Attachment A4 and A7 to Exhibit A. and to include all cost of replacement and repair.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
108.	 	Spare parts required to keep Contractor equipment in good operating order.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
109.	 	All spare parts and third party services to keep Company items in good operating order, unless otherwise specified in this Attachment A2.	 	 	 	 	 	 	 	X	 	 	
 
120

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
110.	 	Contractor to maintain adequate stocks of screens for the following equipment as listed below:	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	a.      For each type of shaker listed in Attachment A1 to Exhibit A., Contractor to provide all screens with equal or larger opening size that DX-84 or equivalent.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	b.      Company shall pay for screens smaller than 80 mesh.	 	 	 	X	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	c.      Any other Contractor owned equipment.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	d.      All other non-Contractor owned shale shaker and flow line cleaner screens.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
111.	 	Replacement parts for all solids control equipment listed in Attachment A1, other than shaker screens as listed in Item 110 above.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
112.	 	Drill pipe wipers for Contractor supplied drill pipe.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
113.	 	Re-circulating trip tank with Driller’s level readout.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
200.	 	GENERAL	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
201.	 	Offshore drilling permies) licenses and clearances, including Navy Permit Drilling site surveyed, marked and cleared of obstructions when required.	 	 	 	 	 	 	 	X	 	 	
 
121

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
202.	 	All radio equipment, including satellite communications, other than that provided by Contractor in Attachment Al to Exhibit A. Includes obtaining any necessary permits.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
203.	 	Radio permits and licenses for Contractor radio equipment. Company will assist Contractor in obtaining these permits if required by Contractor.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
204.	 	Telephone calls by Company on Contractor’s Fleet 77 satellite telephone. Calls by Company’s third party personnel must be authorized, logged and signed for by the Company representative on the Drilling Unit. The original documentation must accompany invoices.	 	 	 	 	 	X	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
205.	 	Telephone calls by Contractor on Company’s satellite telephone. These calls must be logged and authorized by the Company representative on the Drilling Unit.	 	 	 	 	 	 	 	 	 	X	
 	 	 	 	 	 	 	 	 	 	 	 	 	
206.	 	Telephone calls by Company’s third party personnel on Company’s satellite telephone.
 
The Radio Operator has the duty of controlling access to satellite telephones in the radio room and maintaining these logs.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
207.	 	Operating licenses and maintenance of Contractor vehicles.	 	X	 	 	 	 	 	 	 	 	
 
122

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at 
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
208.	 	Meals and quarters for all Contractor’s and Contractor’s subcontractor personnel and including all Company and Company third party personnel subject to the capacity of the Drilling Unit, as mentioned in Exhibit D, the “Compensation Schedule”.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
209.	 	Not Used.	 	 	 	 	 	X	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
210.	 	DrillingUnit positioning, weather forecasting, seabed survey and shallow hazard assessment services as required by Company, Contractor or Contractor’s underwriters surveyors.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
300.	 	Marine and Logistics	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
301.	 	Transport for Contractor personnel (listed in Attachment A3 to Exhibit A.) between Point of Origin and Point of Entry.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
302.	 	All transport for Contractor material and equipment between point of procurement and Company designated shore base.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
303.	 	Air or marine transportation of Contractor and Company personnel, material and equipment between Point of Entry and Drilling Unit in the course of normal duties. The means of transport is at the discretion of Company.	 	 	 	 	 	 	 	X	 	 	
 
123

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at 
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
304.	 	If Contractor requires a special flight to the drilling unit (for example for a tour by management or a prospective client) then this will be provided at Company’s discretion. An emergency flight for medical evacuation shall not be considered as a special flight.	 	 	 	 	 	 	 	 	 	X	
 	 	 	 	 	 	 	 	 	 	 	 	 	
305.	 	Transfer onto and from the Drilling Unit of all materials, equipment and personnel of Contractor and of Company. Contractor personnel shall not be placed on the work boats to assist loading and unloading the boats.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
306.	 	Standby and work/supply/towing vessel(s) as required (including fuel), including boats for moving needed Contractor’s equipment between Ghana and Equatorial Guinea. Standby boat requirements shall be determined by Company, or local laws.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
307.	 	Main towing line from Contractor cables to towing vessel(s) during moves between locations, including shock lines.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
308.	 	Towing bridle, pennant lines, and other associated towing gear, if required.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
309.	 	Replacement of supply vessel mooring lines initially supplied by Contractor which have been damaged during course of Company well.	 	 	 	 	 	 	 	X	 	 	
 
124

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at 
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
310.	 	Replacement of loading and unloading hoses on board Drilling Unit initially supplied by Contractor and damaged during course of Company well.	 	 	 	 	 	X	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
311.	 	Loading and unloading services at dock site or heliport of all material and equipment of Contractor and Company.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
312.	 	Shore base with quay site for loading out Contractor equipment, reasonable yard space required and dedicated to Contractor’s equipment.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
313.	 	a) Cargo baskets for use in transporting Contractor’s supplies on supply vessels. The baskets must be fit for purpose, marked with the load rating and equipped with suitable lifting certified slings and baskets.
 	 	X	 	 	 	 	 	 	 	 	
 	 	b) Cargo baskets for use in transporting Company’s supplies on supply vessels. The baskets must be fit for purpose, marked with the load rating and equipped with suitable lifting certified slings and baskets.	 	 	 	 	 	 	 	X

 	 	 	 	 	 	 	 	 	 	 	 	 	
314.	 	a) Wire rope certified slings for pre-slinging of Contractor furnished drill pipe and drill collars.
 	 	X	 	 	 	 	 	 	 	 	
 	 	b) Wire rope certified slings for pre-slinging of Company furnished drill suing and casing.	 	 	 	 	 	 	 	X	 	 	
 
125

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at 
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
315.	 	a) Replacement of metal slings damaged during loading or unloading of Contractor furnished drill pipe, drill collars and equipment as shown in Attachment Al to Exhibit A.
 	 	X	 	 	 	 	 	 	 	 	
 	 	b) Unless damaged at Company’s shorebase by non-contractor personnel.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
316.	 	Adequate open storage for Contractor equipment and spare parts at Company shore base while equipment is in transit to Drilling Unit.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
317.	 	Transfer of Contractor equipment and spare parts between Company shore base and quay.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
318.	 	Transfer of Contractor equipment and spare parts between Company shore base and third party locations.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
319.	 	Office for Contractor shore-based supervisory staff.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
320.	 	Office furniture and supplies for Contractor shore-based supervisory staff.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
400.	 	Drilling Equipment & Services	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
401.	 	Cementing unit rental.	 	 	 	 	 	 	 	X	 	 	
 
126

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at 
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
402.	 	All cementing services (other than the Cementing unit) and equipment in excess of that listed in Attachment Al to Exhibit A.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
403.	 	All cement and additives.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
404.	 	Mud engineering services (but Contractor will carry out routine mud testing and treatment as required).	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
405.	 	All drilling fluids and additives, including pallets if applicable.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
406.	 	Mud logging service.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
407.	 	All electric well logging services and equipment, including string shot and back-off equipment. Installation and removal of equipment.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
408.	 	Wireline formation testing, side wall sampling, hydraulic fracturing and acidizing.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
409.	 	a) Suitable space for locating well logging and mud logging units, mud lab and wireline workshop ROV, etc.
 	 	X	 	 	 	 	 	 	 	 	
 	 	b) Contractor shall install, run all necessary utilities (air, gas, water, etc) to this equipment at Company’s cost to the Company and Contractor originally agreed locations.	 	 	 	 	 	X	 	 	 	 	
 
127

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
410.	 	Fishing tools for all equipment except Contractor furnished drill pipe, HWDP, drill collars and downhole tools as shown in Attachment A1.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
411.	 	Fishing tools for all Contractor drill pipe, HWDP, drill collars, and downhole tools as shown in Attachment Al to Exhibit A.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
412.	 	Repair and/or replacement parts for Contractor provided fishing tools, if damaged during the performance of Services.	 	 	 	X	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
413.	 	Welding services required on Company’s equipment to the extent available from Contractor’s labor.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
414.	 	a)  Welding materials used on Company’s equipment.	 	 	 	 	 	X	 	 	 	 	
 	 	b) If time required by Company exceeds “reasonable” time, then Company to provide a third party welder.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
415.	 	Any geological or petroleum engineering services.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
416.	 	ROV or diving services, if required for maintenance or repair of Contractor’s Drilling Unit.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
417.	 	ROV or diving services, if required for work related to Company’s well or Subsea facilities.	 	 	 	 	 	 	 	X	 	 	
 
128

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
418.	 	Extra labor or casing crews for running casing or tubing.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
419.	 	Directional drilling engineering services and special equipment.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
420.	 	Jetting tools for setting 36” or 30” conductor casing.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
421.	 	Well test unit and associated equipment for production testing including services and including a separate air compressor for any compressed air needed such equipment, where they are not listed in Attachment Al to Exhibit A.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
422.	 	Drilling bits, mills (other than those listed in Attachment Al to Exhibit A for fishing), hole openers, reamers, under-reamers, casing scrapers, drilling bumper subs, shock subs, drilling safety joints, hydraulic drilling jars and similar downhole equipment, including replacement parts.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
423.	 	Drills stem testing equipment if required.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
424.	 	Handling tools, subs, etc. required for Company supplied drill pipe.	 	 	 	 	 	 	 	X	 	 	
 
129

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
425.	 	Inspection of riser, drill collars, HWDP, drill pipe, subs, pups and all downhole tools as shown in Attachment Al to Exhibit A, hoisting equipment and handling tools prior to spud of first well unless agreed to otherwise by both Parties.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
426.	 	Subsequent inspections when requested by Company except as indicated in Section 6.2.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
427.	 	Core barrel and core bits.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
428.	 	All third party services pertaining to the drilling, workover and completion operations.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
429.	 	Any drill pipe, HWDP, drill collars, subs, bits, reamers, hole openers, stabilizers, shock subs, and other downhole tools in excess of those provided by Contractor as shown in Attachment Al to Exhibit A.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
430.	 	Drill pipe floats for Contractor supplied drill strings as shown in Attachment Al.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
431.	 	Drill pipe floats for Company supplied drill strings.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
432.	 	Mud pump liners as specified by Company limited to two (2) sizes.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
500.	 	BOP and Wellhead Equipment	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
501.	 	BOP control fluid.	 	X	 	 	 	 	 	 	 	 	
 
130

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
502.	 	Initial set rubber goods for BOP stack as per BOP Manufacturer’s specification.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
503.	 	All ring gaskets between sub-sea wellhead or tree and BOP Stack.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
504.	 	Replacement rubber goods and ring gaskets, flex joint rubbers, including riser string seals, VBR packers, annular packing elements and diverter packers, for BOP stacks due to normal or abnormal wear and tear. This to be documented from initial inspection of rubber goods and end inspection of rubber goods. Rubber goods to be compatible for use in OBM, and SBM.	 	 	 	 	 	X	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
505.	 	New annular preventer, diverter and VBR elements and mud seals required at start of Contract. Contractor to keep spare annular preventer elements as mutually agreed on board the Drilling Unit at all times.
 
Company, by prior approval, may accept a used element(s) if relatively new and in good condition.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
506.	 	Replacement annular elements at end of Contract, if proven replacement is needed with documentation of initial and end condition.	 	 	 	X	 	 	 	 	 	 	
 
131

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
507.	 	Repair/replacement of Contractor Subsea well control equipment due to abnormal wear and tear such as key seating with documentation of initial condition and end condition and proven cause of damage.	 	 	 	 	 	X	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
508.	 	Replacement door seals for Contractor supplied BOPs when changed at Company’s request.	 	 	 	 	 	X	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
509.	 	Provide equipment to do BOP test independently. Contractor’s responsibility for this equipment is limited to test tools as currently equipped.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
510.	 	All wellhead and Subsea Equipment i.e., Subsea wellheads, hangers, pack offs, Christmas trees, corrosion caps, etc.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
511.	 	Running and retrieving tools for the following: LPWH, HPWH, casing hangers, pack-offs, wear bushings and nominal seat protectors.	 	 	 	 	 	 	 	X	 	 	
 
132

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
512.	 	Riser Fairings: Company has the discretion whether or not to install and/or replace riser fairings.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	a) Repair and/or replacement of Subsea riser fairings lost or damaged after initial installation.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	b) Repair and/or replacement of Subsea riser fairings lost or damaged before initial installation.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
513.	 	Subsea BOP test plugs, both isolation type and sealing inside the casing hanger.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
600.	 	Well Equipment & Supplies	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
601.	 	Fuel for all Contractors’ equipment on the Drilling Unit.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
602.	 	Helicopter fuel.	 	 	 	 	 	 	 	X	 	 	
 
133

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
603.	 	An inventory of fuel is to be taken as the Drilling Unit goes on and off contract, and signed for by the Company’s representative. Any balance will be reimbursed to the Contractor (if negative) or deducted from invoices (if positive) at Contractor’s documented invoiced cost.	 	 	 	 	 	X	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Contractor will assist Company by obtaining and documenting on and off contract inventories from supply and standby boats on location.	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
604.	 	Lubricants for:	 	 	 	 	 	 	 	 	 	 	
 	 	a) Contractor equipment	 	X	 	 	 	 	 	 	 	 	
 	 	b) Drill string provided by Contractor.	 	X	 	 	 	 	 	 	 	 	
 	 	c) Drill string provided by Company	 	 	 	 	 	 	 	X	 	 	
 	 	d) Casing and Company provided equipment	 	 	 	 	 	 	 	X	 	 	
 	 	Note: if specialized lubricants are required for Company supplied Drill String, then Company shall be responsible for Company’s cost.	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
605.	 	The following items, including all consumable items used therewith:	 	 	 	 	 	 	 	 	 	 	
 	 	a) All conductor pipe	 	 	 	 	 	 	 	X	 	 	
 	 	b) All casing, attachments and other well tangibles	 	 	 	 	 	 	 	X	 	 	
 	 	c) All tubing	 	 	 	 	 	 	 	X	 	 	
 	 	d) All completion equipment	 	 	 	 	 	 	 	X	 	 	
 
134

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
606.	 	Potable water for use on board the Drilling Unit, to the extent of the capacity of the Drilling Unit’s water makers.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
607.	 	Any potable water required in excess of the capacity of the Drilling Unit’s water makers and any drill water above that provided by surplus potable water.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
608.	 	a) Any fabrication material (e.g. steel, cable) provided by Contractor to assist in rig up of Company third party equipment.	 	 	 	X	 	 	 	 	 	 	
 	 	b) Company to supply labor to install.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
609.	 	All rope, cargo slings (for use on Drilling Unit), hand tools and general Drilling Unit consumables.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
700.	 	Waste	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
701.	 	a) Trash compactor.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	b) Bags for Contractor waste.	 	 	 	X	 	 	 	 	 	 	
 
135

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
702.	 	a) Disposal of Contractor’s Victual waste, if required by 33 CFR 151, garbage, refuse and other non-hazardous waste, in Contractor furnished containers.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	b) Disposal of Company’s and Company’s other contractor’s Victual waste, if required by 33 CFR 151, garbage, refuse and other waste, in Company furnished containers.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
703.	 	a) Disposal of Contractor’s scrap metal, drill lines, drums and other containers that have been emptied, drained and interior cleaned with water or other cleaning agents.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	b) Disposal of Company’s scrap metal, drums and other containers that have been emptied, drained and interior cleaned with water or other cleaning agents.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
704.	 	Disposal of Contractor’s waste oil, waste paint and other hazardous waste generated by Contractor’s Drilling Unit, equipment or personnel, or Contractor’s subcontractor personnel and/or equipment during the Contract. Containers to he provided by Company.	 	 	 	 	 	 	 	X	 	 	
 
136

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
705.	 	Disposal of Company’s waste oil, waste paint, or other hazardous waste generated by Company’s or Company’s other contractors personnel and/or equipment during the Contract. Containers to be provided by Company.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
706.	 	Clean out of Oil Storage tanks and disposal of contents, including brine, base oil and synthetic base materials, at the end of the Contract to be performed by Company, if required.	 	 	 	 	 	X	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
800.	 	Safety	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
801.	 	All safety equipment for Contractor personnel, including self-contained breathing apparatus for emergency work in H 2 S environments as shown in Attachment Al to Exhibit A to he provided by Company.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
802.	 	Self contained breathing apparatus for work in H 2 S environment in excess of that furnished by Contractor as shown in Attachment Al to Exhibit A, and/or a cascade breathing system.	 	 	 	 	 	 	 	X	 	 	
 
137

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
803.	 	a) Safety equipment (e.g. floats, life belts, work vests, PPE, fire extinguishers, etc.) for the total complement on board the Drilling Unit.
 	 	X	 	 	 	 	 	 	 	 	
 	 	b) Company shall provide safety equipment, such as work boots, hard hats, gloves and safety glasses and other safety firefighting gear for third party equipment, office and buildings belonging to Company’s other contractors.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
804.	 	Provide explosion-proof wiring and lighting for Contractor’s Drilling Unit and ancillary equipment as required by all applicable regulations.	 	X	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
805.	 	All Company’s or its other contractors’ equipment, materials or supplies to be brought on board the Drilling Unit shall he provided with slings properly certified for the load.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
806.	 	All Company’s or its other contractors’ equipment to be brought on board the Drilling Unit shall be properly inspected and certified as appropriate including but not limited to certifications of’ pressure vessels, and appropriate electrical zoning certifications prior to being placed in service on board the Drilling Unit.	 	 	 	 	 	 	 	X	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Company shall have all its other contractors’ utilize this Contractor’s equipment checklist.	 	 	 	 	 	 	 	 	 	 	
 
138

 
 	 	 	 	Furnished By	
Item
No.	 	DESCRIPTION	 	Contractor at
Contractor’s Cost	 	Contractor, at
Company’s cost, plus
applicable handling
charge	 	Contractor, at
Company’s cost, no
handling charge	 	Company at
Company’s Cost	 	Company at
Contractor’s Cost	
807.	 	Company or its other contractors shall provide MSDS on all chemicals Company or its other contractors bring on board the Drilling Unit.
 
These records must be current at all times.	 	 	 	 	 	 	 	X	 	 	
 
End of Attachment A2
 
139

 
EXHIBIT A3 TO EXHIBIT A
 
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Attachment A3to Exhibit A — Scope of Work
 
Offshore Drilling Contract
 
PERSONNEL TO BE FURNISHED BY CONTRACTOR
 
1.            Number and Classification of Contractor’s Personnel, as per Section 6.1(A)(1); Personnel Rates as per Sections 1.1.1 and 6.1(A)(7): arc shown in the table below.
 
ATWOOD HUNTERCREW COST SCHEDULE
 
 	 	Daily Straight Time 2:	 	Hourly Overtime 3.	 	Hourly Overtime	
SHORE BASED	 	 	 	 	 	 	
Manager	 	674	 	N/A	 	 	
Superintendent	 	626	 	N/A	 	 	
Administrator	 	382	 	N/A	 	 	
RIG BASED	 	 	 	 	 	 	
Toolpusher	 	636	 	N/A	 	 	
Tourpusher	 	544	 	 	 	 	
Barge Captain	 	521	 	 	 	 	
Rig Maintenance Supervisor	 	473	 	 	 	 	
Driller	 	398	 	 	 	66	
Asst. Driller	 	298	 	 	 	50	
Derrickman	 	155	 	 	 	26	
Floorman	 	125	 	 	 	21	
Subsea Engineer	 	511	 	 	 	90	
Roustabout	 	110	 	 	 	18	
Crane Operator	 	311	 	 	 	52	
Welder	 	317	 	 	 	53	
Rig Mechanic	 	429	 	 	 	72	
Rig Electrician	 	429	 	 	 	72	
Swing Elec/Mech	 	429	 	 	 	72	
Motorman	 	125	 	 	 	21	
Materialsman	 	290	 	 	 	48	
OffSzhore Systems Admin	 	290	 	 	 	48	
Rig Medic	 	311	 	 	 	57	
Radio Operator	 	105	 	 	 	18	
Camp Boss	 	301	 	 	 	50	
Cook	 	264	 	 	 	44	
Utility	 	100	 	 	 	17	
Control Room Operator	 	373	 	 	 	62	
 
Note : For Operating Segments referred in Section 3.2 A.2and 3.2 A.4, of the Contract, only the Operations Superintendent will be in Equatorial Guinea.
 
Notes for Attachment A3 Table above:
 
·             The figures in column “A” are to be used as the basis for adding personnel to the permanent crew and for determining the credit for crew members short. This includes all Training, Transportation and Catering costs.
 
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·             It is understood from time to time that there may be a shortfall in certain positions that Contractor makes up for by overtime in equivalent positions or (e.g. Floorman staying over to work in a roustabout position) as reflected in the daily drilling report (IADC report). Any downsizing of the crew requested by Company shall be documented in writing to Contractor.
 
·             The figures in column “C” are the hourly cost of overtime including Training, Transportation and Catering costs.
 
·             The positions denoted with an asterisk (*) are to be fluent in English as per Section 6.1 (A)(7) and for the purposes of this Contract are designated as Key Personnel which may not be replaced or substituted without prior Company approval. Such Key Personnel experience level requirements will be supplied to and agreed by Company.
 
·             Key Personnel may not be changed out without the consent of Company.
 
·             The Contractor shall provide all necessary shorebased administration and management support to fulfill its obligations under this Contract.
 
2.            All Contractor’s Personnel must be conversant in English.
 
3.            Offshore Contractor Personnel Qualifications
 
3.1          The following offshore positions would be expected to be filled by staff with a minimum of five (5) years’ experience on floating or semi-submersible drilling units and who arc fluent in conversational English and who are accomplished in reading and writing English:
 
·       Senior Toolpusher
 
·       Toolpusher
 
·       Driller
 
·       Assistant Driller
 
·       Barge Engineer
 
·       Senior Mechanic
 
·       Senior Electrician
 
·       Crane Operator
 
All other positions shall be filled by staff who have had previous offshore drilling experience. Contractor shall provide Company with resumes of all expatriate staff to be assigned to the project. Company reserves the right to reject Contractor’s proposed personnel.
 
3.2          Minimum Rig Personnel Qualifications Expected By Company
 
Senior Toolpusher	 	(1)	 	(12)	 	(13)	 	(14)	 	(16)	 	 	
Toolpusher	 	 	 	(2)	 	(12)	 	(13)	 	(14)	 	(16)	
 
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Driller	 	 	 	(3)	 	(12)	 	(13)	 	(14)	 	(16)	
Assistant Driller	 	(4)	 	(12)	 	(13)	 	(14)	 	(16)	 	 	
Senior Mechanic	 	 	 	 	 	(5)	 	(14)	 	(16)	 	 	
Senior Electrician	 	 	 	(6)	 	(11)	 	(16)	 	 	 	 	
Crane Operator	 	 	 	 	 	(7)	 	(14)	 	(16)	 	 	
Barge Engineer	 	 	 	(8)	 	(14)	 	(15)	 	(16)	 	(17)	
Medic	 	 	 	 	 	(16)	 	(18)	 	 	 	 	

(1)          10 years experience in all phases of onsite drilling operations. Minimum 2 years’ experience as a Senior Toolpusher on floating / semi-submersible rigs.
(2)          10 years’ experience in all phases of onsite drilling operations. Minimum 1 year experience as a Toolpusher on floating / semi-submersible rigs.
(3)          8 years’ experience in all phases of onsite drilling operations. Minimum 2 years’ experience as a Driller on floating / semi-submersible rigs.
(4)          5 years’ experience in drilling operations. Minimum 1 year as an Assistant Driller on floating / semi-submersible rigs.
(5)          5 years’ experience in maintaining and operating related equipment on a drilling unit.
(6)          5 years’ experience in maintaining and operating SCR or AC-DC electrical equipment on an offshore drilling rig.
(7)          5 years’ experience as Crane Operator, minimum 3 years’ onboard offshore drilling units. Minimum 1 year operating experience as a Crane Operator on floaters. Crane Operators must also have current certification.
(8)          5 years’ operating experience in offshore drilling operations. Must have thorough knowledge of marine and international regulatory body requirements as they apply to offshore drilling operations. Minimum 1 year as Bargemaster on same type of Drilling Unit in drilling mode.
(9)          5 years’ experience in operating and maintaining subsea blowout prevention control equipment.
(10)        3 years’ experience in warehousing, inventory, and maintenance of adequate stock levels. Must have knowledge of offshore drilling equipment and computerized inventory control systems.
(11)        5 years’ experience in offshore drilling and marine operations on floaters.
(12)        Current valid IWCF, American MMS-OCS, Norwegian NPD, or IADC well control certification. Valid shall mean that all well control certificates have not lapsed in accordance with certifying authority. This certificate must be valid for the position in which the individual is employed, i.e., toolpusher with a drillers certificate is not acceptable
(13)        H2S control and operation certification.
(14)        Safety, first aid, and fire fighting certification.
(15)        Master MODU or Unlimited Master’s license.
(16)        Proficient English language skills.
(17)        Ballast Control Operators Ticket.
(18)        Trained and certified to international standards as a Medic. Proficient in English language skills.
 
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Copies of all certificates shall be made available to Company prior to commencement of contract.
 
4.            Shore Base Personnel
 
4.1          The shore-base Drilling Superintendent shall have a minimum of two years as Drilling Superintendent for Contractor’s rig or a rig of similar design.
 
4 2          Shore-base personnel minimum requirements.
 
Drilling Rig Manager	 	(1)	 	(2)	 	(3)	 	(4)	 	 	 	 	

(1)          15 years’ experience in all phases of onsite drilling operations, including 5 years’ offshore experience as Senior Toolpusher/Rig Superintendent.
(2)          Current Well Control certification.
(3)          H2S control and operation certification.
(4)          Proficient English language skills.
 
5.            General
 
All senior staff positions shall work 28 days on and 28 days off.
 
Contractor may not change senior staff personnel without prior approval from Company, such approval shall not be unreasonably withheld.
 
All drill crew personnel shall be fluent in English and are required to have an up to date well control certificate. This certificate must be valid for the position in which the individual is employed, i.e., toolpusher with a drillers certificate is not acceptable. The certificate should be recognized by an appropriate governmental regulatory agency such as the US MMS or IWCF.
 
End of Attachment A3
 
144

 
EXHIBIT A4 TO EXHIBIT A
 
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Attachment A4 to Exhibit A — Scope of Work
 
Offshore Drilling Contract
 
DRILLING UNIT COMMISSIONING, INSPECTION AND
ACCEPTANCE REQUIREMENTS
 
Company requires a full acceptance inspection of the Drilling Unit prior to the Commencement Date of the Contract. Following is a general description of the scope of the inspection.
 
1.            Full Drilling Unit Acceptance Inspection.This survey is an in-depth visual inspection and function testing of all Drilling Unit equipment. This includes  but is not limited to  full inspections of mud pumps, rotary table, drawworks and internal inspection of other vital equipment. The scope of the inspection will include:
 
·       Visual examination to confirm equipment condition and standards of maintenance, and verification of compliance with applicable API standards and recommended practices and other criteria as mutually agreed per the applicable sections of Attachments A4, A5, A6 and A7 of this Contract.
 
·       Opening all major items of equipment for internal inspection as requested by Company, for the purpose of performing an examination of components and ancillary parts for excessive wear, damage, cracks and other defects and for measurements of clearances.
 
·       Function testing, pressure testing, load testing, and insulation resistance checks for all equipment as requested by Company, as applicable, will he conducted.
 
·       Checking that the proper safety devices are installed and are working correctly to prevent accidents and equipment failures.
 
·       Evaluating the efiectiveness of the preventive maintenance program and maintenance record management prior to the Commencement Date of the Contract.
 
2.            InspectionProcedures.Drilling Unit inspections (except for subsea blow out preventer and control systems) will normally be conducted by two third-party independent consultants selected by and at the expense of Company. All other costs associated with the inspection shall be at the expense of the Contractor. The inspection shall be conducted during a rig move, in shipyard or when stacked Criteria used for rejection of equipment through this Attachment A4 to Scope of Work shall be mutually agreed between Company and Contractor.
 
The minimum number of Contractor’s personnel required for assistance are: Toolpusher, Assistant Driller, Derrickman, Mechanic, Electrician, Barge Engineer and two helpers.
 
The time required for a full inspection is normally six days for two rig inspectors. All rig time required for inspection and required repairs, if any, shall be at Contractor’s expense, unless otherwise indicated in Attachment A2 to Exhibit A - Scope of Work.
 
3.            DetailedDescription of Inspection Program.The fullacceptance program consists of the
 
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following:
 
Drilling Equipment: The Drilling Equipment Inspection section specifically relates to equipment listed in Attachment Al to Exhibit A - Scope of Work. Contractor shall submit its maintenance system for review by Company. If found acceptable, Contractor may submit documentation for review and acceptance by Company that is generated from Contractor’s maintenance system verifying the most recent inspections as indicated in Table V. Credit for such inspections shall be granted by Company if it can be demonstrated that the scope of such inspections meets the intent of API RP8B and API RP7L, and that the inspections have been carried out in accordance with the frequencies specified in Contractor’s maintenance system and meet the maintenance and recommended practices and alerts of the manufacturer. In addition, Contractor shall provide documentation to substantiate that such equipment has not been operated over 90% of its rated load capacity since such inspections were performed in order to receive credit. Random checks of the equipment may be specified by Company to the extent necessary to substantiate that the equipment is in serviceable condition. For equipment that is randomly selected for inspection, these items shall he comprehensively reviewed with inspection covers shall be removed to the extent necessary fbr access for visual inspections, measurement of tolerances and clearances, as well as a detailed examination of the mechanical and electrical condition of the equipment.
 
Hoisting Equipment: Drawworks, Rotary Table, Swivel, Crown Block, Traveling Block, Hook, Top Drive.
 
Pipe Handling Equipment: Automatic Pipe Handling Systems, Pipe Spinning Wrench, Tongs, Slips and Safety Clamps, Elevators, Casing Tongs, Spiders, and Elevators.
 
Drilling Fluids Equipment: Mud Pumps, Shale Shakers, Desilters, Desanders, Degasser, Mud Centrifuge, Mud Agitators, Centrifugal Pumps, Standpipe Manifold and Rotary Hoses, Mud Cleaner, Mud Mixing System.
 
Miscellaneous: Drilling Instrumentation, Derrick/Casing Stabbing Board, Tuggers and Sheaves, Man Riding Winches, Survey Line, Well Testing Equipment, Drill String Components.
 
4.            DrillingUnit Floor and Derrick.This inspection ensures the standards of maintenance and safe working order of all derrick fittings and fixtures. Auxiliary drilling equipment items are also examined in accordance with Section 3 above, together with a review of drilling tool and tubular NDE inspection records.
 
5.            Well Testing Equipment.All aspects of the production equipment support pipelines (which belong to the rig) are included in this section together with review of the current condition and performance of the support equipment.
 
6.            BulkSystem. The performance of the bulk systems shall be verified by function testing of the system.
 
7.            Mud System.The mud system inspection relates to all aspects of mud mixing, storage, cleaning, and pumping, including the mud pits, together with the centrifugal pumps, agitators, ventilation, pipework and related systems. All mud cleaning equipment is inspected, including shale shakers, degasser, de-sanders, de-silters, and mud cleaners. The mud pumps are given a detailed mechanical/electrical review. Also included is the high pressure mud system from the mud pumps to the top drive or swivel.
 
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8.            Electrical.The electrical system inspection includes an insulation resistance check which highlights problem areas within all DC motors, critical system AC motors (as defined by Contractor’s maintenance system and accepted by Company), generators, and transformers. The Elmagco brake is highlighted for particular attention with regard to the brake monitoring and backup power supply systems; electrical supply to living quarter, rig floor and other parts of the rig will be inspected for proper installation and usage.
 
9.            Power Generation.Afull condition and performance review of all power generation and diesel engines and generators, the emergency generator, propulsion systems, air compressors and water makers to ensure safe, reliable service. All equipment safety features are checked and tested where appropriate, including the main engine shutdowns and pressure relief valves.
 
10.          Maintenance Management.Maintenance programs, procedures and historical files are reviewed to establish standards and efficiency.
 
11.          Safety Systems and Equipment Check.General Rig Safety, Gas Detection System, Fire Control System, Automatic Fire Detection System, CO2 Fire Control System, Fire Stations, Extinguisher and Firefighting Equipment, Heli-deck Foam System, Survival and Lifesaving Equipment, Lifeboats, Davit-Launched Life Raft Stations, Escape Routes, Breathing Apparatus, Helicopter Facilities, Drilling Facilities, First Aid Stations and Sick Bay, Emergency Procedures, Living Quarters, Potable Water Maker and Potable Water System, Sewage System, Pollution Control, Work Permits and General Housekeeping. Company may credit inspections documented in Contractor’s maintenance system that have been performed within established frequencies and in accordance with manufacturer’s recommended practices, as well as all current and valid certification surveys conducted by classification surveys.
 
12.          Certification.The current status of the rig is reviewed with regard to the required certification which should be available. Certification inspections which will fall due within the duration of the Contract are highlighted, together with any deficiencies which may be problematic. Certification of lifting gear and appliances including the registrar in place are examined.
 
13.          Safety Management.The safety programs, level of training and certification, emergency procedures, documentation systems and procedures mar he reviewed to establish the standard and efficiency of the safety management system.
 
14.          Barge Equipment. Ballast and Bilge System, Overflow and Vents, Watertight Integrity/Watertight Compartments, Mooring System, Bulk Air System and Tanks, Registration and Classification, Communication Equipment, General Operations.
 
The Drilling Unit acceptance inspection will also document the status of required equipment to ensure the Drilling Unit is in compliance with the equipment specified in Attachment Al to Exhibit A — Scope of Work.
 
A copy of the written report will be given to Contractor following the inspection. All deficient items shall be repaired and/or replaced at Contractor’s expense prior to the Commencement Date of the Contract.
 
End of Attachment A4
 
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EXHIBIT A5 TO EXHIBIT A
 
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Attachment A5 to Exhibit A — Scope of Work
 
Offshore Drilling Contract
 
DRILL STRING COMPONENT INSPECTION REQUIREMENTS
 
The Drilling Unit and all associated equipment are subject to inspection and acceptance testing by COMPANY and/or its agents. Said inspection is without prejudice to CONTRACTOR’s obligation to provide a rig and associated equipment which are fully capable of performing in accordance with good international petroleum industry practice and which conform to CONTRACTOR’s listing and description of said rig and equipment in Schedule “C”, Section I. By performing this inspection, neither COMPANY nor its agents warrant the seaworthiness or operational safety of CONTRACTOR’s rig or equipment, and in no way are the indemnity provisions as set forth in this Contract affected by this inspection.
 
The parties acknowledge that the Drilling Unit will be mobilizing to COMPANY’s well location immediately following the completion of drilling operations with the previous operator or upgrade project. Accordingly, COMPANY will keep Drilling Unit inspections to a minimum so as to avoid undue delays and interruptions to the Drilling Unit’s drilling operations. All delays arising from inspections will be conducted at the Standby Day Rate.
 
DRILL PIPE AND BOTTOM-HOLE ASSEMBLY (BHA) REQUIREMENTS
 
A.                    When new, drill string components shall have met the following requirements:
 
COMPONENT	 	MINIMUM REQUIREMENTS OUTLINED IN	
 	 	 	
Drill pipe	 	API Specification 5D	
Tool joints	 	API Specification 7	
Drill collars	 	API Specification 7	
Subs	 	API Specification 7	
 
Whenever so requested by COMPANY, CONTRACTOR shall furnish satisfactory evidence, traceable to the specific components furnished, that the above requirements were met when the components were new.
 
B.                      On the date of this contract, drill string components shall meet the requirements of Standard DS-1, Service Category Level 4, latest edition, including the following:
 
COMPONENT	 	MINIMUM REQUIREMENTS	
 	 	 	
Drill pipe	 	Premium Class	
Tool joints	 	Premium Class	
 	 	 	
Drill collar OD	 	 	
 
Minimum requirements of Standard DS-1, Service Level Category 4. Bottom-Hole Assembly will comply with the bevel diameter range, as listed in Table 3.8 in DS-1, Volume 3, 3rd Edition, to standards applicable when purchased.
 
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DRILL STEM INSPECTION
 
A.                           Methods and Procedures
 
1.                        Drill pipe, tool joints, drill collars, HWDP, subs, and all rotary-shouldered connections on any drill string component shall be inspected in accordance with the requirements of Standard DS-1 for Service Category Level 4. Inspection shall be performed by a third party inspection company. CONTRACTOR shall furnish COMPANY with a copy of the inspection report, and all components shall be marked as required in Standard DS-1. COMPANY may require that inspections be witnessed by a COMPANY representative, at COMPANY’s expense.
 
2.                        All specialty equipment, such as hole openers, underreamers, drilling jars, roller reamers, floor safety valves, and IBOP’s shall be inspected internally and function tested in the manner prescribed by their manufacturers. CONTRACTOR shall furnish satisfactory evidence that these inspections were satisfactorily completed.
 
B.                           Frequency
 
Drill string components shall be inspected by a third party inspection company at the beginning of this contract and then no less frequently than the intervals below:
 
COMPONENT	 	INSPECTION FREQUENCY	
 	 	 	
Drill pipe and tool joints	 	1500 rotating hours	
 	 	 	
Drill collars, HWDP, stabilizers, hole openers, underreamers, drilling jars, roller reamers, floor safety valves, and IBOP’s	 	300 rotating hours (Excluding back reaming time.)	
 
CONTRACTOR shall furnish COMPANY with a copy of the inspection reports. COMPANY may require that inspections be witnessed by a COMPANY representative, at COMPANY’S expense. Hevi-wate Drill Pipe will comply with the dimensional criteria as listed in Table 3.9.1 on page 137 of DS-1, Volume 3, 3rd Edition, to standards applicable when purchased.
 
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EXHIBIT A6 TO EXHIBIT A
 
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Attachment A6 to Exhibit A — Scope of Work
 
Offshore Drilling Contract
 
DRILLING HOISTING EQUIPMENT INSPECTION REQUIREMENTS
 
Inspection shall be carried out as per requirements stated in API  RP 8B. Inspection categories arc as follows:
 
Category I:	 	Observation of equipment during operation for indications of inadequate performance. When in use, equipment shall be visually inspected on a daily basis for cracks, loose fits or connections, elongation of parts, and other signs of wear, corrosion or overloading. Any equipment found to show cracks, excessive wear, etc., shall be removed from service for further examination. The equipment shall be visually inspected by a person knowledgeable in that equipment and its function.	
 	 	 	
Category II:	 	Category I inspection, plus further inspection for corrosion, deformation, loose or missing components, deterioration, loose or missing components, deterioration, proper lubrication, visible external cracks, and adjustment.	
 	 	 	
Category III:	 	Category II inspection plus further inspection, which should include NDT of critical areas and may involve some disassembly to access specific components and identify wear that exceeds the manufacturer’s allowable tolerances.	
 	 	 	
Category IV:	 	Category III inspections, plus further inspection for which the equipment is disassembled to the extent necessary to conduct NDE of all primary load carrying components as defined by the manufacturer. Equipment shall be disassembled in a suitably-equipped facility to the extent necessary to permit full inspection of all primary load carrying components and other components that are critical to the equipment; as well as inspected for excessive wear, cracks, flaws and deformations. Corrections shall be made in accordance with the manufacturer’s recommendations.	
 
It isthe Contractor’s responsibility to develop, submit for Company approval and follow a schedule of inspections as specified by Contractor’s maintenance system. This schedule shall be based on consideration of OEM recommendations, operating experience, equipment age and usage, ambient conditions, regulatory requirements, inspection and testing results, previous repairs, loading and loading cycles and other measurable life-cycle criteria, such as running hours or ton-miles, etc. If Contractor’s maintenance system does not specify the scope and frequency of inspections of hoisting equipment, the table below shall be used.
 
In addition, inspection Category III (min.) shall be performed prior to the following:
 
·                                         A Drilling Unit entering a long term Contract. Long term includes a period of one or more year(s).
·                                         A Drilling Unit entering a contract where harsh drilling conditions are anticipated and/or will be drilling in a sensitive location.
 
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·                                         Equipment being subjected to heavy load conditions. Heavy load conditions include loads equal to or greater than seventy percent (70%) (min.) of rated capacity.
·                                         A Drilling Unit will be subjected to low temperature drilling conditions that are below the documented temperature rating of the equipment.
 
End of Attachment A6
 
154

 
EXHIBIT A7 TO EXHIBIT A
 
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Attachment A7 to Exhibit A — Scope of Work
 
Offshore Drilling Contract No.
BOP ACCEPTANCE, INSPECTION AND TESTING; WELL CONTROL
SYSTEMS ACCEPTANCE, INSPECTION AND TESTING
 
1.1               Prior to rig mobilization, COMPANY reserves the right to conduct, at its cost, with CONTRACTOR’s equipment and personnel, a successful BOP and Control Systems Test in accordance with manufacturers specification to COMPANY’s satisfaction. This test is to be witnessed by a Company representative. Successful completion of this test is required before Company will accept the Drilling Unit for performance of the work hereunder. If the test is not successful at the first attempt then Contractor will use its best efforts to take remedial action necessary and will repeat the BOP test at no cost to COMPANY.
 
The initial BOP test shall also be subject to the provisions of Clause 20.2 of the Contract.
 
BOP Inspection and Testing
 
BOP equipment acceptance criteria will be based on COMPANY and the Equipment Manufacturer’s specifications. All installed and replacement parts shall be from the original manufacturer. No other parts are acceptable. All tests shall be successfully completed prior to spudding the first well. An Equipment Manufacturer’s Representative shall be made available on site if deemed necessary by the COMPANY Representative conducting acceptance Inspection and testing. One (1) CONTRACTOR subsea engineer shall be on site during the acceptance testing. The testing procedure shall be reviewed by the COMPANY Representative prior to starting the testing program, and all test objectives will be discussed and clearly outlined. Every effort should be made to perform the testing in the order listed.
 
Visual Inspection
 
CONTRACTOR shall provide preventive maintenance records on equipment as required by the COMPANY Representative. Visual inspection shall be carried out, where deemed necessary by the COMPANY Representative, so as to confirm use of original manufacturer’s parts and implementation of manufacturer’s preventive maintenance program. This includes, but is not limited to, the following:
 
(a)          Visually inspect annular for seal condition and bore wear.
 
(b)          Flex joint (ball joint) for Internal bore wear and its choke and kill stabs.
 
(c)          Fail-safe valves shall be disassembled. Gates and scats shall be examined for wear.
 
(d)          Rams (Doors Open).
 
·     Bore for wear and damage.
·     Top seal area for wear and damage.
·     Condition of ram blocks and seals.  Confirmation rubber goods are original manufacturer’s parts.
 
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·     Ram door seals and seal areas.
·     Dimension of ram cavities
·     Roughness of bonnet sealing faces
 
(e)         General Inspection
 
·     Condition of control hoses.
·     Choke and kill line hoses and stabs.
·     Guidance structure.
·     Inspect seal ring grooves.
·     Check accumulator pre-charge pressure and adjust if necessary.
·     Flush pilot line hoses in both pods.
·     Slip joint.
·     Diverter packing elements.
·     Reserve spare parts inventory.
·     Confirm only crimp on hose fittings and stainless steel piping is used on all subsea stack equipment.
 
BOP and Related Equipment Operator Tests
 
All operators (except annular) to be tested to a minimum of 3000 psi via hot line test hose with pressure gauge and isolation valve. The location of the pressure gauge and hot line will be further than 10 feet from the operator. All operators to be tested twice, once from each side of the accompanying shuttle valve. All hoses must be marked prior to removal. Test rams with ram blocks off so that rubber goods are not damaged.
 
(a)       Rams (doors open) - with control hoses removed at the shuttle valve, test open and close operators. Ram-locking functions to be checked at this time.
 
(b)       Annular - with control hoses removed at the shuttle valves, test open and close operators to a maximum pressure of 1500 psi.
 
(c)       Wellhead and LMRP connectors - with control hoses removed at the shuttle valve, test all lock and unlock functions to 3000 psi.
 
(d)       All backup control systems to be test to 3000 psi.
 
(e)       ROV stabs: Minimum hookup.
 
BOP and Related Equipment Pressure Tests (Test Stump)
 
(a)       All rams, valves and wellhead connectors to be pressure tested to:
 
250 psi	5 minutes	
10000 psi	10minutes	
 
(b)       Annular(s) pressure test to:
 
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250 psi	5 minutes	
70% of Rated Working Pressure	10 minutes	
 
All tests to be recorded on chart recorder. VBR rams to be tested for pipe size to be used during operations.
 
BOPs and Control System Function Tests
 
After connecting the control hoses, all functions, except annulars, to be tested with ± 3000 psi control pressure (after assembly is completed):
 
(a)       Check that all functions are hooked up properly.
 
(b)       Check all hoses and fitting for leaks.
 
(c)       Check control system for leaks.
 
A second function test at normal operating pressure (1500 psi) to be conducted to record function times and fluid volumes for each function. Maximum permissible response times, as per API:
 
Rams	45 seconds	
Annulars	60 seconds	
 
It is important that this test be conducted last. After the test is complete, no hoses, fittings, etc., should be changed or disconnected without approval of the COMPANY Representative.
 
Hydraulic Closing System Test
 
Test to ensure that accumulator has enough capacity, without the assistance from the charging system, to open and close all rams and one bag-type preventer with a minimum pressure of 200 psi above the pre-charge pressure.
 
Summary
 
To ensure that the above test procedure is conducted in the most efficient and time effective manner, the following are recommended:
 
(a)       Detail schematics of the BOP and BOP control system be available on the Drilling Unit.
 
(b)       Proper working condition of control flowmeter and read-back pressure gauges is necessary prior to finalizing the acceptance testing.
 
(c)       CONTRACTOR should have one (1) qualified subsea engineer who is fluent in English available to provide 24-hour operation.
 
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(d)       Have all doors on the BOP stack open prior to arrival of COMPANY’s representative on the Drilling Unit
 
(e)       All lights on all panels shall be tested and functional.
 
(f)        All functions shall be operated from the remote panels to confirm working order.
 
(g)       An Equipment Manufacturer’s Representative shall be made available on site if deemed necessary by the COMPANY Representative.
 
(h)       Any changes to the system after testing shall be reviewed prior to the change by the COMPANY Representative.
 
(i)        CONTRACTOR shall, at his cost, repair or replace items not meeting manufacturer’s specifications or wear tolerances.
 
(j)        Final test acceptance shall be on the date COMPANY’s Drilling Manager gives CONTRACTOR written notice that COMPANY is satisfied that the BOP and Control System meets all COMPANY requirements.
 
l.2   All such inspections required by COMPANY will be paid by COMPANY. A satisfactory result of these inspections shall be required prior to Drilling Unit acceptance.
 
1.3  Subject always to the provisions of Exhibit 3, COMPANY and CONTRACTOR agree to the following in relation to the BOP test: CONTRACTOR shall ensure adequate personnel resources are available to ensure timely execution of the BOP inspection.
 
Nothing contained within this ATTACHMENT A7 shall prejudice COMPANY’s rights contained elsewhere within the Agreement.
 
End of Attachment A7
 
159

 
EXHIBIT A8 TO EXHIBIT A
 
160

 
Attachment A8 to Exhibit A — Scope of Work
 
Offshore Drilling Contract
 
ENVIRONMENTAL, SAFETY, FIRE AND HEALTH SYSTEMS AUDIT AND INSPECTION
 
This exhibit is not applicable
 
161

 
EXHIBIT A9 TO EXHIBIT A
 
162

 
Attachment A9 to Exhibit A — Scope of Work
 
Offshore Drilling Contract
 
CONTRACTOR’S SAFETY MANAGEMENT SYSTEM
 
TO BE REVIEWED AND ADDRESSED BY THE PARTIES IN THE BRIDGING DOCUMENT
 
TABLEOF CONTENTS
 
Section	 	Contents	
 	 	 	
1.0	 	PURPOSE	
 	 	 	
2.0	 	SCOPE	
 	 	 	
3.0	 	REFERENCES	
 	 	 	
4.0	 	DEFINITIONSand ABBREVIATIONS	
 	 	 	
5.0	 	ORGANIZATION AND RESPONSIBILITIES	
 	 	 	
5.1	 	Purpose	
5.2	 	Scope	
5.3	 	Safety Organization and Responsibilities	
5.4	 	Corporate Safety & Training Department	
5.4.1	 	Corporate Safety & Training Manager	
5.5	 	Line Management Responsibilities	
5.6	 	Sub-Contractor Services	
5.7	 	Client, Contractors and Third Party	
 	 	 	
6.0	 	EMPLOYEE SELECTION, COMPETENCY AND TRAINING	
 	 	 	
6.1	 	In-house Training and Orientation	
6.1.1	 	Safety Induction and Orientation	
6.1.2	 	Other Internal/In-House Training	
 	 	·  Safety Training Observation Program (STOP)	
 	 	·  Rig Site Safety Related Training	
 	 	·  On The Job Training (OJT)	
 	 	·  Newly Promoted Personnel	
6.2	 	External Training/Seminar/Conferences (Mandatory and Recommended Training for Shore Based Management and all Rig Based Personnel are identified in a MATRIX form)	
6.3	 	Records of Training	
6.3.1	 	Rig Based	
6.3.2	 	Shore Based (Rig Site)	
6.4	 	Request for Training	
 
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6.4.1	 	Human Resources Department	
6.4.2	 	Corporate Safety & Training Department	
6.5	 	Evaluation and Review Process	
6.5.1	 	Measuring Internal Training Performance	
6.5.2	 	Measuring External Training Performance	
6.5.3	 	Training Needs, Assessment and Review Process	
 	 	 	
7.0	 	DRUG AND ALCOHOL POLICY	
 	 	 	
7.1	 	Objectives	
7.2	 	Policy Definitions	
7.3	 	Application	
7.4	 	Standards	
7.5	 	Enforcement	
7.6	 	Types of Drug Testing	
7.6.1	 	Drugs To Be Tested For	
7.6.2	 	Pre-Employment Testing	
7.6.3	 	Random Testing	
7.6.4	 	Post Accident/Incident Testing	
7.6.5	 	Reasonable Cause Testing	
7.6.6	 	Periodic Testing/U.S. Coast Guard	
7.7	 	Notice of Disciplinary Action	
7.8	 	Requirements of Testing Facilities	
7.9	 	Acknowledgments	
 	 	 	
8.0	 	ENVIRONMENTAL IMPACT CONSIDERATIONS	
 	 	 	
9.0	 	RISK ASSESSMENT AND RISK MANAGEMENT	
 	 	 	
9.1	 	Objectives	
9.2	 	Risk Acceptance	
9.3	 	Risk Management Methods	
9.3.1	 	Safety Programs (STOP, JSA, Meetings)	
9.3.2	 	Maintenance Program	
9.3.3	 	Formal Safety Assessment (FSA)	
9.3.4	 	Assessment of Risk (HAZID and HAZOPS)	
9.3.5	 	Hazard Register	
9.3.6	 	Risk Acceptance Criteria	
9.4	 	Follow-up Procedures	
 	 	 	
10.0	 	EMPLOYEE INVOLVEMENT	
 	 	 	
I0.1	 	Purpose	
10.2	 	Scope	
10.3	 	Employee Involvement Methods (Also refer to STOP in Section 9.3 Risk Management Methods)	
10.3.1	 	Types of Safety Meetings: Pre-Tour Safety, Pre-Job, Weekly	
10.3.2	 	Safety Recognition Programs: Quarterly and President’s Safety Award	
10.4	 	Safety Initiatives	
 
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10.5	 	Rig Based Safety, Health & Environmental (SHE) Committee	
10.6	 	Safety Alerts	
10.7	 	Records	
 	 	 	
11.0	 	SAFE OPERATIONAL PROCEDURES	
 	 	 	
11.1	 	Basic Safety Rules	
11.1.1	 	Introduction	
11.1.2	 	Basic Safety Rules Brochure	
11.2	 	General Safety Requirements	
11.2.1	 	Basic Work Clothes/Attire	
11.2.2	 	Personal Protective Equipment (PPE)	
11.2.3	 	Eye Protection	
11.2.4	 	Hand Protection	
11.2.5	 	Hearing Protection	
11.2.6	 	Respiratory Protection	
11.2.7	 	Fall Protection Equipment	
11.2.8	 	Housekeeping	
11.2.9	 	Unguarded Opening	
11.2.10	 	Work Over The Side	
11.2.11	 	Electrical Safety	
11.2.12	 	Radiation Safety	
11.2.13	 	Ventilation	
11.2.14	 	Lighting	
11.2.15	 	Signs and Notices	
11.2.16	 	Portable Gas Detection Equipment	
11.3	 	Cranes and Lifting Equipment	
11.3.1	 	Qualification	
11.3.2	 	General Requirements	
11.3.3	 	Lifting Equipment	
11.3.4	 	Cranes	
11.3.5	 	Air Winches	
11.3.6	 	Fork Lifts	
11.4	 	Welding and Cutting	
11 4.1	 	General Precautions	
11.4.2	 	Cylinder Stowage	
11.5	 	Materials Handling	
11.5.1	 	Manual Handling	
11.5.2	 	Storage and Handling of Dangerous Materials	
11.5.3	 	Hazardous Materials Communication Program	
11.6	 	Safe Use of Equipment	
11.6.1	 	Tools and Equipment	
11.6.2	 	Pneumatic and Hydraulic Hoses	
11.6.3	 	Safe Work Procedures	
11.6.4	 	Guarding of Machinery and Moving Parts	
11.6.5	 	Lock-Out and Tag-Out Procedures	
11.7	 	Helicopter Operations	
11.7.1	 	Responsibilities	
11.7.2	 	Special Precautions	
 
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11.7.3	 	Passenger Procedures	
11.7.4	 	Helideck Equipment	
11.7.5	 	Helicopter Refueling Procedures and Guidelines	
11.8	 	Off The Job Safety	
 	 	 	
12.0	 	EMERGENCY RESPONSE PROCEDURE	
 	 	(Reference should also be made to Appendices Section and Emergency Response Plan - Rig and Area Specific)	
12.1	 	Introduction	
12.2	 	Emergency Escape Equipment and Procedures	
12.3	 	Abnormal Pressure Situations	
12.4	 	Abandonment of the Rig and Evacuation Procedures	
12.4.1	 	Responsibility	
12.4.2	 	Procedures for Abandonment of the Rig	
12.5	 	Evacuation Procedures	
12.6	 	Person Overboard	
12.7	 	Medical Evacuation (Medivac)	
12.8	 	Storm/Hurricane/Cyclone Encounter Procedures (Reference should also be made to Appendices Section and STORM Encounter Procedures Manual Area Specific)	
12.9	 	Hydrogen Sulfide (H2S) Emergency (Reference should also be made to Appendices Section and H2S Emergency Manual - Area Specific)	
12.10	 	Working In Potential H2S Environment	
12.10.1	 	Description	
12.10.2	 	Toxicity to Personnel	
12.10.3	 	Rig Equipment and Personnel	
12.10.4	 	Personnel Safety and Protection	
12.10.5	 	Training Program	
12.10.6	 	Personal Protective Equipment (PPE)	
12.10.7	 	Equipment	
12.11	 	Life Saving Appliances and Equipment	
12.11.1	 	Lifeboat/Capsule	
12.11.2	 	Lifeboat Launching Equipment (Davits)	
12.11.3	 	Inflatable Life Rafts	
12.11.4	 	Means of Embarkation	
12.11.5	 	Life Jacket/Preserver (PFD)	
12.11.6	 	Work Vest (PFD)	
12.11.7	 	Life Ring Buoys	
12.11.8	 	Line Throwing Appliances	
12.11.9	 	Distress Signals	
12.11.10	 	Self Contained Breathing Apparatus	
12.11.11	 	Combustible Gas/Oxygen Detector (‘sniffer’)	
12.12	 	Fire Protection and Prevention	
12.12.1	 	Equipment	
12.12.2	 	Fire Drills/Other Emergency Drills	
12.12.3	 	Emergency Response Team	
 	 	 	
13.0	 	ACCIDENT/Incident Evaluation AND REPORTING	
 
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13.1	 	Objectives	
13.2	 	Scope	
13.3	 	Reporting Requirements	
13.4	 	Forms and Reporting	
13.5	 	Incident Evaluation	
13.5.1	 	All Incidents	
13.5.2	 	Lost Time Incident and Medical Treatment Cases	
13.5.3	 	Fatalities	
13.5.4	 	Special Accident Investigation (Catastrophic Occurrence)	
13.6	 	Monthly Safety Reports	
13.7	 	Safety Statistics	
 	 	 	
14.0	 	MANAGEMENT OF CHANGE	
 	 	 	
15.0	 	OCCUPATIONAL HEALTH & HYGIENE	
 	 	 	
15.1	 	Purpose	
15.2	 	Scope	
15.3	 	Types Of Occupational Health Hazards	
15.4	 	Occupational Health Hazard Control Methods	
15.5	 	Hygiene and Living Quarters	
15.6	 	Hospital/Medical Treatment Room	
15.6.1	 	General Requirements	
15.6.2	 	Medic Qualification	
15.6.3	 	Medication	
15.6.4	 	First Aid and Medical Equipment	
15.6.5	 	Hospital	
15.6.6	 	Weekly Inspection	
15.7	 	Rehabilitation of Injured Personnel	
 	 	 	
16.0	 	PERMIT TO WORK SYSTEM	
 	 	 	
16.1	 	Purpose	
16.2	 	Scope	
16.3	 	Description	
16.4	 	Glossary of Terms	
16.5	 	Authority Levels and Responsibilities	
16.6	 	Work Requiring Permit	
16.7	 	Types of Permits and Forms	
16.8	 	Procedures	
16.9	 	Administration	
16.10	 	Isolation Procedures	
16.11	 	Training/Retraining or Review Requirements	
16.12	 	Audit & Review	
 	 	 	
17.0	 	Safety AUDIT, Inspection AND REVIEW	
 	 	 	
17.1	 	Objectives	
17.2	 	Scope	
 
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17.3	 	Safety Audit, Inspection and Survey Procedures	
17.3.1	 	Type of Safety Audit and Inspection	
17.3.2	 	Approach	
17.3.3	 	Audit Structure	
17.3.4	 	Reporting	
17.3.5	 	Interview Techniques	
17.3.6	 	Audit/Inspection Review and Correction	
17.4	 	Selection Criteria For Auditor/Inspector/Surveyor	
17.4.1	 	Recommended Internal Auditor/Inspector’s Qualification	
17.4.2	 	Recommended External Organization Auditor/Inspector/Surveyor	
17.5	 	Special Instructions	
 	 	 	
18.0	 	Security	
 	 	 	
18.1	 	Purpose	
18.2	 	Scope	
18.3	 	Security Planning	
18.3.1	 	Methodology	
18.3.2	 	Security Plans	
18.4	 	Responsibilities	
18.4.1	 	Security Committee	
18.4.2	 	Manager of Safety, Health, Environment and Security	
18.4.3	 	Operations Manager	
18.4.4	 	References	
18.5	 	Definitions	
18.6	 	Training And Guidance	
18.6.1	 	Corporate Office	
18.6.2	 	Shore Based	
18.6.3	 	Rig Based	
18.7	 	Audit And Inspection	
18.7.1	 	Monthly	
18.7.2	 	Annual	
18.7.3	 	As Required	
18.8	 	Reporting	
 	 	 	
19.0	 	Dropped Objects Prevention System (DROPS)	
 	 	 	
19.1	 	Purpose	
19.2	 	Objectives	
19.3	 	Responsibilities	
19.4	 	Reference	
19.5	 	Zone Assignments	
19.6	 	Reduce the Incidents of Dropped Objects through these Measures	
19.7	 	Implement a DROPS Action Plan	
19.8	 	Review of Inspection Check Sheets	
19.9	 	Frequency of Inspections by Rig Crews	
19.10	 	Control of Temporary Equipment	
19.11	 	Continuous Improvement	
19.12	 	Records	
 
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19.13	 	Audit	
19.14	 	Drops Register	
19.15	 	Tools / Equipment in Derrick Log Sheet	
 	 	 	
APPENDICES	
 	 	 	
A	 	Safety Training Observation Program (STOP)	
B	 	Off The Job Safety (OTJS)	
C	 	Job Safety Analysis	
D	 	Safety Duties and Responsibilities of Shore Based Management and Rig Crew	
E	 	Storage & Handling of Hazardous Materials and Associated Instruments or Equipment	
F	 	Hazard Identification (HAZID) Procedures	
G	 	Guidelines For Hazard Operability Study (HAZOP)	
H	 	Emergency Response Plan	
I	 	Tropical Rotating Storm Procedure	
J	 	Hydrogen Sulfide (H2S) Guidelines and Procedures	
K	 	Lifting Gear and Appliances Register Guidelines	
L	 	Safe Work Procedures	
M	 	Helicopter Refueling Procedures and Guidelines	
N	 	Internal Company Safety Audit - Guidelines and Implementation	
O	 	Permit To Work System - Training Program	
P	 	Potable Water Treatment And Testing Procedure	
 	 	 	
EXHIBITS	
 	 	 	
A	 	Safety Organization Chart	
B	 	Safety Orientation For New Hires	
C	 	On Arrival Safety Briefing - Check List	
D	 	Mandatory (M) and Recommended (R) External Training	
E	 	Training Request Form	
F	 	Consent Form (for Alcohol and Drug Screening)	
G	 	Chain of Custody	
H	 	Hazard Study Record Sheet	
I	 	Hazid Action Sheet	
J	 	Hazard Identification List	
K	 	Hazid-Fire Risk Analysis	
L	 	Hazard Register	
M	 	Safety Instructions Meeting	
N	 	SF-5 - Weekly Rig Safety Inspection Report	
O	 	Quarterly Safety Award	
P	 	Safety Notice	
Q	 	Basic Safety Rules	
R	 	SF-1 - Employer’s First Report of Incident	
S	 	SF-2 - Surgeon’s Report	
T	 	SF-3 - Employer’s Supplemental Report of Incident	
U	 	SF-4 - Supervisor’s Incident Evaluation Report	
V	 	SF-6 - Third Party Incident Notice	
 
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W	 	Monthly Safety Statistics Report	
X	 	Permit To Work System (Hot Work)	
Y	 	Permit To Work System (Cold Work)	
Z	 	Confined Space Entry Certificate	
AA	 	Isolation (Mechanical/Electrical) Certificate	
BB	 	Crane Lifting - Check List	
CC	 	Abrasive Blasting - Check List	
DD	 	Fuel Oil Transfer - Check List	
EE	 	Work Over The Side - Check List	
FF	 	Pressure Testing - Check List	
GG	 	Spray Painting - Check List	
HH	 	OTJS (Off The Job Safety) - Home Fire Safety Checklist	
II	 	OTJS - “Home Slip & Fall Safety” Checklist	
JJ	 	Automobile Loss Notice	
KK	 	STOP Breakdown by Category (Example 1)	
LL	 	STOP Breakdown by Category (Example 2)	
MM	 	Radio Silence Checklist	
NN	 	Employee Computerized Maintenance, Purchasing And Inventory System Training And Orientation	
OO	 	Corporate/Area Security Measures	
PP	 	Shore Base/Rig Security Measures	
QQ	 	Example Rig Security Plan	
RR	 	Travel Security Guidelines	
 
170

 
EXHIBIT A10 TO EXHIBIT A
 
171

 
Attachment A10 to Exhibit A — Scope of Work
Offshore Drilling Contract
APPLICATION FOR PERMIT TO OPERATE IN GHANA
 
Contractor is advised that, for the term of this Agreement and Work Order, Work shall be in compliance with the Laws of the Republic of Ghana, the Agreement and Ghana National Petroleum Corporation (GNPC) regulations, including but not limited to, the requirement to register and apply for permits from the Ghana National Petroleum Corporation (GNPC) before setting up in the Republic of Ghana, as set forth in the Guidelines for Setting Up Upstream Petroleum Service Companies in Ghana issued by the Ministry for Energy dated March 26, 2008.
 
A specimen “Application Form for Permit to Operate as Petroleum Service Company in Ghana” is attached in this Attachment A10 to Exhibit “A”.
 
For all information regarding application for this permit and to obtain the Guidelines noted above, please direct your inquiries to Thomas Manu, GNPC Director of Operations using both the following email addresses: t.manu@gnpcghana.com thmsmanu@yahoo.co.uk
 
Specimen Form
 
GHANA NATIONAL PETROLEUM CORPORATION
 
Application Form for Permit To Operate as
Petroleum Service Company in Ghana
 
PART ONE — Corporate Structure and Services
 
1.                                      Name of Applicant (as indicated in Certificate of Incorporation)
 
2.                                      Date and Place of Incorporation.

3.                                      Address of Registered Office
(Indicate street and postal address, telephone, facsimile numbers and email address)

4.                                      List all Companies or Individuals with shares in the applicant company. Please provide detailed addresses.
 
172

 
 	 	 	 	Percentage share in	
Name of Shareholder	 	Address	 	the Company	

 	 	 	 	 	
 
5.                                      List Directors of the company (with detailed address)
 
Name of Director	 	occupation/profession	 	Address	

 	 	 	 	 	
 
6.                                      Give an outline of the corporate structure, including an explanatory diagram, if appropriate, showing parent, subsidiary and affiliate companies. (Annex 1)
 
7.                                      Please provide a description of the range of services you propose to offer in Ghana.
 
PART TWO                             Financial Capability and Technical Competency of Applicant
 
A. Financial Capability
 
1.              Provide Annual Reports or Audited Financial Reports for each of the last three years, if any. (Annex 2)
2.              Indicate sources where applicant intends raising funds for the operations in Ghana:
 
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B. Management and Technical competencies
 
3.              Provide Organizational Chart indicating key management and technical staff. (Annex 3)
 
4.                      a.   Provide detailed information on the number of staff and their expertise.
b.   Indicate expertise to be sourced locally and internationally. (Annex 4)
 
5.              Indicate sources from which applicant proposes to obtain equipment and other facilities to support exploration and production activities. (Annex 5)
 
C. Details of Experience
 
6.              Describe company’s past oil industry experience, including locations and dates of significant activities or contracts. (Annex 6)
 
7.              In which countries do applicant, parent company and affiliates currently have oil industry activities or contracts? List of all current operations globally. For Ghana, please show the various contracts and subcontracts being undertaken and total capital investments made to date, if applicable. (Annex 7).
 
PART THREE — Plans and Programmes
 
Please provide the company’s business plan for Ghana for the next three (3) years. The plan should include:
 
(a)                               Employment Programme and Budget.
(b)                              Technology Transfer Programme and Budget
(c)                               Training Programme and Budget
(d)                              Social Development Programme and Budget
(e)                               Environmental Management Programme including Decommissioning
 
PART FOUR — Local Content
 
Please provide a description of the proportion of Ghanaian participation in respect of
(a)                               management,
(b)                              infrastructure investments,
(c)                               ownership,
(d)                              employment,
(e)                               value of services,
(f)                                 raw materials utilized,
(g)                              Ghanaian finished goods utilized and
(h)                              Ghanaian participation in procurement of imported goods as a share of your company’s activities in Ghana.
 
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PART FIVE — Miscellaneous
 
Any other relevant information which applicant wishes to offer or further proposal which applicant seeks to make in relation to this application.
 
SUBMISSION OF APPLICATION
 
Completed application forms in triplicate together with a non-refundable permit fee of Two Thousand United States Dollars (US$2000.00) for foreign companies and One Thousand Ghana Cedis (ghc 1,000.00) for Ghanaian companies in the form of a Cheque or Banker’s Draft payable to the Ghana National Petroleum Corporation, at the following address:
 
The Managing Director
GHANA NATIONAL PETROLEUM CORPORATION
PRIVATE MAIL BAG
TEMA
GHANA
Telephone:	233 22 204726	
Facsimile:	233 22 202854	
Email:	info@gripcghana.com	
 
175

 
EXHIBIT B
 
176

 
EXHIBIT B TO OFFSHORE DRILLING CONTRACT
 
INDEPENDENT CONTRACTOR HEALTH, ENVIRONMENTAL AND SAFETY
GUIDELINES
 
1.            RESPONSIBILITY FOR COMPLIANCE
 
1.1          Contractor shall comply (and ensure that all members of Contractor Group comply) with all applicable laws and these Independent Contractor Health, Environmental and Safety Guidelines (“Guidelines”) within the Area of Operations. These Guidelines are intended to promote a safe and healthful workplace where the Services are performed without incident and in an environmentally-sound manner.
 
1.2          These Guidelines are a minimum standard and are intended to supplement, not replace, Contractor’s safety program. Contractor may implement additional measures, as necessary, to assure workplace health, environmental and safety protection, and shall implement all additional measures required by law.
 
1.3          The requirement for Contractor to comply with these Guidelines does not alter Contractor’s status as an independent contractor, does not change the rights or obligations Contractor has as an independent contractor, and does not amend or restrict Contractor’s liabilities and indemnities provided in this Contract. All costs associated with compliance are included in the compensation provided for under this Contract, and Contractor has no right to claim any additional payment not specifically provided for in this Contract because of the requirement for compliance with these Guidelines.
 
1.4          Contractor shall communicate these Guidelines to its employees and to members of the Contractor’s Group prior to entering the Area of Operations. Contractor shall maintain written documentation of its actions undertaken to fulfill these responsibilities and maintain a copy of those written documentations on site.
 
1.5          Contractor shall provide Company with the name of its Contractor representative and those of Contractor Group who are responsible for health, environmental, safety and security protection in the Area of Operations.
 
1.6          Company or its representatives may inspect the performance of the Services in the Area of Operations at any time to determine compliance with these Guidelines and prescribe measures to Contractor to achieve compliance, Contractor or Contractor’s Group shall implement steps to achieve compliance with these Guidelines.
 
2.            HEALTH, ENVIRONMENTAL AND SAFETY WORK PLAN
 
2.1          On or before the Effective Date of the Contract, Company will advise Contractor whether a Health, Environmental and Safety Work Plan (“Plan”) is required, and if so, of the scope of the Plan. Contractor shall prepare the plan on or before the Effective Date of the Contract.
 
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2.2          The Plan developed by Contractor shall describe the health, environmental and safety issues associated with the Services, and the mitigation measures required to address these issues before Contractor or Contractor Group enters the Area of Operations. Contractor shall ensure that the Plan is based on, and complies with applicable laws, decrees, codes, standards, administrative rules and regulations, relevant Company policy, processes and standards, these Guidelines and generally accepted good international industry practice for the industry in which the Services are to be provided. If an inconsistency or conflict exists between components of these laws, decrees, codes, standards, rules, regulations, policy, these Guidelines and practices, Contractor shall ensure that it complies with the most stringent to the extent that it is legal.
 
2.3          Contractor shall submit Contractor’s Plan to Company’s Representative for review. Company has the right, but not the obligation, to review Contractor’s Plan and either approve the Plan or return it to Contractor with notice of deficiencies. Contractor shall correct any deficiencies and resubmit the Plan for Company’s review. Contractor shall ensure that the Plan is accepted by Company before Contractor commences the Services. Company’s review of the Plan does not absolve Contractor of its responsibility to develop and implement a Plan that complies with applicable laws or these Guidelines.
 
3.            ENTRANCE TO PROPERTY
 
3.1          Before commencement of performance, Contractor shall inspect and confirm that the work site within the Area of Operations is safe and if not, promptly report any unsafe condition to Company. Without relieving Company of its obligation under Item 20l of Attachment A2 to Exhibit A Scope of Work, failure to promptly report an unsafe condition to Company precludes Contractor from asserting any defense or Claim against Company in reliance on an unsafe condition, which should have been observed during inspection.
 
3.2          Contractor shall comply (and ensure that all members of Contractor Group comply) with Company’s security requirements that Company communicates to Contractor during the performance of the Services.
 
3.3          Contractor shall ensure that only those employees or personnel of Contractor or Contractor Group having authorized business arising out of this Contract are allowed in the Area of Operations.
 
4.            MOTOR VEHICLE SAFETY
 
4.1          Contractor shall have or develop and implement (and ensure that all members of Contractor Group comply) with its own motor vehicle safety plan (“Motor Vehicle Safety Plan”) to promote safe practices relating to operation of motor vehicles and equipment (“vehicle”) used in performance of services within the Area of Operations, unless the Services provided do not require the operation of motor vehicles and equipment (“vehicle”). Company Representative may review this Motor Vehicle Safety Plan and, if required, Contractor shall implement improvements, such as a provision for defensive driving training.
 
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4.2          Contractor shall comply (and ensure that all members of Contractor Group comply) with rules and regulations, including written instructions prescribed by Company and communicated to Contractor, relating to vehicle safety. These include observation of the posted speed limit, or if not posted, a safe speed with regard to existing conditions.
 
4.3          Contractor shall ensure that all vehicles are in safe operating condition and operators must be properly trained, qualified, licensed and/or certified. Contractor shall ensure that these vehicles are equipped with seat belts for driver and passengers and that operator and passengers use seat belts at all times.
 
4.4          Except as provided in this Section, the operator of a vehicle may not use a cellular telephone or any other communication device, in either hand-held or hands-free mode, while the vehicle is in motion. These telephones or communication devices may be left in an “on” position to alert drivers of an incoming call; however, calls must not be answered until the vehicles have been stopped in a safe location. This guideline does not apply to Contractor’s use of facility mobile equipment (e.g., forklifts, electric carts, fire trucks, etc.), dispatch or emergency response communications, or citizen band radios if previously approved to do so in writing by Company.
 
4.5          On or before the Effective Date of the Contract, Company will advise Contractor whether a driver monitoring system is required. If a driver monitoring system is required, Contractor shall have, or develop and implement such a system. Company may request review of the system’s monthly data and recommend measures to improve Contractor’s vehicular safety performance.
 
4.6          Contractor shall ensure that motorcycles are not used for performing the Services except if approved in writing by Company.
 
5.            SMOKING
 
5.1          Smoking is prohibited in all areas containing crude oil or fuel storage, gas processing and compression equipment and separation or treating equipment. Smoking is only permitted in designated, authorized areas.
 
5.2          Company has the right to order persons observed smoking in unauthorized areas to cease or to leave the Area of Operations.
 
5.3          Smoking is prohibited in Company-provided aircraft and vessels.
 
6.            PERMIT TO WORK
 
6.1          The “Permit to Work” (“PTW”) applies to work that requires a specific, permit to perform the work. PTW requires identification of job task hazards, evaluation of job task risks, specification for control measures to track performance and use of those control measures to prescribe improvements to performance. The purpose of PTW is to prescribe documented practices to manage and control risks associated with the particular work. Contractor shall submit its practice(s) for Company’s review. If Company determines that Company’s documented practices for substantially the same
 
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work are more stringent than Contractor’s documented practices, Company Representative may require Contractor to follow Company’s documented practices.
 
6.2          Prior to starting any non-routine, safety critical work or field activities, Contractor shall perform a Job Hazard Analysis (“JHA”). Contractor shall ensure that the JHA accomplishes all of the following:
 
(A)         Study and record each step of any non-routine, safety critical work or field activities.
 
(B)          Identify existing or potential equipment-, environmental- or action-generated job hazards.
 
(C)          Determine the best way to perform the job and mitigate or eliminate hazards and risks.
 
6.3          Prior to starting any non-routine, safety critical work or field activities, Contractor shall communicate the JHA to its employees and those members of Contractor’s Group who will perform the non-routine, safety critical work.
 
6.4          Before hot work operations are conducted, Contractor shall communicate to the Company that a hot work permit is required and shall develop, implement and comply with all conditions of any hot work permit.
 
6.5          Contractor shall develop, implement and comply with (and ensure that all members of Contractor Group comply with) written safe-entry procedures for any Services involving entry into confined spaces, limited access vessels or below grade pits.
 
6.6          Contractor shall develop, implement and comply with an energy isolation system (lock-out/tag-out) before any member of Contractor Group performs work on equipment or machinery.
 
7.            PRESSURE TESTING
 
7.1          Contractor shall ensure that its employees or Contractor Group do not test pipes or pressure vessels with or without compressed air, gas or service fluid, without Company’s prior written approval.
 
8.            EXPLOSIVES AND HAZARDOUS MATERIALS
 
8.1          If explosives are required in the performance of the Services, Contractor shall train its employees and provide Company with written notification regarding the proposed use, storage and handling of explosives prior to the start of the blasting. Further, Contractor shall ensure that its employees are qualified to perform this type of work.
 
8.2          Contractor shall notify and receive Company’s prior written approval before chemicals or hazardous substances are brought to the Area of Operations.
 
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8.3          Contractor shall ensure that all hazardous substances used in the performance of the Services are handled, stored, transported, identified, documented and secured in a safe and environmentally-sound manner.
 
8.4          Contractor shall maintain (and ensure that all members of Contractor Group maintain) Material Safety Data Sheets or their equivalent (“MSDSs”) in the Area of Operations for all chemicals and other hazardous substances used in performance of the Services and perform all the Services consistent with instructions contained in these MSDSs.
 
9.            FIRE PROTECTION AND EMERGENCY RESPONSE
 
9.1          Contractor shall take (and ensure that all members of Contractor’s Group take) reasonable precautions to prevent fires. Contractor shall ensure that contaminated paper, rags, trash and other combustible are disposed of in safe containers in compliance with applicable laws and generally accepted prudent industry practice.
 
9.2          Contractor shall ensure that flammable liquids, such as, gasoline, kerosene and fuel oil, are transported and stored in industry-approved metal containers that are designed for these purposes. Contractor shall ensure that these liquids are stored away from possible sources of ignition.
 
9.3          Contractor shall make reasonable efforts to ensure that fire protection equipment is not tampered with. Contractor shall ensure that hydrants or main water valves are not opened or closed without Company’s written approval, except in the case of an emergency.
 
9.4          Contractor shall immediately report all leaks or other indications of gas escaping around piping, vessels or equipment to Company. Contractor shall cease (and ensure that all members of Contractor Group cease) all work in the area near the leak upon discovery of the hazard.
 
9.5          Contractor shall ensure that its employees use only non-toxic cleaning solvents with a high flash point (above 140 o F or 60 o C) for cleaning purposes.
 
9.6          Contractor shall ensure that its employees receive the fire protection, safety and other emergency training required under all applicable laws and these Guidelines.
 
9.7          Contractor shall provide its own fire protection equipment for the use of its employees and personnel of Contractor Group unless otherwise agreed by Company in writing.
 
9.8          Contractor shall shut down (and ensure that all members of Contractor Group shut down) internal combustion engines before refueling, except where the refueling point is sufficiently remote from the engine to allow safe refueling.
 
9.9          In case of fire or other emergency situation, Contractor shall immediately take (and ensure that all members of Contractor Group take) appropriate measures to protect the safety of personnel and to extinguish the fire or otherwise handle the emergency situation even where the cause is unrelated to the Services. The first priority must be the safety of all personnel. Contractor shall notify Company Representative about the fire or other
 
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emergency immediately, but not later than the period of time after discovering the emergency incident permitted under the Plan.
 
9.10        Contractor shall shut down (and ensure that all members of Contractor Group shut down) and remove all equipment from the area in and around the fire and other emergency situation to the extent possible.
 
9.11        Use of motors, compressors, pumps and other equipment inside tank dike areas by Contractor is permitted only in accordance with Company procedures.
 
9.12        Contractor shall ensure that “strike anywhere” matches and plastic disposable lighters are not carried or used in hazardous areas. Safety matches are preferred, but facility or work site rules apply and control in case of conflict.
 
10.                              MEDICAL AID
 
10.1        Contractor shall provide first aid personnel, equipment and supplies for its employees and personnel of Contractor Group unless otherwise agreed by Company in writing.
 
11.                              PERSONAL PROTECTIVEEQUIPMENT
 
11.1        Personal protective equipment must be provided by Contractor for its employees and personnel of Contractor Group if required by applicable laws, decrees, codes, standards, administrative rules and regulations, relevant Company policy or generally accepted good international industry practice for the industry in which the Services are to be provided. Contractor shall provide this equipment at its own cost unless otherwise agreed by Company in writing. Contractor’s employees must wear (and ensure that all members of Contractor Group wear) this equipment within the Area of Operations, as required
 
11.2        All personal protective equipment must be used and maintained by Contractor in compliance with applicable laws and manufacturer’s instructions.
 
11.3        Contractor shall provide fall protection rescue equipment and personnel trained in its use, if performing work that requires fall protection equipment. This should also include high angle rescue training and associated equipment.
 
12.                              HOUSEKEEPING
 
12.1        Contractor shall maintain good housekeeping at all times and keep all work sites clean and free from obstructions. Contractor shall mark and identify all tripping hazards.
 
12.2        Contractor shall keep (and ensure that members of Contractor Group keep) the access to emergency exits clear at all times.
 
12.3        Contractor shall ensure that all ditches, holes, excavations, overhead work and other impediments connected with the Services are properly barricaded, and are provided warning signs or lights where necessary.
 
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13.                              INCIDENT AND SAFETY REPORTING
 
13.1                        Contractor shall report all on-the-job accidents or injuries arising from the Services to the proper governmental authorities, where required . , and to Company Representative. Contractor shall also report all theft or other incidents of a criminal or security nature, such as, a hijacking or assault. Contractor shall complete and provide Company with a copy of every accident and incident report involving personnel injury or property damage that is filed with Contractor’s (or any member of Contractor Group’s) insurance company or representative or that are reportable under OSHA’s recordkeeping regulations (or their equivalent in the Area of Operations).
 
13.2                        Contractor shall maintain and file (and ensure that all members of Contractor Group maintain and file) accident and incident reports required under this Contract or as required by applicable laws, decree, codes, administrative rules, these Guidelines and regulations, and furnish copies to Company.
 
13.3                        Contractor shall immediately and verbally report all accidents and incidents to Company and confirm the report in writing within the time limit specified by Company in the Plan. This includes fatalities, injuries, fires, spills, motor vehicle accidents, damage to Company property and other reports required in this Contract.
 
13.4                        Contractor shall immediately and verbally report all accidents and incidents to Company-arising from the Services that affect health, the environment and safety (including spills) and confirm the report in writing within the time limit specified by Company in the Plan. These reports must be delivered to Company Representative on a monthly basis unless otherwise specified by Company in the Plan.
 
13.5                        If required by Company Representative, Contractor shall also prepare monthly reports regarding total hours worked , number and type of incidents that occurred during the report period or other statistic required by Company. Contractor shall deliver these reports to Company Representative by a specified date each month.
 
14.                              BEHAVIOR-BASED SAFETY
 
14.1                        Contractor shall develop, implement and comply with (and ensure that all members of Contractor Group implement) a behavior-based safety process (“BBS”) to provide for observation and feedback on employee behaviors and to track and analyze these observations in an effort to identify and implement actions for improvement. BBS is intended to prevent injury and incident through reduction of at-risk behaviors in the workplace.
 
15.                              ENVIRONMENTAL PROTECTION
 
15.1                        Contractor shall prevent (and ensure that all members of Contractor Group prevent) spills or other releases of oil or chemical substances during the performance of Services. Contractor shall develop, implement and comply with a pollution prevention plan. Company has the right, but not the obligation to review this pollution prevention plan.
 
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15.2                        Contractor shall exercise (and ensure that all members of Contractor Group exercise) the necessary care to protect and preserve the environment, including flora, fauna and other natural resources or assets at any location where the Services are performed. Contractor shall mitigate (and ensure that all members of Contractor’s Group mitigate) adverse impacts to the environment. This includes proper disposal of all hazardous and non-hazardous wastes such as oil, chemicals, sewage and garbage. Contractor shall comply with any environmental practices specified by Company and included as a condition of this Contract. In the event Contractor discovers or is notified of 1) any condition or situation on, in or around the Area of Operations which may constitute a release of Hazardous Substances or a violation of any law, or 2) any threatened or actual lien, action or notice that the Area of Operation is not in compliance with any law, the party discovering the condition shall immediately notify the Company. Contractor shall then immediately take reasonable measures to remediate the conditions and notify any other appropriate governmental authorities.
 
15.3                        Contractor shall assess the environmental hazards of materials and supplies used in conjunction with the Services and provided by the Contractor under Attachment A2 to Exhibit A – Scope of Work and substitute materials presenting less risk whenever possible. Contractor shall not use the following materials, as well as any other materials specified by Company, in the Area of Operations without Company’s written approval:
 
(A)                             Polychlorinated Biphenyls (PCBs).
 
(B)                               Asbestos.
 
(C)                               Chlorinated solvents and thinners,
 
(D)                              Halon and other chlorinated fluorocarbons.
 
15.4                        Contractor shall use only properly grounded above-ground steel tanks for fuel storage. Contractor shall not use bladder, fiberglass, plastic and other types of fuel storage tanks without Company’s written approval. Contractor shall ensure that loading and drainage connections to fuel storage tanks are either plugged or locked in the closed position when not in use, and equipped with self-closing (“dead-man’s valve”) fuel dispensing nozzles.
 
15.5                        Contractor shall ensure that all offshore, above-ground fuel, oil and chemical storage tanks used in connection with the Services have a secondary containment mechanism with a minimum capacity equal to 110% of the capacity of the largest single tank. Secondary containment impounds may have a drain connection for removal of storm water if the drain discharge is normally plugged or equipped with a valve that is generally locked closed.
 
15.6                        Contractor shall ensure that its employees do not hunt, disturb or capture native birds, fish or other animals. Contractor may allow its employees to fish at certain times and in certain places in the Area of Operations if permitted by local regulations in the Area of Operations.
 
15.7                        Contractor shall ensure that trees and vegetation are not removed to an extent greater than is necessary to perform the Services. Contractor shall ensure that topsoil is
 
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stockpiled for subsequent use in site restoration unless Company provides in writing for an alternative course of action.
 
15.8                        Contractor shall ensure that fossils and antiquities found at work sites are protected from damage or disturbance. Contractor shall report the location of these fossils and antiquities to Company and suspend work at that location pending further instructions from Company. Contractor is not entitled to compensation for the period of the suspension but Company shall reimburse Contractor for all of the following expenses of Contractor which are actual, direct and non-recoverable:
 
(A)                   Expenses incurred by Contractor as a consequence of the suspension which are reasonably necessitated by the suspension.
 
(B)                     Expenses otherwise incurred by Contractor during the period of the suspension which Contractor could not reasonably have avoided in order to be able to recommence performance of the Services upon the suspension being lifted.
 
15.9                        Contractor and its subcontractors shall keep a reasonable degree of order by properly disposing of accumulated rubbish and waste materials. Contractor and its subcontractors shall start site cleanup and remediation immediately upon completion of Work at that site.
 
15.10               Contractor and its subcontractors shall not discharge oil, solvents chemicals, etc. to water bodies or unto land.
 
16.                              SHORT SERVICE EMPLOYEE PROGRAM
 
16.1                        A short service employee (“SSE”) is an individual who has been employed by Contractor or subcontractor for less than six (6) months or has been in a like job by Contractor for less than six (6) months. No one person crew may be staffed by an SSE. Only one SSE is allowed on a 2-4 person crew and on crews of five (5) persons or more no more than twenty percent (20%) may be SSE’s. Contractor shall notify Company of any SSE’s on its crews. A qualified mentor must be assigned to each SSE to monitor the SSE’s job performance. Exceptions to the SSE policy may be made only with Company’s prior written approval.
 
16.2                        On or before the Commencement Date of the Contract, Company will advise Contractor whether a Short Service Employee (“SSE”) program is required. If required, Contractor shall prepare and implement its SSE program. This SSE program applies to those employees engaged by Contractor or any member of Contractor Group who have less than six months experience in the same job type.
 
16.3                        Minimum requirements of a SSE program include all of the following:
 
(A)                             SSE personnel shall be visibly identified.
 
(B)                               The number of SSEs in any work crew shall be limited to the extent possible.
 
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(C)                               A list of any high-risk work activities or areas in which SSEs are not allowed to work.
 
17.                              STOP WORKAUTHORITY
 
17.1                        Stop Work Authority.Both Company and Contractor shall have the right to stop work at any time the work environment is imminently hazardous to persons, property or the environment. The Parts stopping the work shall immediately notify the other Party of the reasons for stopping the work. Contractor shall provide an estimate of when the work will resume. Contractor shall take all appropriate measures to abate the imminent hazard and limit the duration of the stop work and coordinate efforts with Company Representative to mitigate the effect of this stop work authority.
 
18.                              TRAINING
 
18.1                        Contractor shall ensure its employees are trained (and ensure that all members of Contractor’s Group are trained) in compliance with appropriate health, safety and environmental codes, standards, laws and regulations of all governmental or regulatory agencies having jurisdiction over the Services or the Area of Operations. Contractor shall ensure that this training also addresses potentially dangerous conditions, safe work practices and procedures, including safety training to ensure the proper use of any personal protection equipment required to perform the Services. At Company’s request, Contractor shall provide Company with a certification that training requirements are met and maintained.
 
18.2                        Prior to commencement of the Services, Contractor shall participate (and ensure that all members of Contractor Group participate) in a health, environmental and safety orientation with Company Representative.
 
19.                              MISCELLANEOUS
 
19.1                        Contractor shall secure (and ensure that all members of Contractor Group secure) compressed gas cylinders in place on a regular cart or chained to a support in an upright position. Contractor shall ensure that these cylinders are protected when not in use with protective valve caps. Furthermore, Contractor shall ensure that compressed oxygen and flammable gases are not stored together or near combustible materials, but stored in accordance with written instructions provided by Company or, if no instructions are provided, in accordance with generally accepted good international industry practice.
 
19.2                        Contractor shall ensure that no firearms, ammunition or deadly weapons are stored,brought upon or used in the Area of Operations except as may be authorized by Company (e.g., for security purposes to ensure protection of Contractor’s personnel and property).
 
19.3                        Contractor shall ensure that all of its safety equipment are properly maintained and in operable condition in accordance with manufacturer’s instructions, Company requirements and applicable laws.
 
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19.4                       Contractor shall review the final or completed work site and undertake any remedial measures required to remove hazards and restore the work site in accordance with Company requirements.
 
20.                              WORKER RECOGNITION AND AWARD PROGRAM
 
20.1                        If required by Company, Contractor shall develop a Worker Recognition and Award (R&A) Program to recognize and positively reinforce workers who exhibit safe work behaviors and teams that have an effective culture of safety. The Worker R&A Program shall be agreed by Company before Work begins. During the Work, the Company’s and Contractor’s Representatives shall oversee the Worker R&A Program, with awards implementation by Contractor’s line managers, supervisors and safety inspectors. The program could include:
 
·                                       Recognition of workers for stopping unsafe work.
 
·                                       Recognition of workers for reporting unsafe conditions, unsafe acts, at-risk behaviors and near misses.
 
·                                       Recognition of workers for completing safety activities, such as safety audits, inspections and behavioral observations.
 
·                                       Recognition of work teams for excellent housekeeping in their Work Area(s) or for completing high-risk activities safety.
 
·                                       Instant small awards to be handed out frequently to positively reinforce workers who are observed working safely.
 
20.2                        The Worker R&A Program shall not provide incentives to the Contractor for meeting pre-determined safety milestones (i.e. safe hours worked) or for attaining a certain incident rate.
 
20.3                        Rewards shall be material or monetary, as appropriate. Public recognition and positive feedback shall also be included, as appropriate for the local culture.
 
END OF EXHIBIT B
 
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EXHIBIT C
 
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EXHIBIT C TO OFFSHORE DRILLING CONTRACT
 
DRUG, ALCOHOL AND SEARCH POLICY
 
1.                                     GENERAL POLICY
 
1.1.                           Compliance.Contractor and Subcontractors (“Subcontractor” means any Person who is engaged by Contractor or another Subcontractor to provide the Services (other than a person engaged as an employee), but does not include the vendor of Products to Contractor) shall comply with Company’s drug, alcohol, and search policy (“Policy”) set out in this Exhibit, except to the extent that compliance is penalized under the laws of the United States or violates applicable laws.
 
1.2.                           Policy, Program and Training.Contractor and Subcontractors shall have in place a written controlled substance and alcohol policy, an implementation program, and a training program, that meet or exceed the requirements provided in this Exhibit. When required by law, Contractor shall comply with U.S. Department of Transportation (DOT) procedures for transportation workplace drug and alcohol testing programs, 49 CFR Part 40, and applicable DOT rules and regulations (or their equivalent in the Area of Operations).
 
1.3.                           Notice to Personnel.Contractor shall provide a written notice (set out in Section 2 of this Exhibit) to all personnel of Contractor and Subcontractors Who will be engaged in performing the Services in the Area of Operations, prior to assigning them to work under this Contract. Each of those individuals must be specifically made aware of Company’s and Contractor’s right to search.
 
1.4.                           Search.Contractor shall have the right to perform reasonable, unannounced searches of the personnel of Contractor or Subcontractors at any time while they are in the Area of Operations, including searches of personal vehicles and personal effects which are in or entering into the Area of Operations.
 
1.5.                           Testing.    Contractor shall have the right to perform reasonable, unannounced controlled substance and alcohol tests on the personnel of Contractor or Subcontractors at any time while they are in the Area of Operations. If a test is positive, the individual must be removed from the Area of Operations or cease performance of the Services until reinstatement is permitted by Company. The individual shall be similarly treated if he/she refuses or fails to have a requested test. Individuals testing positive or refusing tests are subject to reinstatement upon the agreement of Company and Contractor Management Representatives.
 
1.6.                           Post-Accident Testing.Contractor shall conduct an immediate preliminary evaluation into the circumstances of all accidents, injuries, near misses and mishaps in the Area of Operations which arise out of this Contract or the performance of the Services. This evaluation must include a review of the conduct and behavior of affected individuals following any incident or near miss involving these individuals to determine whether personnel performance contributed to the incident. Alcohol and/or controlled substances test(s) must be required by Contractor when the evaluation reveals a reasonable cause to suspect the presence of alcohol or controlled substances.
 
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1.7                              Training. At a minimum, Contractor’s and Subcontractors’ personnel (before arriving at the Area of Operations) shall receive training on all items listed in Sections 1.7A to 1.7D below and Contractor’s and Subcontractors’ supervisors shall receive training on all items listed in Sections 1.7A to 1.7E below:
 
A.                                Company’s and Contractor’s controlled substances and alcohol policies.
 
B.                                  The effects and consequences of controlled substance and alcohol use on personal health, safety and the work environment.
 
C.                                  The details of Contractor’s employee assistance program, if any, and available treatment resources.
 
D.                                 The consequences of failing to comply with Contractor’s and Company’s policies.
 
E.                                   The physical, behavioral and performance indicators that may indicate controlled substance and alcohol use or abuse.
 
1.8                              Records. Contractor shall keep records of activities in compliance with this Exhibit. These records must be maintained for at least twenty-four months after termination or completion of this Contract.
 
2.                                     NOTICE TO CONTRACTOR’S EMPLOYEES
 
2.1.                           Company’s Drug, Alcohol, and Search Policy.
 
2.1.1.                  The use, possession, distribution, purchase or sale of any controlled substances or alcohol by Contractor or Subcontractors or their personnel is prohibited while within the Area of Operations.
 
2.1.2.                  The use (in any place) of any controlled substance or alcohol which causes or contributes to unacceptable job performance or unusual job behavior in the Area of Operations is prohibited. Being under the influence of alcohol while within the Area of Operations is prohibited.
 
2.2.                           Penalty for Violation.Contractor and Subcontractors and their personnel who enter the Area of Operations shall comply with this Policy. Any Person violating the Drug, Alcohol and Search Policy may be removed from the Area of Operations and may be denied future access. In addition, Company may suspend the Services as a result of violation of this Policy or, in the event that Contractor is unwilling or unable to remedy violation of this Policy by its personnel, Company may terminate this Contract. In appropriate cases, local law enforcement agencies may be advised of violations.
 
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2.3.                           Searches and Testing.In support of this Policy, Company or Contractor may conduct or require searches and tests as follows:
 
2.3.1.                                                                    Searches.Unless prohibited by law, the following searches may be carried out:
 
2.3.1.1.         Company or Contractor may carry out reasonable searches of individuals and their personal effects and personal vehicles when entering the Area of Operations, while within the Area of Operations and when leaving the Area of Operations. These searches may be carried out at any time and without prior announcement.
 
2.3.1.2.         Entry by an individual into the Area of Operations constitutes consent to a search of the individual and his/her personal effects, including packages, briefcases, purses, lunch boxes and vehicle or any office, locker, closet or desk.
 
2.3.1.3.         An individual may elect to decline to cooperate; however, refusal to cooperate may result in the individual being removed from the Area of Operations and restricted or disqualified from performing the Services for Company.
 
2.3.2.                  Testing.Unless prohibited by applicable law, the following testing may be conducted:
 
2.3.2.1.         Company or Contractor may conduct or have conducted a controlled substance or alcohol test(s) on the personnel of Contractor or Subcontractors upon entering or while within the Area of Operations. This testing may be carried out at any time and without prior announcement.
 
2.3.2.2.         Prior written consent shall be obtained from any individual who is to be tested. A positive test or a failure to give written consent for a test or a substituted or adulterated test or a failure to take a requested test is cause for removal from the Area of Operations, and may result in the individual being restricted or disqualified from performing the Services for Company.
 
3.                                     DEFINITIONS
 
3.1.                           As used in this Exhibit, these terms have the following meanings:
 
3.1.1                     “Controlled substance” means:
 
3.1.1.1            Opiates, including heroin.
 
3.1.1.2            Hallucinogens, including marijuana, mescaline and peyote.
 
3.1.1.3            Cocaine.
 
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3.1.1.4            PCP.
 
3.l.1.5               Prescription drugs, including amphetamines, benzodiazepines and barbiturates, which (a) are not obtained and used under a prescription lawfully issued to the Person possessing them or (b) have been prohibited by Company for use in the Area of Operations by any personnel or personnel performing specified functions.
 
3.1.1.6            Any other substance included in the U.S. Federal Controlled Substances Act or its regulations or that is otherwise unlawful to possess or sell under applicable law.
 
3.1.2                     “Controlled substance testing” means testing to detect the presence of controlled substances.
 
3.1.3                     Controlled substance or alcohol “test” means any collection and analysis using urine, breath or other samples to determine the presence of controlled substances or alcohol in the body.
 
3.1.4                     “Under the influence of alcohol” or a “positive alcohol test” means having a blood alcohol concentration (%BAC) of 0.04% or above.
 
3.1.5                     Those terms defined in Exhibit B – Independent Contractor Health, Environmental and Safety Guidelines have the same meaning in this Exhibit C Company’s Drug Alcohol and Search Policy.
 
END OF EXHIBIT C
 
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EXHIBIT D
 
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EXHIBIT D TO OFFSHORE DRILLING CONTRACT
COMPENSATION
 
Contractor shall be compensated by Company for the Services in accordance with the rates set forth in this Exhibit D Compensation for Services rendered and the Drilling Unit, personnel and all other items furnished by Contractor in conformance with this Contract. Daily rates shall be prorated on the basis of a twenty-four hour calendar day to the nearest one-half hour. No other payments shall be due by Company to Contractor other than those specifically provided for in this Contract. Section numbers and summarized descriptions are provided below for convenience; however, if a conflict exists between this Exhibit and the Contract, the body of the Contract prevails.
 
I.                                        MOBILIZATION AND DEMOBILIZATION FEES.
 
1.                            Mobilization Feeper Section 8.l (A): 90% of the Operating Rate during mobilization. It is noted that the costs of providing the following items are specifically excluded from the Mobilization Fee: towing/transport vessels, anchor handling vessels, safety standby vessel, fuel for all vessels and the Drilling Unit, and rig positioning services which shall be provided by Company.
 
2.                            Demobilization Feeper Section 8.1(H): 90% of the Operating Rate to a point one (1) nautical mile from the last well location of this Contract.  It is noted that the costs of providing the following items are specifically excluded from the Demobilization Fee: towing/transport vessels, anchor handling vessels, safety standby vessel, fuel for all vessels and the Drilling Unit, and rig positioning services which shall be provided by Company until Demobilization is complete.
 
II.                                    DRILLING SERVICES RATES.
 
1.                                      Operating Rateper Section 8.1 (B):
 
(a)         During Mobilization/Demobilization : US$511,000
(b)        During Operations in Equatorial Guinea : US$545,067
(c)         During Operations in Ghana : US$537,895
(d)        During Operations in other countries : US$511,000 plus
adjustments required by Contract (i.e., Sections 13 and 26)
 
2.                                     Moving Rateper Section 8.1(C): 90% of Operating Rate.
 
3.                                      Standby with Crews Rateper Section 8.1(D): 90% of Operating Rate
Sections 8.1(D) (1) (2) and (3): the first twenty-four consecutive hours, the Operating Rate shall apply. Thereafter the Standby with Crews Rate shall apply.
 
Section 8.1(D) (4), the Standby with Crews Rate applies without the first twenty-four consecutive hours of the Operating Rate.
 
4.                                      Extended Standby Rateper Section 8.1(E): 80% of Operating Rate
 
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5.                                      Force Majeure Rate per Section 8.1(F): 90% of Operating Rate
 
·                                         First thirty (30) days: Stand-by with Crews Rate
·                                         After thirty (30) days, up to ninety (90) days: One-half of the Extended Standby Rate
·                                         After ninety (90) days: Zero Rate unless Contractor elects to terminate the Contract
 
6.                                      Redrill Rate per Section 8.1(G): 50% of Operating Rate
 
7.                                      Off Weather Rate per Section 8.1(K): 85% of the Operating Rate
 
8.                                      Variation of Service Rates per Section 8.3:
 
On the Commencement Date and subsequent one year anniversaries of the Commencement Date, the dayrates payable under the Agreement shall be subject to adjustment for cost increases incurred by Contractor, with the first calculated from the date of the Effective Date and subsequent calculations based on the anniversary date of the last calculation. Such cost increases must be documented by Contractor to the reasonable satisfaction of Company and shall include additional expenses incurred for payroll, payroll burden, insurance, travel costs and shorebase overhead. Additionally, twenty five percent (25%) of the Base Operating Rate of $511,000 shall be subject to annual adjustment, not to exceed 8% annually either upward or downward as the case may be, based on the Producer Price Index for Oil and Gas Field Machinery and Equipment (Series Id# pcu333132333132) (or, if such index is discontinued, a similar mutually agreeable inflation index) in effect for the month of the Commencement Date and on each successive one year anniversary date thereof for the duration of the Contract. For clarity, following the initial Operating Rate adjustment effective at the Commencement Date, each subsequent annual adjustment shall be made to the Operating Rate, as adjusted in the previous year.
 
III.                                REIMBURSEMENTS TO CONTRACTOR.
 
I. Meals and Lodging for Additional Persons:
 
Per Section 9.5: The Service rates set forth in Part II above include meals and lodging limited to available space for all of Company Persons and all of Company’s other contractors’ personnel: $1,000 lump sum per day
 
IV.                               MISCELLANEOUS FINANCIAL PROVISIONS.
 
COMPANY’s address for submission of CONTRACTOR’s paper invoices,  per Sec. 10.1(A):	 	CONTRACTOR’s banking information, per Sec. 10.2(E)(1):	
 	 	 	
c/o:	 	Intermediary Bank: Wachovia Bank, New York.	
Kosmos Energy Ghana HC	 	SWIFT Code: PNBP US3NNYC	
8401 N. Central Expressway, Suite 280	 	ABA Code: 026-005-092	
Dallas, Texas 75225	 	 	
 	 	 	
Noble Energy EG Ltd.	 	For Credit: FirstCaribbean International Bank
((Cayman) Ltd.	
100 Glenborough Drive, Suite 100	 	SWIFT Code: FCIB KYKY	
Houston, Texas 77067	 	Account No.: 2000192002655	
 
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 	 	For Further Credit: ALPHA OFFSHORE DRILLING	
 	 	 	
 	 	Account No.: 7001850	
 
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Currency of Payment,per Sec. 10.2(E)(3):
 
United States Dollars
 
Payroll Burdenper Sec. 1.1: Payroll Burden shall mean the following percentage of the straight time salary of each of Contractor’s employees: 40%
 
END OF EXHIBIT D
 
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EXHIBIT E
 
198

 
RIG SHARING AGREEMENT
(“ATWOOD HUNTER”)
 
This Rig Sharing Agreement (“Contract”) dated as of                             2008 is made by and between Kosmos Energy Ghana HC  a company, with offices at Clifton House, 75 Fort Street, George Town, Grand Cayman, Cayman Islands (“Kosmos”);  Noble Energy EG Ltd.,  a company with offices at 100 Glenborough Drive, Suite 100, Houston, Texas 77067 (“Noble”) and  Alpha Offshore Drilling Services Company,  a Cayman Islands company, with its registered office located at M&C Corporate Services Ltd., P.O. Box 309 GT, Ugland House, South Church Street, George Town, Grand Cayman, Cayman Islands (“Contractor”). These parties may also be referred to individually as “Party” or collectively as “Parties”.
 
Whereas,the Parties have entered into that certain Offshore Drilling Contract between Kosmos Energy Ghana HC and Noble Energy EG Ltd. and Alpha Offshore Drilling Services Company dated June        ,2008 (“Drilling Contract”);
 
Whereas,Kosmos and Noble have agreed to share the use of the Drilling Unit as specified in the Drilling Contract.
 
Now therefore, the Parties, for and in consideration of the mutual obligations, undertakings, premises and covenants herein contained do hereby agree as follows:
 
ARTICLE I – DEFINITIONS
 
1.1                                Capitalized Terms. Any capitalized term not specifically defined in this agreement shall have the same meaning as in the Drilling Contract.
 
1.2                                Reference to Sections. References to sections in this agreement shall be understood to be Sections of the Drilling Contract.
 
ARTICLE II – RIG SHARING PROCEDURES
 
2.1.                             Noble Affiliate Well(s) In Israel; Possible Adjustment of Initial Operating Term.The Parties acknowledge that Contractor (or its Affiliate) and Noble’s Affiliate, Noble Energy Mediterranean Ltd. (“Noble Med”) have entered into that certain drilling contract for one or two wells offshore Israel dated                                           , 2008 (“EMed Contract”). The E.Med Contract allows Noble Med to mobilize the Drilling Unit, drill and test one well (with an option to drill, but not test, a second well) in the Eastern Mediterranean. For purposes of determining the Operating Term of the Drilling Contract, the E.Med Contract has been allocated an estimated period of 166 days. To the extent that the actual total number of days used by Noble Med (including mobilization and operating) under the E.Med Contract is less or greater than 166 days, the days allocated to Noble under the Drilling Contract, and thus the initial Operating Term, shall be adjusted accordingly. Notwithstanding the foregoing, Kosmos and Contractor agree that Noble Med’s use of the Drilling Unit under the E.Med Contract may take more than 166 days, and the Parties currently estimate that all possible operations might
 
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take a total of approximately 202 days. In any event, if the number of days is less or greater than 166 days, the Operating Term of the Drilling Contract shall be adjusted accordingly, and any increase or reduction in Noble’s days shall occur in the drilling segment described in Section 3.2(A)(4) of the Drilling Contract.
 
2.2                                Mobilization from Noble Affiliate Well(s) In Israel; Possible Adjustment of Initial Operating Term. The Mobilization under the Drilling Contract from Israel to the Mauritania Line is estimated to take 35 days (and the cost is allocated under the Drilling Contract two-thirds to Noble and one-third to Kosmos), and the Mobilization from the Mauritania Line to one mile from Kosmos’ first well location in Ghana is estimated to take 20 days (and the cost is allocated under the Drilling Contract one-half each to Noble and Kosmos). To the extent that the actual Mobilization days are less or greater than the estimated days, the days shall he adjusted and allocated to Noble or Kosmos in the same proportion as cost has been allocated under the Drilling Contract (2/3 Noble and 1/3 Kosmos from Israel to the Mauritania Line and 50/50 from the Mauritania Line to Kosmos’ first well location in Ghana), and the initial Operating Term shall be adjusted accordingly.
 
2.3                                Limits On Spudding A Well At The End of Each Segment. Neither Kosmos nor Noble may spud a well during the time allotted to it in a time segment under Section 3.2(A) if the number of days left in that time segment is less than 30 days. Noble and Kosmos shall agree on such modifications of the time segments allotted to each in Section 3.2(A)(4) (for Noble) and Section 3.2(A)(5) (for Kosmos) as will fairly and equitably distribute any unused days or excess days from any earlier segment. That agreement shall be communicated to Contractor at least 30 days prior to expiration of each segment described at Section 3.2(A)(4) and Section 3.2(A)(5) or as may he otherwise agreed between Kosmos and Noble.
 
2.4                                Beginning of First Time Segment.The segment or time described in Section 3.2(A)(1) of the Drilling Contract shall begin when the Drilling Unit is one nautical mile from the first Kosmos well location to be drilled during that segment.
 
2.5                                End of Each Time Segment. Each time segment described in Section 3.2(A)(1) through (5) of the Drilling Contract shall end after (i) the Drilling Unit has finished drilling the last well to be drilled during that time segment, (ii) the last anchor has been bolstered; and (iii) the Drilling Unit is underway and one nautical mile away from the location of the last well drilled during that segment.
 
2.6                                Beginning of Each Time Segment After the First. The time segments described in section 3.2(A)(2) through (5) of the Drilling Contract shall begin at the same time as the prior segment ends as described in Article 2.5 above.
 
2.7                                Designation of First Well Location For EachTime Segment. No later than 30 days before termination of drilling operations on the last well drill during each time segment under Section 3.2(A), the Party allotted the time under the next time segment shall notify the Contractor in writing of the location or the first well to be drilled during that next time segment. The notice shall specify Lat/Long coordinates.
 
2.8                                Consumables. At the end of each time segment as provided in Article 2.5, Noble and Kosmos shall jointly take a written inventory and record it on the IADC report of all materials and supplies ordinarily considered as expendable or consumable in the well operations. The Party next receiving the Drilling Unit shall pay the other Party at cost for all expendables and/or consumables identified in the inventory. It is provided, however, that the Party receiving the Drilling Unit shall have the right to reject any expendables and/or consumables. Those items
 
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will then be removed from the Drilling Unit by the Party transferring the Drilling Unit unless otherwise agreed.
 
2.9                                Failure To Receive Drilling Unit. If Noble or Kosmos is unable to utilize or to assign its allotted time segment, that Party shall be required to make all payments to Contractor pursuant to the Drilling Contract until the other takes possession of the Rig for its assigned time segment.
 
ARTICLE III – THIRD PARTY SERVICES
 
3.1                                List of Third Party Service Providers. At least 30 days prior to Commencement Date, Noble and Kosmos will agree on a list of third party service providers to be contracted by Noble and Kosmos for services on the Drilling Unit during the Operating Term of the Drilling Contract. Noble and Kosmos shall work together to identify and contract such services to minimize changeover of such personnel and services at the end of each time segment.
 
ARTICLE IV – RIGHTS AND DUTIES AND INDEMNITIES
 
4.1                                Rights and Obligations Before The First Time Segment Begins. From Commencement Date until the first time segment provided for in Section 3.2(A)(1) begins as provided in Article 2.1 above, the rights and duties of Noble and Kosmos shall be as provided in the Drilling Contract.
 
4.2                                Rights and Duties Between Noble and Kosmos During Operating Term. The rights and obligations of Noble and Kosmos during the Operating Term under the Drilling Contract shall enure to the benefit of and be binding upon each of Kosmos and Noble based upon the time allotted to each as identified in Articles 2.3, 2.4, 2.5 and 2.6 hereof. The liability of Kosmos and Noble, respectively, to Contractor under the Contract shall be several and not joint with respect to the days included in each time segment.
 
4.3                                Indemnities During Each Time Segment. Each of Noble and Kosmos shall indemnify and hold the other harmless from any and all liability, cost, damage or expense owed by the indemnifying Party under the Drilling Contract during the time segments allotted to each from the time a segment begins until it ends as provided in Article II above. During that time, Company shall be deemed to be either Noble or Kosmos depending upon which of those two Parties has been allotted the time segment. Contractor shall not look to one Party for any obligation or liability arising under the Drilling Contract during a time segment allotted to the other Party.
 
ARTICLE V – EFFECT OF EARLY CONTRACT TERMINATION
 
5.1                                Termination of the Drilling Contract Before the First Time Segment. Any termination rights of Company under the Drilling Contract before the first time segment described in Section 3.2(A)(1) begins shall be exercised by Noble and Kosmos only upon unanimous agreement between those parties. In such event, the terms of the Drilling Contract shall apply to each in proportion to the number of days allotted to each during the remainder of the Drilling Contract; to the extent that termination occurs before the first segment begins under Section 3.2(A)(1), the allocation of any remaining mobilization days shall be in proportion to the percentages applicable to Noble and Kosmos in Section 2.4 of the Drilling Contract.
 
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5.2                                Termination of the  Drilling Contract After the First Time Segment  Begins. Any termination of the Drilling Contract by either Noble or Kosmos during a time segment in which either is using the Drilling Unit shall not affect the rights of the other to use the Drilling Unit for the next time segment except that all remaining time segments of that Party under the Drilling Contract shall be consolidated into one continuous segment from the date of termination. To the extent the non-terminating Company reasonably requires additional time to get ready to commence operations prior to commencement of its next scheduled segment, the terminating Company shall pay Standby With Crews Rate until the non-terminating Company is ready to commence operations. . It is provided, however, that neither Noble nor Kosmos shall terminate the Drilling Contract for convenience during a time segment in which either is using the Drilling Unit except upon agreement by both such Parties.
 
5.3                                Termination of the Drilling Contract  By Contractor. If the Contractor terminates the Drilling Contract during any time segment, the Drilling Contract shall continue as to the Party entitled to use the Drilling Unit in the next time segment except that all remaining time segments of that Party under the Drilling Contract shall be consolidated into one continuous segment from the date of termination. To the extent the non-terminated Company reasonably requires additional time to get ready to commence operations prior to commencement of its next scheduled segment, the terminated Company shall pay Standby With Crews Rate until the non-terminated Company is ready to commence operations.
 
5.4                                Notice of Disputes. Noble and Kosmos shall promptly notify each other of any dispute either may have with the Contractor during any time segment under the Drilling Contract as soon as possible after the occurrence of the dispute.
 
ARTICLE VI – INSPECTION OF DRILLING UNIT
 
6.1                                Prior to Commencement of Services. Prior to the Commencement Date, Noble and Kosmos will share the cost of inspection of the Drilling Unit by a third party on the basis of 50% each.
 
ARTICLE VII – ASSIGNMENT
 
7.1                                Assignment of the Drilling Contract Subject To This Agreement. Any assignment of the Drilling Contract shall be made subject to this agreement. Any assignment of the Drilling Contract without being subject to this agreement shall be null and void.
 
7.2                                Assignment of This Agreement. This agreement may be assigned on the same basis as provided in the Drilling Contract for assignment of that agreement subject to Article 7.1 above.
 
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ARTICLE VIII - INSURANCE
 
8.1                                No Additional Insurance. None of the Parties shall be required to carry insurance for purposes of this agreement. The Parties, however, shall maintain the insurance coverage provided for under the Drilling Contract.
 
ARTICLE IX - TERM
 
9.1                                Concurrent Terms.Theterm of this agreement shall run concurrently with the duration of the Drilling Contract.
 
9.2                                Early Termination. No Party shall have the right to terminate this agreement before termination of the Drilling Contract.
 
ARTICLE X - GOVERNING LAW AND DISPUTE RESOLUTION
 
10.1                          Reference to Drilling Contract. The governing law and dispute resolution provisions of the Drilling Contract shall apply to this agreement.
 
ARTICLE XI - CONFIDENTIALITY
 
11.1                          Undertaking. Noble and Kosmos each undertake to keep confidential all information received from the other regarding the activities performed within this agreement and under the Drilling Contract (“Confidential Information”).
 
11.2                          Exclusion.Forpurposes of this Agreement, Confidential Information shall not include any information that:
 
(A)                             corresponds in substance to information developed by either such Party prior to receipt of Confidential Information under this agreement; or
 
(B)                               is public information generally known on a non-confidential basis in the petroleum industry;
 
(C)                               corresponds in substance to information legally furnished to either such Party before, during or after entering into this agreement by others as a matter of right without restriction on disclosure; or
 
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(D)                              disclosure of the Confidential Information is required pursuant to an order of a court, government instrumentality, or securities exchange, properly exercising jurisdiction over the matter.
 
11.3                          Duration of Confidentiality Obligation. The obligation to keep information confidential in accordance with the terms of this article shall continue for two years after expiration of the term of this agreement.
 
ARTICLE XII - GENERAL PROVISIONS
 
12.1                          NoWaiver. No waiver by a Party of any one or more breaches of this agreement by any other Party shall operate or be construed as a waiver of any future default or defaults by the same Party. No Party shall be deemed to have waived, released, or modified any of its rights under this agreement unless such Party has expressly stated, in writing, that it does waive, release or modify such rights.
 
12.2                          Modification.Thisagreement may not be modified except by written consent of the Parties.
 
12.3                          Headings. The topical headings used in this agreement are for convenience only and shall not be construed as having any substantive significance or as indicating that all of the provisions of this agreement relating to any topic are to be found in any particular article or provision.
 
12.4                          Singular and Plural.Referenceto the singular includes a reference to the plural and vice versa.
 
12.5                          Counterpart Execution. This agreement may be executed in counterparts and each counterpart shall be deemed an original agreement for all purposes; provided that neither Party shall be bound to this agreement until both parties have executed a counterpart.
 
12.6                          Entirety. This agreement, along with the Drilling Contract, comprises the full and complete agreement of the Parties regarding the subject matter hereof and supersedes and cancels all prior communications, understandings, and agreements between the Parties whether written or oral, expressed or implied.
 
12.7                          No Third Party Beneficiaries. Except as otherwise provided in the Drilling Contract, the interpretation of this agreement shall exclude any rights under legislative provisions conferring rights under a contract to persons not a party to that contract.
 
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ARTICLE XIII - NOTICES
 
13.1                          All notices authorized or required between the Parties by any of the provisions of this agreement shall be in writing, properly addressed to the other Party as shown below, and delivered in person, by courier, or by facsimile transmission. Oral communication and e-mails do not constitute notice for purposes of this agreement. A notice given under any provision of this agreement shall be deemed delivered only when received by the Party to whom the notice is directed. “Received” for purposes of this article means actual delivery of the notice to the address or facsimile address of the Party shown below.
 
13.2        Addresses:
 
Kosmos Energy Ghana HC
c/o Kosmos Energy Inc.
8401 N. Central Expressway, Suite 280
Dallas, Texas 75225
Attention: Marvin Garrett
Facsimile: 214-363-9024
 
Noble Energy EG Ltd.
c/o Noble Energy Inc.
100 Glenborough Drive, Suite 100
Houston, Texas 77067-3610
Attention: Ron Jordan
Facsimile: 281-872-2511
 
Alpha Offshore Drilling Services Company
332A-11C, 11th Floor, Plaza Ampang City
Jalan Ampang
50450 Kuala Lumpur, MALAYSIA
Attention: Tony Dyne
Facsimile: 603-4257-9208
 
With copies to:
Atwood Oceanics, Inc.
Attention: Glen P. Kelley
15835 Park Ten Place Drive
 
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Houston, Texas 77084
Facsimile: 281-578-3253
 
IN WITNESS WHEREOF,the authorized representatives of the Parties hereto have executed this agreement effective on the day and year first above written.

Kosmos Energy Ghana HC	 	

By	 	 	

Noble Energy EG Ltd.	 	

By	 	 	
David L. Stover	 	
Executive Vice President and COO	 	

Alpha Offshore Drilling Services Company	 	

By	/s/ Anthony H. Dyne	 	
Anthony H.Dyne	 	
Director	 	
 
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EXHIBIT E TO OFFSHORE DRILLING CONTRACT
 
RIG SHARING AGREEMENT
(CHART)

 

 

 
EXHIBIT F

 
EXHIBIT F TO OFFSHORE DRILLING CONTRACT KOSMOS INVOICING PROCEDURE
 
1.            All original invoices shall be addressed as follows:
Kosmos Energy Ghana HC
C/o Kosmos Energy, LLC
Attn: Accounts Payable
8401 N. Central Expressway, Suite 280
Dallas, Texas 75225 USA
 
2.            In addition to Contractor’s other requirements, invoices must contain the following information and be submitted with all supporting documentation. Invoices may NOT be submitted in electronic form, specifically not email or facsimile, only original invoices with original signatures shall be accepted.
 
a)                                     Contractor’s name, address, contact phone and fax numbers;
b)           Sequential invoice numbering system, commensurate with Contractor’s needs;
c)            Invoice Date;
d)           Reference: Ghana;
e)            Contract No.          , dated the          day, of          , 2007;
f)            Work Order No.
 
3.            All invoices must be in U.S. dollars (USS) and have a clear breakdown of Goods and Services.  The Contractor shall issue separate invoices in respect of Work performed in Ghana or Ghanaian territorial waters and Work performed outside of Ghana. The invoice shall contain one of the following statements identifying the appropriate tax requirement:
 
a)            For Work performed outside Ghana, the following wording must appear on the invoice:
“Work rendered outside Ghana, not taxable.”
b)           For Work performed inside Ghana:
“This invoice relates to Work performed in Ghana and is subject to withholding tax to be withheld by Kosmos.”
 
NOTE 1: Company, as required under the terms of the petroleum agreement governing the West Cape Three Points Block, shall withhold 5% of the value of invoiced goods and services rendered within the Republic of Ghana including its territorial waters. For all goods and services provided from outside the Republic of Ghana no withholding tax shall be withheld.
 
NOTE 2: Company is exempt from Value Added Tax (VAT) in its operations and will provide certificate to this effect upon request of Contractor. VAT should not therefore appear on invoices submitted to Company under the provisions of the present Invoicing Procedure (Attachment “B”).
 
NOTE 3: Company and its Contractors are exempt from any import duties/taxes, with the exception of minor administrative charges, on goods and materials imported into the Republic of Ghana that are to be used to perform the Work, subject to compliance with certain procedures.
 
4.            The following amounts should be shown on each invoice:
 
Invoice Amounts
 
Total Gross	 	$	 	 	
Tax to be Withheld by Company	 	$	(         	)	
Total Amount Due	 	$	 	 	
 
Sample Text Section of an Invoice:

 
 	 	 	 	Amount	 	
Item	 	Description	 	Subtotal	 	Totals	 	
01	 	Service 1	 	100.00	 	 	 	
02	 	Service 2	 	100.00	 	 	 	
 	 	Total	 	 	 	$	200.00	 	
 	 	5% Tax Withheld (if applicable)	 	 	 	$	(10.00	)	
 	 	TOTAL DUE	 	 	 	$	190.00	 	
 	 	Include payment information as requested in Item 7 on all invoices.	 	 	 	 	 	
 
5.            Payment Information: Each invoice should provide the following payment information:
 
Remit payment by wire transfer or USS check to:
Check made payable to :
Mailing address:
OR
Wire transfer details:
Bank Name:
Account Name:
Account Number:
ABA Routing Number:
Swift Code:
Other
 
6.            The original invoice should contain an original signature by a named representative of Contractor;
 
7.            To facilitate invoice processing and assure prompt payment, the initial invoice under the Contract should contain, as support, a copy of the official and initialed Contract rate schedule or quote;
 
8.            A cover letter to Company detailing the invoices being submitted for payment should accompany each group of invoices and contain an attachment by invoice number of an accounts receivable report for any invoices Contractor has pending with Company; and,
 
9.            All invoices must have the “text” in English.
 
10.          Contractor is responsible for ensuring compliance with all tax laws and administration of its affairs.
 
11.          Should Contractor have any questions regarding Invoice Procedures, please address them to:
 
Kosmos Energy Ghana HC
c/o Kosmos Energy, LLC
Accounts Payable Department,
8401 N. Central Expressway, Suite 280
Dallas, Texas 75225 USA,
Telephone: 972-739-7700
 
12.          Failure to follow these instructions will result in the invoice being returned for re-submittal of a conforming invoice.

 
EXHIBIT G

 
EXHIBIT G TO OFFSHORE DRILLING CONTRACT
ATWOOD OCEANICS AND AFFILIATES
CODE OF CONDUCT
 
Introduction – The Company believes that its greatest resource is you, the employee. Together, we all have a responsibility to conduct ourselves in a manner which is in compliance with high ethical and legal standards while meeting the growing business needs and challenges in our industry. It is important that we conduct our business honestly and fairly.
 
This booklet will explain the policies which have been adopted by the Company to ensure that we perform our business at high ethical standards while meeting the continuing business needs of our customers.
 
Remember, “actions speak louder than words” and we will be held accountable for our actions by our customers, who hold the success of this Company and all of us in their hands. Accordingly, as we certify our compliance with these policies on the attached Certificate Of Compliance, let’s continue to meet these very important ethical and legal standards.
 
All Corporate Office, Regional Office, and Shorebase Rig Operations personnel will be required to review the Code Of Conduct and execute the accompanying Certificate Of Compliance on an annual basis.

 	John R. Irwin	
 	 	
 	President and CEO	
 
The Company would advise all employees that:
 
Responsibility Every employee and supervisor has the responsibility and duty to certify compliance with our policies and to report any concern or allegation of wrongdoing to their supervisors, the Human Resources Department, or the Legal Department.

 
No Contract of Employment — This Code of Conduct and the policies contained herein shall not constitute a contract of employment and may be amended, modified, or terminated by the Company at any time with or without notice.
 
Ethics — All employees are required to handle the Company’s business with integrity, honesty, respect, and in compliance with high ethical and legal standards.
 
Insider Trading — It is imperative that all information, of any kind, which we learn about the Company and/or a customer during the course of our business, be kept in the strictest confidence. It is a violation of the law to pass material non-public information about our employer, customers or suppliers which was obtained in the course of employment. The law provides for civil and criminal penalties including imprisonment for violations of these provisions. It is a violation of this policy and the law to buy or sell securities or engage in any other action to take advantage of or pass on to others, that information which is material and non-public. Violators may be subject to corrective discipline up to and including termination, in addition to prosecution under applicable federal and state statutes. If you have any questions or concerns, please contact the Legal Department.
 
Antitrust — The Company requires each employee to comply with all legal requirements relating to our dealings with customers, competitors, and vendors when the Company is selling or buying services. It is a violation of this policy and the law to:
 
·                      bribe or take a bribe as a means of influencing someone to take action in violation of their legal or ethical duties and responsibilities.
 
·                      fix or stabilize prices.
 
·                      engage in bid rigging.
 
·                      allocate or steer customers under any agreement with our competitors.
 
·                      agree with our competitors upon certain terms or conditions of sale.
 
Confidentiality — The Company’s customer/client lists, price lists, books, records, pricing techniques, equipment, services, technical information and related material regarding products and our trade secrets all constitute confidential information and shall not be disclosed by employees. Further, the Company and employees are prohibited from acquiring confidential or proprietary information (including technology) about other companies through illegal means, including deceit, misrepresentation, or receipt of information illegally acquired by a third party or from present or former employees who are not authorized to disclose it under all applicable laws. All employees must sign a Confidentiality Agreement and certify compliance with this policy and may also be required to certify compliance on an annual basis. Upon termination of employment from the Company, every employee must return to his or her supervisor all of the Company’s trade secrets and confidential information which he or she was given during the course of employment.
 
Foreign Corrupt Practices Act — All employees, consultants, and their agents and representatives are required to comply with the provisions of the Foreign Corrupt Practices Act (“FCPA”). Although the FCPA is a U.S. law, it can have application to the conduct of the Company’s business around the world. The FCPA prohibits the corrupt offer, payment or gift of money or anything of value to a foreign government official or employee or to any foreign political candidate or party for the purpose of

 
influencing any act or decision of a government body in order to obtain or retain business or to direct business to any person. Please contact the Legal Department if you have any questions or concerns.
 
Communications Systems — The Communications Systems of the Company shall mean all work stations, computers, E-mail, telephones, voicemail, fax machines, internal and external electronic bulletin boards, wire services, on-line services and the Internet (when access, e.g. to wire services, on-line services and the Internet Account, is provided be the Company). All employees and consultants using the Company’s Communications Systems shall be defined as Users and are required to comply with the following:
 
a.                                      Users of the Company’s Communications Systems must insure that the Communications Systems are used for legitimate business purposes.
 
b.                                     The Company’s Communications Systems shall be defined to mean any and all means of communication with the Company’s employees, customers, vendors, contractors, agents, etc., and shall include but is not limited to, interoffice mail, voicemail, E-mail, pagers, cellular or digital phones, computers, telephones, and the software and wiring to access these forms of media, photocopy machines, facsimile machines, and the like.
 
c.                                      Users shall be defined to mean employees, agents, contractors, and others who have been authorized by the Company to access the Communications Systems.
 
d.                                     The Company shall have the right to monitor, access and disclose, for any purpose, the contents of any messages saved in the Communications Systems, and all Users waive any right of privacy expectation upon their use of the Communications Systems and further consent to said access or monitoring by the Company.
 
e.                                      Users must insure that their use of the Communications Systems does not compromise the security and integrity of the Company’s systems. Further, all Users must follow all rules and procedures regarding protection against viruses, encryption and all password requirements.
 
f.                                        Users must comply with federal, state, and local laws, including, but not limited to copyright, harassment, discrimination, defamation, privacy, publicity, and obscenity.
 
g.                                     Users must refrain from using the Communications Systems for chain mail, harassing others, posting abusive or demeaning messages, posting comments directly or indirectly in chat rooms regarding the business of the Company, and infringing on the rights of others.
 
Equal Employment Opportunity — The Company is an equal opportunity employer and will not tolerate or condone discrimination in employment on the basis of race, age, color, gender, sexual preference, religion, national origin, disability, or veteran status.
 
All employees shall comply with all federal, state, and local laws prohibiting discrimination in employment. An individual’s race, color, gender, sexual preference, national origin, religion, age, or disability shall not be considered in any hiring or promotion decision, shall not cause an individual to be treated differently in the terms and conditions of employment or in the exercise of any disciplinary action, including termination; shall not subject the person to harassment or allow harassment to occur, Further,

 
the Company shall not segregate or sponsor functions which segregate on the basis of any individual’s race, gender, sexual preference, color, national origin, religion, age, or disability.
 
It shall constitute a violation of this policy if employees fail to cooperate in a truthful and forthcoming manner in connection with any investigation of any complaints or concerns which may arise about discrimination and an employee’s employment. Further, retaliation against an employee who reports concerns about equal employment opportunity will not be tolerated.
 
Harassment — All employees shall comply with all federal, state and local laws governing the prevention of harassment in the workplace of any employee, consultant, or customer on the basis of gender, sexual preference, race, color, national origin, religion, age, disability or veteran status.
 
Drugs and Alcohol — The Company is a Drug-Free Workplace and alcohol is not permitted on Company premises except with the express permission of the Company. All Employees are required to comply with all federal, state and local laws governing the use of drugs and alcohol.
 
Environmental — All employees are required to comply with the federal, state, and local laws relating to the environment, human health, wildlife, and natural resources, and all safety laws, rules, and regulations including occupational safety and health standards. Smoking is not permitted on Company property except in designated areas.
 
Safety and Health — The Company is committed to striving to provide a safe and healthy work environment for all employees. Safety management systems have been developed to help us to identify, monitor and control hazards as best as reasonably practicable to promote safe and healthy working conditions for all. Every employee has a personal responsibility to follow our safety management systems and to watch out for their own health and safety as well as the safety of others. Accordingly, employees are encouraged to report any safety or health related concerns to their supervisor or the Safety and Training Department.
 
Quality — The Company prides itself on providing quality services to its clients. The fundamental quality of the Company’s services has been, and will continue to be, the very foundation of our success. In order to continue to strive for quality operations, the Company depends upon the ongoing efforts of our valued employees to continually seek to improve all facets of our operations. The Company is committed to providing its employees with the resources to achieve and maintain these goals.
 
Conclusion - All employees are reminded that they are employed at the will of the Company and this Code Of Conduct shall not be construed to form an express or implied contract of employment. The Company also reminds all employees that all policies may be amended, changed or withdrawn at any time with or without notice. Employees are encouraged to review all Company policies periodically as this Code Of Conduct is only intended to provide you with a brief summary of the various Company policies. All employees are required to sign and date the following Certificate Of Compliance and return it to the Legal Department. All employees may also be requested to similarly sign and return a Certificate Of Compliance on an annual basis.

 
MEMORANDUM
 
TO	:	 	ALL EMPLOYEES OF ATWOOD OCEANICS AND ITS AFFILIATES	
 	 	 	 	
FROM	:	 	John Irwin	
 	 	 	 	
DATE	:	 	11 January 2007	
 	 	 	 	
SUBJECT	:	 	ATWOOD OCEANICS AND AFFILIATES BUSINESS ETHICS COMPLIANCE	
 
Atwood Oceanics and its various affiliates and subsidiaries always strive to ensure that all of its business affairs are conducted in compliance with all legal requirements and in full conformity with high ethical standards. One aspect of these business objectives involves compliance with the provisions of the  Foreign Corrupt Practices Act.  This Memorandum is intended to provide you with additional details regarding this important issue beyond what is provided to you by our Company Policy Statement regarding this Act. This Memorandum also provides you with a brief review of Atwood’s Gift Acceptance Guidelines as additional guidance and advice to assist you in maintaining Atwood’s corporate culture of high ethical standards and manner of fair dealing with everyone we come in contact with.
 
The Foreign Corrupt Practices Act (“FCPA”) 15 U.S.C. sections 78 dd-1, et seq., is a U.S. Federal law that requires publicly traded companies (like Atwood) to maintain records that accurately represent the company’s transactions and have an adequate system of internal accounting controls. The  FCPA  was adopted in 1977, and then amended in 1998, to add certain anti-bribery provisions. The  FCPA  prohibits the corrupt offer, payment, or gift of money (or anything of valu) to a foreign government official, employee, or any foreign political candidate or party for the purpose of influencing any act or decision of a government body or official in order to obtain or retain business or to direct business to any person. There is a distinction between such acts of bribery and facilitation payments. A facilitation or “ grease payment ” is permitted if: i) it is not in violation of any local laws and, ii) is made to a foreign official, political party, or party official to expedite or secure the performance of a clerical or routine governmental action  that they were already bound to perform .
 
In order to try to provide some clarity and guidance, the FCPA provides a list of examples which qualify as routine governmental actions: obtaining permits, licenses, or other official documents; processing governmental papers such as visas and work orders; providing police protection and mail service; providing phone service, power and water supply, loading and unloading cargo, or protecting perishable products; and scheduling inspections associated with contract performance or transit of goods across country.
 
Occasionally, some companies would try to circumvent the restrictions of the FCPA by working through unscrupulous local representatives. However, the  FCPA  also prohibits corrupt payments made by intermediaries. Intermediaries may include joint venture partners or agents. Accordingly, it is unlawful to make a payment to a third party (intermediary) knowing that all or a portion of the payment will go directly or indirectly to a foreign official. The term “knowing” does include conscious disregard and deliberate ignorance.

 
The penalties for violating the FCPA’s anti-bribery provisions can be severe. On the criminal side, corporations are subject to a fine of up to $2,000,000. Corporate officers, directors, stockholders, employees, and agents are subject to a fine of up to $100,000 and imprisonment for up to five (5) years. Further, under the Alternative Fines Act, the fines assessed could be up to twice the benefit that the defendant sought to obtain by making the corrupt payment. Fines imposed on individuals may NOT be paid by their employer or principal. On the civil side, the Attorney General or the SEC may commence a civil action for a fine of up to $10,000 against any firm as well as any officer, director, employee, or agent of a firm or a stockholder acting on behalf of the firm who violates the anti-bribery provisions of the  FCPA . Additionally, in an SEC enforcement action, the court may impose an additional fine not to exceed the greater of (i) the gross amount of the pecuniary gain to the defendant as a result of the violation, or (ii) a specified dollar limitation. The specified dollar limitations are based upon the seriousness of the violation and range from $5,000 to $100,000 for an individual and $50,000 to $500,000 for a business entity. There also could arise a private cause of action for a violation of the anti-bribery provisions of the  FCPA . A competitor that alleges that the bribery resulted in the defendant’s securing of a foreign contract could seek three (3) times its damages under the Racketeer Influenced and Corrupt Organizations Act (“RICO”).
 
Violations of the FCPA can be a very serious matter for both corporations and individuals alike. In addition to the fines and penalties discussed above, there is also the potentially serious damage to a company’s reputation and value as well as damage to the reputation, career, and personal life of any individuals involved. Atwood wishes to make clear to everyone that we will not support nor condone any actions which constitute a violation of the  FCPA .  If someone is in doubt about whether the situation they are faced with would constitute a violation of the  FCPA , do not proceed with the transaction. Seek advice and input from your supervisor, senior management, or Atwood’s legal department before proceeding further. You should also be mindful that we all still have our annual Audit Committee Confirmation responsibility to disclose any direct or indirect payments to government officials/employees from corporate funds as well as all facilitating/expediting (‘grease”) payments in excess of $500.
 
In addition to FCPA compliance, it is also important to remember that the reputation of Atwood and the legacy of our individual careers can be harmed by the acceptance of a bribe, kick-back, improper gift, or other compensation from any vendors or companies that wish to do business with Atwood.  If a gift is offered to you and it influences (or appears to influence) your business decision on behalf of Atwood, you should not accept the gift.  A copy of Atwood’s 10 May 2004 Gift Acceptance Guidelines is included herewith for your information which you should review. We appreciate everyone’s efforts to preserve and protect the reputation of Atwood Oceanics by maintaining our corporate culture of high ethical integrity and honest business standards.

 

ATWOOD OCEANICS
 
FOREIGN CORRUPT PRACTICES ACT
POLICY STATEMENT
 
It is the goal of Atwood Oceanics to conduct its business in compliance with all laws and regulations and in conformity with high ethical standards. In pursuit of this goal, the Company prohibits its employees, representatives, and agents from violating the Foreign Corrupt Practices Act (“FCPA”) 15 U.S.C §78. The FCPA prohibits the corrupt offer, payment, or gift of money or anything of value to a foreign government official, employee, or any foreign political candidate or party for the purpose of influencing any act or decision of a government body or official in order to obtain or retain business or to direct business to any person. A facilitating or “grease payment” to a foreign official, political party, or party official to expedite or to secure the performance of a routine governmental action (i.e. obtaining permits or licenses; processing governmental papers like visas and work orders; providing police protection or scheduling inspections; providing phone service, power or water supply; or actions of a similar nature) is not considered a violation of the FCPA.
 
A violation of the FCPA may result in the imposition of significant civil and criminal penalties for the Company as well as for individual employees. A violation of the FCPA is also considered by the Company to be serious misconduct and may be cause for disciplinary action up to and including immediate termination of the involved employee(s).

 	/s/ John R. Irwin	
 	John R. Irwin	
 	President and CEO	
 
(I)          Rev. 0
 
February 2003

 
EXHIBIT H

 
EXHIBIT H TO OFFSHORE DRILLING CONTRACT
 
PARENT OR ULTIMATE HOLDING COMPANY GUARANTEE
 
THIS GUARANTEEis made the                  day of                                       2008, by Noble Energy Inc, a company with offices at 100 Glenborough, Suite 100, Houston, Texas 77067-3610 (hereinafter called the “GUARANTOR”) in favour of Alpha Offshore Drilling Services Company,  a company registered in the Cayman Islands under registration number 1140 whose registered office is situated at c/o M&C Corporate Services Limited, P.O. Box 309GT, Ugland House, South Church Street, George Town, Grand Cayman, Cayman Islands (hereinafter called “CONTRACTOR” which term includes its successors and assigns). GUARANTOR is the parent or ultimate holding company of  Noble Energy EG Ltd  (hereinafter called the “COMPANY”).
 
WHEREAS:
 
1.                   This Guarantee is supplemental to a contract dated the                               day of June 2008, and made between COMPANY and  Kosmos Energy Ghana HC  (or its relevant subsidiary) of the one part and CONTRACTOR of the other part (hereinafter called the “CONTRACT”) whereby CONTRACTOR agrees and undertakes to provide the semisubmersible drilling unit ATWOOD HUNTER and associated services at the request of COMPANY for the relevant work segments of the CONTRACT (hereinafter called the “SERVICES”).
 
2.                   GUARANTOR is the parent or ultimate holding company of COMPANY.
 
3.                   GUARANTOR is aware of the subject matter and terms and conditions of the CONTRACT and COMPANY’s obligations thereunder.
 
4.                   GUARANTOR has agreed to guarantee the performance of COMPANY and/or any of its affiliates or assignees with respect to COMPANY’s obligations under the CONTRACT. Any reference to COMPANY in this document shall also include any and all such affiliates and/or assignees, if applicable.
 
5.                   GUARANTOR is empowered to enter into this Guarantee and has taken all steps to ensure that when executed, this Guarantee shall be valid and binding in accordance with the terms hereof.
 
NOW THIS DEEDWITNESSETH and GUARANTOR hereby agrees as follows:
 
1.                   In this Guarantee “DEFAULT” means failure on the part of COMPANY to execute and complete the SERVICES or any part thereof in accordance with the CONTRACT, or a breach of any of COMPANY’s obligations under the CONTRACT or failure on the part of COMPANY to comply with any court order arising out of or in connection with the CONTRACT or the enforcement thereof; and “REMEDY” or “REMEDYING” means to make good, or making good, such DEFAULT.
 
2.                   If COMPANY shall commit any DEFAULT, GUARANTOR shall:

 
a)                  indemnify CONTRACTOR against all loss, damage, liability, claims, demands, proceedings, costs and expenses arising from such DEFAULT without the necessity for CONTRACTOR to seek any remedy or proceed first against COMPANY or any other person or to enforce any other security for COMPANY’s obligations; and
 
b)                 if CONTRACTOR requires by notice in writing, REMEDY or procure the REMEDYING by COMPANY of such DEFAULT.
 
3.                   If GUARANTOR is unable or unwilling to REMEDY or to procure the REMEDYING by COMPANY of the DEFAULT but is able and willing at its own cost to engage a third party (to be named by GUARANTOR) to REMEDY the DEFAULT, GUARANTOR shall notify CONTRACTOR writing accordingly. If CONTRACTOR, in its complete discretion, consents in writing to the engagement of such third party, GUARANTOR shall without delay engage the third party PROVIDED that GUARANTOR shall be responsible for all acts and omissions thereof as if GUARANTOR were itself undertaking the REMEDYING of the DEFAULT. Failure by the third party to REMEDY the DEFAULT shall be treated as a DEFAULT and GUARANTOR shall indemnify CONTRACTOR accordingly.
 
4.                   GUARANTOR, when giving notice to CONTRACTOR under clause 3 above or as soon as reasonably practicable thereafter, shall provide CONTRACTOR. with such information as CONTRACTOR may reasonably require or request in order to reach a speedy decision whether or not to give its consent.
 
5.                   The liability of GUARANTOR shall be as primary obligor and not merely as surety and shall not be Impaired or discharged by reason of any of the following (whether or not GUARANTOR has notice thereof or has consented thereto):
 
a)                  any arrangement made between COMPANY and CONTRATOR;
 
b)                 any alteration in the obligations undertaken by COMPANY;
 
c)                  any variation of the SERVICES or other additional or substituted work undertaken by COMPANY and/or CONTRACTOR under the CONTRACT;
 
d)                 any indulgence or forbearance shown by CONTRACTOR towards COMPANY or GUARANTOR whether as to performance, time for performance, payment, time for payment or any other matter, or any arrangement entered into or composition accepted by CONTRACTOR modifying (by operation of law or otherwise) the rights and remedies of CONTRACTOR under the CONTRACT or any action or failure to act or delay on the part of CONTRACTOR;
 
e)                  any failure or delay by CONTRACTOR in enforcing any other security given for COMPANY’s obligations or any release by CONTRACTOR of such security whether in whole or in part;
 
f)                    any action lawfully taken by CONTRACTOR to determine or suspend (or to resume alter suspension) the CONTRACT;
 
g)                 any change in the relationship between GUARANTOR and COMPANY;
 
h)                 any invalidity of the CONTRACT;

 
i)                     any disability, incapacity or change in the status or constitution of COMPANY, GUARANTOR or CONTRACTOR;
 
j)                     the liquidation or dissolution of COMPANY, the insolvency of COMPANY or any receivership, judicially supervised administration, moratorium, composition of creditors, claims or other analogous event affecting COMPANY or any of its property. If COMPANY loses its separate legal identity, GUARANTOR shall become directly liable for the performance of COMPANY’s obligations under the CONTRACT;
 
k)                  any failure or delay to assert any of CONTRACTOR’s rights under the CONTRACT.
 
6.                   This Guarantee shall remain in effect whether or not GUARANTOR remains the parent company of, or controls directly or indirectly COMPANY unless CONTRACTOR shall, in its absolute discretion, consent to release GUARANTOR from its obligations hereunder. GUARANTOR acknowledges that CONTRACTOR’s consent will in any event only be given if GUARANTOR procures a guarantee in favor of CONTRACTOR in the same, or substantially the same, terms as this Guarantee from other acceptable guarantor(s).
 
7.                   This Guarantee shall come into effect immediately prior to the date of the CONTRACT and shall, subject to clause 6 above, remain in effect until all liabilities of COMPANY arising under or in connection with the CONTRACT have ceased or five (5) years from the date that the drilling unit is off hire pursuant to the CONTRACT or until CONTRACTOR notifies GUARANTOR in writing that its obligations hereunder have ceased (whichever shall first occur).
 
8.                   This Guarantee shall be governed by and construed in accordance with the laws of England and Wales and in the event of any dispute relating thereto GUARANTOR hereby submits to the exclusive jurisdiction of the Courts of England and Wales.
 
9.                   Notwithstanding anything to the contrary in this Guarantee, in no event shall GUARANTOR’s liability exceed that of COMPANY under the CONTRACT.
 
IN WITNESS WHEREOF, GUARANTOR has caused this Guarantee to be executed as its deed the day and year first before written:                           2008.

Noble Energy Inc
 
Name:	 	 	
 	 	 	
Printed Name:	 	 	
 	 	 	
Title:	 	 	

 
PARENT OR ULTIMATE HOLDING COMPANY GUARANTEE
 
THIS GUARANTEE is made the             day of                                     2008, by Kosmos Energy Holdings, a company with offices at 8401 N. Central Expressway, Suite 280, Dallas, Texas 75225 (hereinafter called “GUARANTOR”) in favour of  Alpha Offshore Drilling Services Company,  a company registered in the Cayman Islands under registration number 1140 whose registered office is situated at c/o M&C Corporate Services Limited, P.O. Box 309GT, Ugland House, South Church Street, George Town, Grand Cayman, Cayman Islands (hereinafter called “CONTRACTOR” which term includes its successors and assigns). GUARANTOR is the parent or ultimate holding company of  Kosmos Energy Ghana HC  (hereinafter called “COMPANY”).
 
WHEREAS:
 
1.                                      This Guarantee is supplemental to that certain Offshore Drilling Contract dated the                            day of June 2008, and made among COMPANY and  Noble Energy EG Ltd.  of the one part and CONTRACTOR of the other part (hereinafter called the “CONTRACT”) whereby CONTRACTOR agrees and undertakes to provide the semisubmersible drilling unit ATWOOD HUNTER and associated services at the request of COMPANY for the relevant work segments of the CONTRACT (hereinafter called the “SERVICES”).
 
2.                                      GUARANTOR is the parent or ultimate holding company of COMPANY.
 
3.                                      GUARANTOR is aware of the subject matter and terms and conditions of the CONTRACT and COMPANY’s obligations thereunder.
 
4.                                      GUARANTOR has agreed to guarantee the performance of COMPANY and/or any of its affiliates or assignees with respect to COMPANY’s obligations under the CONTRACT. Any reference to COMPANY in this document shall also include any and all such affiliates and/or assignees, if applicable.
 
5.                                      GUARANTOR is empowered to enter into this Guarantee and has taken all steps to ensure that when executed, this Guarantee shall be valid and binding in accordance with the terms hereof.
 
NOW THIS DEED WITNESSETH and GUARANTOR hereby agrees as follows:
 
1.                   In this Guarantee “DEFAULT” means a failure on the part of COMPANY to fulfill its obligations in accordance with the CONTRACT or failure on the part of COMPANY to comply with any court order arising out of or in connection with the CONTRACT or the enforcement thereof; and “REMEDY” or “REMEDYING” means to make good, or making good, such DEFAULT.
 
2.                   If COMPANY shall commit any DEFAULT and such DEFAULT shall be continuing, GUARANTOR shall:
 
a)             indemnify CONTRACTOR against all loss, damage, liability, claims, demands, proceedings, costs and expenses arising from such DEFAULT without the necessity for CONTRACTOR to seek any remedy or proceed first against COMPANY or any other person or to enforce any other security for COMPANY’s obligations; and

 
b)            if CONTRACTOR requires by notice in writing, REMEDY or procure the REMEDYING by COMPANY of such DEFAULT.
 
3.              If GUARANTOR is unable or unwilling to REMEDY or to procure the REMEDYING by COMPANY of the DEFAULT but is able and willing at its own cost to engage a third party (to be named by GUARANTOR) to REMEDY the DEFAULT, GUARANTOR shall notify CONTRACTOR in writing accordingly. If CONTRACTOR, consents in writing to the engagement of such third party, which consent shall not be unreasonably withheld, GUARANTOR shall without delay engage the third party PROVIDED that GUARANTOR shall be responsible for all acts and omissions thereof as if GUARANTOR were itself undertaking the REMEDYING of the DEFAULT. Failure by the third party to REMEDY the DEFAULT shall be treated as a DEFAULT and GUARANTOR shall indemnify CONTRACTOR accordingly.
 
4.              GUARANTOR, when giving notice to CONTRACTOR under clause 3 above or as soon as reasonably practicable thereafter, shall provide CONTRACTOR with such information as CONTRACTOR may reasonably require or request in order to reach a speedy decision whether or not to give its consent.
 
5.              The liability of GUARANTOR shall be as primary obligor and not merely as surety and shall not be impaired or discharged by reason of any of the following (whether or not GUARANTOR has notice thereof or has consented thereto):
 
a)             any arrangement made between COMPANY and CONTRACTOR;
 
b)            any alteration in the obligations undertaken by COMPANY;
 
c)             any variation of the SERVICES or other additional or substituted work undertaken by COMPANY and/or CONTRACTOR under the CONTRACT;
 
d)            any indulgence or forbearance shown by CONTRACTOR towards COMPANY or GUARANTOR whether as to performance, time for performance, payment, time for payment or any other matter, or any arrangement entered into or composition accepted by CONTRACTOR modifying (by operation of law or otherwise) the rights and remedies of CONTRACTOR under the CONTRACT or any action or failure to act or delay on the part of CONTRACTOR;
 
e)             any failure or delay by CONTRACTOR in enforcing any other security given for COMPANY’s obligations or any release by CONTRACTOR of such security whether in whole or in part;
 
f)               any action lawfully taken by CONTRACTOR to determine or suspend (or to resume after suspension) the CONTRACT;
 
g)            any change in the relationship between GUARANTOR and COMPANY;
 
h)            any invalidity of the CONTRACT;
 
i)                any disability, incapacity or change in the status or constitution of COMPANY, GUARANTOR or CONTRACTOR;

 
j)                the liquidation or dissolution of COMPANY, the insolvency of COMPANY or any receivership, judicially supervised administration, moratorium, composition of creditors, claims or other analogous event affecting COMPANY or any of its property. If COMPANY loses its separate legal identity, GUARANTOR shall become directly liable for the performance of COMPANY’s obligations under the CONTRACT;
 
k)             any failure or delay to assert any of CONTRACTOR’s rights under the CONTRACT.
 
6.              This Guarantee shall remain in effect whether or not GUARANTOR remains the parent company of, or controls directly or indirectly COMPANY unless CONTRACTOR shallconsent to release GUARANTOR from its obligations hereunder. GUARANTOR acknowledges that CONTRACTOR’s consent will in any event only be given if GUARANTOR procures a guarantee in favor of CONTRACTOR in the same, or substantially the same, terms as this Guarantee from other guarantor(s) reasonably acceptable to CONTRACTOR.
 
7.              This Guarantee shall come into effect immediately prior to the date of the CONTRACT and shall, subject to clause 6 above, remain in effect until all liabilities of COMPANY arising under or in connection with the CONTRACT have ceased or five (5) years from the date that the drilling unit is off hire pursuant to the CONTRACT or until CONTRACTOR notifies GUARANTOR in writing that its obligations hereunder have ceased (whichever shall first occur).
 
8.              This Guarantee shall be governed by and construed in accordance with the laws England and Wales and in the event of any dispute relating thereto GUARANTOR hereby submits to the exclusive jurisdiction of the Courts of London, England.
 
9.              Notwithstanding anything to the contrary in this Guarantee, in no event shall GUARANTOR’s liability exceed that of COMPANY under the CONTRACT.
 
IN WITNESS WHEREOF, GUARANTOR has caused this Guarantee to be executed as its deed the day and year first before written:                              2008.

Kosmos Energy Holdings	 	 	
 	 	 	
Name:	 	 	 	
 	 	 	
Printed Name:	 	 	 	
 	 	 	
Title:	 	 	 	

 
PARENT OR ULTIMATE HOLDING COMPANY GUARANTEE
 
THIS GUARANTEE is made the          day of                         2008, by Atwood Oceanics Pacific Limited, a company with offices at 332A-11C, 11 th  Floor, Plaza Ampang City, Jalan Ampang, 50450 Kuala Lumpur, Malaysia (hereinafter called the “GUARANTOR”) in favour of  Alpha Offshore Drilling Services Company,  a company registered in the Cayman Islands under registration number 1140 whose registered office is situated at c/o M&C Corporate Services Limited, P.O. Box 309GT, Ugland House, South Church Street, George Town, Grand Cayman, Cayman Islands (hereinafter called “CONTRACTOR” which term includes its successors and assigns). GUARANTOR is the parent or ultimate holding company of CONTRACTOR.
 
WHEREAS:
 
1.                                      This Guarantee is supplemental to a contract dated the               day of June 2008, and made between CONTRACTOR of the one part and  Kosmos Energy Ghana HC  and  Noble Energy EG Ltd.  (hereinafter collectively referred to as “COMPANY”) of the other part (hereinafter called the “CONTRACT”) whereby CONTRACTOR agrees and undertakes to provide the semisubmersible drilling unit ATWOOD HUNTER and associated services at the request of COMPANY for the relevant work segments of the CONTRACT (hereinafter called the “SERVICES”).
 
2.                                      GUARANTOR is the parent or ultimate holding company of CONTRACTOR.
 
3.                                      GUARANTOR is aware of the subject matter and terms and conditions of the CONTRACT and CONTRACTOR’s obligations thereunder.
 
4.                                      GUARANTOR has agreed to guarantee the performance of CONTRACTOR and/or any of its affiliates or assignees with respect to CONTRACTOR’s obligations under the CONTRACT. Any reference to CONTRACTOR in this document shall also include any and all such affiliates and/or assignees, if applicable.
 
5.                                      GUARANTOR is empowered to enter into this Guarantee and has taken all steps to ensure that when executed, this Guarantee shall be valid and binding in accordance with the terms hereof.
 
NOW THIS DEED WITNESSETH and GUARANTOR hereby agrees as follows:
 
1.              In this Guarantee “DEFAULT” means failure on the part of CONTRACTOR to execute and complete the SERVICES or any part thereof in accordance with the CONTRACT, or a breach of any of CONTRACTOR’s obligations under the CONTRACT or failure on the part of CONTRACTOR to comply with any court order arising out of or in connection with the CONTRACT or the enforcement thereof; and “REMEDY” or “REMEDYING” means to make good, or making good, such DEFAULT.
 
2.              If CONTRACTOR shall commit any DEFAULT, GUARANTOR shall:
 
a)                                     indemnify COMPANY against all loss, damage, liability, claims, demands, proceedings, costs and expenses arising from such DEFAULT without the necessity for COMPANY to seek any remedy or proceed first against CONTRACTOR or any other person or to enforce any other security for CONTRACTOR’s obligations; and

 
b)                                    if COMPANY requires by notice in writing, REMEDY or procure the REMEDYING by CONTRACTOR of such DEFAULT.
 
3.                                      If GUARANTOR is unable or unwilling to REMEDY or to procure the REMEDYING by CONTRACTOR of the DEFAULT but is able and willing at its own cost to engage a third party (to be named by GUARANTOR) to REMEDY the DEFAULT, GUARANTOR shall notify COMPANY in writing accordingly. If COMPANY, in its complete discretion, consents in writing to the engagement of such third party, GUARANTOR shall without delay engage the third party PROVIDED that GUARANTOR shall be responsible for all acts and omissions thereof as if GUARANTOR were itself undertaking the REMEDYING of the DEFAULT. Failure by the third party to REMEDY the DEFAULT shall be treated as a DEFAULT and GUARANTOR shall indemnify COMPANY accordingly.
 
4.                                      GUARANTOR, when giving notice to COMPANY under clause 3 above or as soon as reasonably practicable thereafter, shall provide COMPANY with such information as COMPANY may reasonably require or request in order to reach a speedy decision whether or not to give its consent.
 
5.                                      The liability of GUARANTOR shall be as primary obligor and not merely as surety and shall not be impaired or discharged by reason of any of the following (whether or not GUARANTOR has notice thereof or has consented thereto):
 
a)             any arrangement made between COMPANY and CONTRACTOR;
 
b)            any alteration in the obligations undertaken by COMPANY;
 
c)             any variation of the SERVICES or other additional or substituted work undertaken by COMPANY and/or CONTRACTOR under the CONTRACT;
 
d)            any indulgence or forbearance shown by COMPANY towards CONTRACTOR or GUARANTOR whether as to performance, time for performance, payment, time for payment or any other matter, or any arrangement entered into or composition accepted by CONTRACTOR modifying (by operation of law or otherwise) the rights and remedies of CONTRACTOR under the CONTRACT or any action or failure to act or delay on the part of CONTRACTOR;
 
e)             any failure or delay by COMPANY in enforcing any other security given for CONTRACTOR’s obligations or any release by COMPANY of such security whether in whole or in part;
 
f)               any action lawfully taken by CONTRACTOR to determine or suspend (or to resume after suspension) the CONTRACT;
 
g)            any change in the relationship between GUARANTOR and COMPANY;
 
h)            any invalidity of the CONTRACT;
 
i)                any disability, incapacity or change in the status or constitution of COMPANY, GUARANTOR or CONTRACTOR;

 
j)                the liquidation or dissolution of CONTRACTOR, the insolvency of CONTRACTOR or any receivership, judicially supervised administration, moratorium, composition of creditors, claims or other analogous event affecting CONTRACTOR or any of its property. If CONTRACTOR loses its separate legal identity, GUARANTOR shall become directly liable for the performance of CONTRACTOR’s obligations under the CONTRACT;
 
k)             any failure or delay to assert any of COMPANY’s rights under the CONTRACT.
 
6.                                      This Guarantee shall remain in effect whether or not GUARANTOR remains the parent company of, or controls directly or indirectly CONTRACTOR unless COMPANY shall, in its absolute discretion, consent to release GUARANTOR from its obligations hereunder. GUARANTOR acknowledges that COMPANY’s consent will in any event only be given if GUARANTOR procures a guarantee in favor of COMPANY in the same, or substantially the same, terms as this Guarantee from other acceptable guarantor(s).
 
7.                                      This Guarantee shall come into effect immediately prior to the date of the CONTRACT and shall, subject to clause 6 above, remain in effect until all liabilities of CONTRACTOR arising under or in connection with the CONTRACT have ceased or five (5) years from the date that the drilling unit is off hire pursuant to the CONTRACT or until COMPANY notifies GUARANTOR in writing that its obligations hereunder have ceased (whichever shall first occur).
 
8.                                      This Guarantee shall be governed by and construed in accordance with the laws of England and Wales and in the event of any dispute relating thereto GUARANTOR hereby submits to the exclusive jurisdiction of the Courts of England and Wales.
 
9.                                      Notwithstanding anything to the contrary in this Guarantee, in no event shall GUARANTOR’s liability exceed that of CONTRACTOR under the CONTRACT.
 
IN WITNESS WHEREOF, GUARANTOR has caused this Guarantee to be executed as its deed the day and year first before written:                         2008.

Atwood Oceanics Pacific Limited	 	 	
 	 	 	
Name:	 	 	 	
 	 	 	
Printed Name:	 	 	 	
 	 	 	
Title:	 	 	 	

 
AMENDMENT NO. 1 TO DRILLING CONTRACT
(ATWOOD HUNTER)
 
This Amendment No. 1, dated as of March 2, 2009 (“Amendment Effective Date”), to the Drilling Contract (the “Amendment”) is made by and among  Kosmos Energy Ghana HC  (“Kosmos”), a company with offices at Suite 409, 4 th  Floor Century Yard, Cricket Square, PO Box 32322, George Town, Grand Cayman KY1 1209, Cayman Islands,  Noble Energy EG Ltd.  (“Noble”), a company with offices at 100 Glenborough, Suite 100, Houston, Texas 77067 and  Swiftdrill Offshore Drilling Services Co.  (“Swiftdrill” or “Contractor”), a Cayman Islands company with its registered office located at M&C Corporate Services Ltd., P.O. Box 309, Ugland House, South Church Street, George Town, Grand Cayman, Cayman Islands. These parties may be referred to individually as a “Party” or collectively as “Parties”.
 
Whereas, Kosmos, Noble and Alpha Offshore Drilling Services Company (“Alpha”) entered into that certain Offshore Drilling Contract dated June 23, 2008 relating to operations in West Africa (the “Drilling Contract”);
 
Whereas, by Assignment Agreement dated 25 August 2008, Alpha assigned that portion of the Drilling Contract that relates to Noble’s operations offshore Equatorial Guinea to Swiftdrill;
 
Whereas, by Assignment Agreement dated 22 December 2008, Alpha assigned that portion of the Drilling Contract that relates to Kosmos’ operations offshore Ghana to Swiftdrill;
 
Whereas, Noble’s affiliate, Noble Energy Mediterranean Ltd. (“Noble Med”), entered into that certain Drilling Contract dated June 23, 2008 with Alpha (the E. Med Contract”), and such E. Med Contract has been amended as of February 12, 2009 to cover the drilling and possible testing of a total of three wells in Israel (the “E. Med Contract Amendment”) (the E. Med Contract and E. Med Contract Amendment together called the “Amended E. Med Contract”);
 
Whereas, Alpha, Kosmos and Noble entered into that certain Rig Sharing Agreement (Atwood Hunter) dated June 24, 2008 (the “Rig Sharing Agreement”) relating to the allocation of days between Kosmos and Noble during the term of the Drilling Contract;
 
Whereas, due to the E. Med Contract Amendment, the Parties recognize that the Drilling Contract and the Rig Sharing Agreement require amendment; and
 
Whereas, the Rig Sharing Agreement will be amended by separate agreement.
 
Now, Therefore, the Parties, for and in consideration of the mutual obligations, undertakings, premises and covenants herein contained do hereby agree as follows:

 
1.             Defined Terms
Any term defined in the Drilling Contract shall have the same meaning when used in this Amendment unless otherwise specified herein.
 
2.             Amendment to Drilling Contract
Effective as of the Amendment Effective Date, the Drilling Contract shall be amended as follows:
 
(a) Section 3.2(A) of the Drilling Contract is hereby deleted in its entirety and replaced with the following provision:
 
(A)     “The initial Operating Term of this Contract is 1,146 days and shall commence upon the Mobilization Completion Date. The initial Operating Term is anticipated to be as follows:
 
(1)                        Kosmos has two hundred seventy (270) days of operations offshore Ghana; then
 
(2)                        Noble has one hundred sixty-eight (168) days of operations offshore Equatorial Guinea; then
 
(3)                        Kosmos has two hundred seventy (270) days of operations offshore Ghana; then
 
(4)                        Noble has one hundred sixty eight (168) days of operations offshore Equatorial Guinea; then
 
(5)                        Kosmos has two hundred seventy (270) days of operations offshore Ghana.
 
The Parties acknowledge that the Amended E. Med Contract allows for the drilling of three wells (with the option to test such wells) in the Eastern Mediterranean with a total allocated period of 300 days (subject to Noble Med’s right to use the Drilling Unit for additional days as specified in the Rig Sharing Agreement, as amended). In any event, to the extent that the actual total number of days used by Noble Med (including mobilization and operating) is less or greater than 300 days, the days allocated to Noble under the Drilling Contract, and thus the initial Operating Term, shall be adjusted accordingly, with any increase or decrease in the number of days for Noble being applied to the drilling segment referenced in Section 3.2(A)(4).
 
The Parties hereto further acknowledge that the Mobilization under this Contract from Israel to the Mauritania Line is estimated to take 35 days and (and the cost is allocated two-thirds to Noble and one-
 
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third to Kosmos), and the Mobilization from the Mauritania Line to one mile from Kosmos’ first well in Ghana is estimated to take 20 days (and the cost is allocated one-half each to Noble and Kosmos). To the extent that the actual mobilization days are less or greater than the estimated days, the days shall be adjusted and allocated to Noble or Kosmos in the same proportion as cost has been allocated under the Drilling Contract (2/3 Noble and 1/3 Kosmos from Israel to Mauritania Line and 50/50 from the Mauritania Line to Kosmos’ first well in Ghana), and the initial Operating Term shall be adjusted accordingly.
 
Notwithstanding anything to the contrary in the Contract and consistent with Kosmos’ plan to commence oil production in Ghana during the first half of 2010, should Kosmos and its Joint Interest Owners fail to achieve commercial oil production by September 30, 2010 and, in Contractor’s reasonable opinion, Kosmos’ financial capability is insufficient to complete its payment obligations under the Contract, Kosmos and Atwood shall meet in good faith to review relevant payment security issues to resolve the matter, including posting of a letter of credit. After such review, if Contractor, in its reasonable opinion, is not satisfied with remedies discussed, Contractor may reduce the term of the Kosmos’ segments of the Contract accordingly, not to exceed a nine (9) month reduction in term. In the event of such reduction and the option set forth in Section 3.2(C) has been exercised by Noble, Noble shall be obligated to accept the Drilling Unit on an accelerated basis immediately following the conclusion of the relevant Kosmos’ drilling program segment(s).”
 
3.             Continued Effect
Except as specifically amended hereby, the terms and provisions of the Drilling Contract shall remain in full force and effect.
 
SIGNATURES ON FOLLOWING PAGE
 
3

 
IN WITNESS WHEREOF, the authorized representatives of the Parties have executed this Amendment on the day and year first written above.

KOSMOS ENERGY GHANA HC	 	

By:	/s/ Marvin Garrett	 	
 	Marvin Garrett	 	
 	Vice President	 	

NOBLE ENERGY EG, LTD.	 	

By:	/s/ David L. Stover	 	
 	David L. Stover	 	
 	Executive Vice President and	 	
 	Chief Operating Officer	 	

SWIFTDRILL OFFSHORE DRILLING SERVICES CO.	 	

By:	/s/ Anthony A. Dyne	 	
Name:	Anthony A. Dyne	 	
Title:	Director	 	
 
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Exhibit 10.26

 
Tullow Ghana Limited
Building 11
Chiswick Park
566 Chiswick High Road
London, UK
W4 5YS
Attention: Mr. Ian Springett
 
Anadarko WCTP Company
Anadarko Tower
1201 Lake Robbins Drive
The Woodlands, Texas 77380
Attention: Mr. Charles E. Provost, Jr.
 
4 May 2010
 
Agreement for the Construction, Installation, Lease, Operations and Maintenance of a Floating, Production, Storage and Off-Loading (FPSO) Facility for the Phase 1 Development for the Jubilee Field Unit between Jubilee Ghana MV 21 B.V., and Tullow Ghana Limited (the “Lease Agreement”)
 
We refer to: (1) the above-referenced Lease Agreement which Tullow Ghana Limited (“Tullow”) is entering into contemporaneously with this letter on behalf of the parties to the Unit Agreement (the “UUOA Parties”); and (2) the Advance Payments Agreement dated the same date as this letter between Jubilee Ghana MV 21 B.V., Modec, Inc., Tullow and Tullow Group Services Limited (the “AP Agreement”). Words and expressions used in this letter have the same meaning as set out in the Lease Agreement unless otherwise defined herein.
 
Each of Tullow and Anadarko (the “Block Partners”) have agreed to enter into this side letter and provide the undertakings set out herein in consideration of Kosmos Energy Ghana HC (‘Kosmos”) agreeing irrevocably to vote as a UUOA Party to approve Tullow, on behalf of the UUOA Parties, entering into the Lease Agreement and the AP Agreement in the form which has been approved by Kosmos on the date of this letter (but subject to there being no material change in circumstances, or any material event or any material information coming to the knowledge of Kosmos, after the date of this letter but prior to the vote under the UUOA, which would affect its interests in approving the Lease Agreement or the AP Agreement).
 
The Block Partners agree that, subject to the terms of this letter, in the event that Tullow is required by the terms of Clause 4.2 of the AP Agreement to purchase the FPSO Facility, then Kosmos may require the Block Partners to use their reasonable endeavours to enter into an FPSO lease agreement with Tullow on behalf of the UUOA Parties (the “Applicable Lease Agreement”) which is substantially on the terms of the Lease Agreement, provided that the Applicable Lease Agreement Lease Rates shall be no less than the Lease Rates applicable in the Lease Agreement at the relevant time, subject to such adjustments to the Lease Rates as the Block Partners may agree are necessary to ensure that the Block Partners receive additional compensation to ensure that such rates are properly and fully reflective of the risk profile assumed by the Block Partners under the Applicable Lease Agreement, are properly and fully reflective of the market conditions at that time and reflect the cost of any necessary debt or equity funding required by the Block Partners in relation thereto or any other commitments or liabilities which must be assumed by the Block Partners in entering into the Applicable Lease Agreement. Without limiting the foregoing, such adjustments shall also properly reflect the capital at risk of the Block Partners. Kosmos and the Block Partners agree to hold discussions
 
Kosmos Energy Ghana HC
c/o 8176 Park Lane, Suite 500 Dallas, Texas 75231 Phone 214-445-9600 Fax 214 363 9024

 
in good faith with a view to reaching agreement on the Lease Rates and such other reasonable amendments to the Applicable Lease Agreement as may be required in connection with the submission of the Applicable Lease Agreement to the UUOA Parties for approval.
 
The entry into the Applicable Lease Agreement between the Block Partners and the UUOA Parties shall be subject to the board approval of each Block Partner and Kosmos.
 
This letter will automatically terminate and be of no further force or effect upon a change of control of Kosmos. For this purpose, a “change of control” means, prior to an IPO, the shareholders in Kosmos on the date of this letter (and their respective affiliates) cease, directly or indirectly, to beneficially own at least 50.1% of the ordinary share capital carrying a right to vote in general meetings of Kosmos or, after an IPO, the shareholders in Kosmos on the date of this letter (and their respective affiliates) cease, directly or indirectly, to beneficially own at least 35% of the ordinary share capital carrying a right to vote in general meetings of Kosmos or, at any time, any person (together with persons with whom they act in concert) directly or indirectly, beneficially owns more of the ordinary share capital carrying a right to vote in general meetings of Kosmos than the shareholders in Kosmos on the date of this letter (and their respective affiliates).
 
This letter agreement shall be governed by and construed in accordance with English law. The parties irrevocably submit to the jurisdiction of the English courts and irrevocably waive any right to claim that such forum is inconvenient.
 
This letter may be executed in counterparts and each counterpart shall be deemed an original for all purposes; provided that no party shall be bound to this letter until all parties have executed a counterpart.
 
Please confirm your agreement with the foregoing by signing and returning a copy of this letter as set out below.
 
Yours faithfully,
 
For and on behalf of Kosmos Energy Ghana HC
 
/s/ Kosmos ENERGY GHANA HC	 	

Acknowledged and agreed by Tullow Ghana Limited
 
Signed:	/s/ A. Graham Martin	 	
Name:	A. Graham Martin	 	
Date:	4 May 2010	 	

Acknowledged and agreed by Anadarko WCTP Company
 
 	Signed:	/s/ ANDARKO WCTP COMPANY	 	 	
 	 	 	 	 	 	
 	Date:	3 May 2010	 	 	 	
 
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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

        We consent to the reference to our firm under the caption "Experts" and to the use of our report dated March 2, 2011, related to the consolidated financial statements and schedules of Kosmos Energy Holdings in Amendment No. 2 to the Registration Statement (Form S-1) and related Prospectus of Kosmos Energy Ltd. for the registration of its common stock.
 	 	 	
 	 	/s/ Ernst & Young LLP	
Dallas, Texas
March 21, 2011

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Exhibit 23.1

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Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

        We hereby consent to the reference of our firm and to the use of our reports of Kosmos Energy Ltd. as of December 31, 2009, dated February 3, 2010, and as of December 31, 2010, dated March 21, 2011, in this Form S-1 Registration Statement and the related Prospectus to be filed on or about March 22, 2011. We also consent to the reference to us under the heading "Experts" in such Registration Statement and the Prospectus to which the Registration Statement is related.
 	 	 	 	 	
 	 	NETHERLAND, SEWELL & ASSOCIATES, INC.	

 	
By:	
 	
/s/ G. LANCE BINDER, P.E.

G. Lance Binder, P.E.
Executive Vice President	
Dallas, Texas
March 22, 2011

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Exhibit 23.2

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EXHIBIT 99.1

WORLDWIDE PETROLEUM CONSULTANTS
ENGINEERING  •  GEOLOGY  •  GEOPHYSICS  •  PETROPHYSICS	 	CHAIRMAN & CEO
C.H.(SCOTT) REES III

PRESIDENT & COO
DANNY D. SIMMONS

EXECUTIVE VP
G. LANCE BINDER	 	EXECUTIVE COMMITTEE
P. SCOTT FROST - DALLAS
J. CARTER HENSON, JR. - HOUSTON
DAN PAUL SMITH - DALLAS
JOSEPH J. SPELLMAN - DALLAS
THOMAS J. TELLA II - DALLAS	

February 3, 2010

Mr. Tommy Fulford
Kosmos Energy, LLC
8176 Park Lane, Suite 500
Dallas, Texas 75231

Dear Mr. Fulford:

        In accordance with your request, we have estimated the gross (100 percent) original oil-in-pace (OOIP) and proved, probable, and possible undeveloped reserves and future revenue, as of December 31, 2009, to the Kosmos Energy, LLC (Kosmos) interest in the LM2, UM3, and UM2 Reservoirs located in the Jubilee Field Phase 1 Development Unit Area in the West Cape Three Points and Deepwater Tano license areas, offshore Ghana. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Kosmos. The estimates in this report have been prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future corporate income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Industries—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Kosmos' use in filing with the SEC.

        The Jubilee Field Phase 1 development is ongoing, with first production scheduled to begin in late 2010. We estimate the gross (100 percent) OOIP and oil reserves and the net oil reserves and future net revenue to the Kosmos interest in the Jubilee Field Phase 1 Development Unit Area, as of December 31, 2009, to be:

	 	Gross (100 Percent)	 	 
	 	Future Net
Revenue(1)
(MM$)	 	
Category	 	OOIP
(MMBBL)	 	Oil Reserves
(MMBBL)	 	Net Oil Reserves(1)
(MMBBL)	 	Total	 	Discounted
at 10%	 	
Proved Undeveloped	 	 	938	 	 	234	 	 	55	 	 	1,127	 	 	699	 	
Probable Undeveloped	 	 	142	 	 	93	 	 	22	 	 	776	 	 	440	 	
Possible Undeveloped	 	 	147	 	 	117	 	 	27	 	 	898	 	 	368	 	

(1)
Kosmos' net interest is based on currently agreed unit interest factors of 50 percent for West Cape Three Points and 50 percent for Deepwater Tano; these factors are subject to change as additional data are obtained,

        The oil reserves shown include crude oil only. Oil volumes are expressed in millions of barrels (MMBBL); a barrel is equivalent to 42 United States gallons. Net oil reserves are the share of reserves attributable to the Kosmos interest. These properties are not modeled in this report to have a commercial market for gas; produced gas will be consumed in operations or reinjected. Revenue estimates are expressed in millions of United States dollars (MM$).

4500 THANKSGIVING TOWER • 1601 ELM STREET • DALLAS, TEXAS 75201-4754 • PH: 214-969-5401 • FAX: 214-969-5411	 	NSAI@NSAI-PETRO.COM	
1221 LAMAR STREET, SUITE 1200 • HOUSTON, TEXAS 77010-3072 • PH: 713-654-4950 • FAX: 713-654-4951	 	NETHERLANDSEWELL.COM	

        The estimates shown in this report are for proved, probable, and possible undeveloped reserves. These reserves are classified as undeveloped even though many of the wells have already been drilled but are awaiting installation of the complete development system. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

        Future net revenue to the Kosmos interest is after deductions for royalties, production sharing oil revenue, applicable taxes, future capital costs, operating expenses, and abandonment costs and after consideration of estimated Ghanaian taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

        For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities, We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Our estimates of future revenue do not include any salvage value for the lease and well equipment but do include Kosmos' estimates of the costs to abandon the wells, pipelines, and production facilities. Abandonment costs are included as capital costs.

        Oil prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2009. The average Brent crude price of US$59.60 per barrel is adjusted for crude handling, transportation fees, quality, and a regional price differential. The oil price is held constant throughout the lives of the properties.

        Lease and well operating costs used in this report are based on operating expense estimates of Kosmos, These costs are intended to include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters, general and administrative overhead expenses of Kosmos are not included. Lease and well operating costs are held constant throughout the lives of the properties. Capital costs are included as required for new development wells and production equipment. The future capital costs are held constant to the date of expenditure.

        The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. Estimates of reserves may increase or decrease as a result of future operations, market conditions, or changes in regulations.

        For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, historical cost information, and property ownership interests. The reserves in this report have been estimated using a combination of deterministic and probabilistic methods; these estimates have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. We used standard engineering and geoscience methods, or a combination of methods, such as volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to establish reserves quantities and reserves categorization that conform to SEC definitions and guidelines. These reserves are for wells that lack history upon which performance-related estimates of reserves can be based. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. In evaluating the information at our

disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be political, socioeconomic, legal, or accounting, rather than engineering and geoscience. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

        The contractual rights to the properties have not been examined by Netherland, Sewell & Associates, Inc. (NSAI), nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Kosmos, public data sources, and the nonconfidential files of NSAI and were accepted as accurate. Supporting geoscience, field performance, and work data are on file in our office. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties and are not employed on a contingent basis.
 	 	 	 	 	 	 	
 	 	 	 	Sincerely,	

 	

 	

 	 	 	 	NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-002699	

 	

By:	
 	
/s/ C.H. (SCOTT) REES III

C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer	

 	

 	

By:	 	/s/ JOSEPH J. SPELLMAN

Joseph J. Spellman, P.E. 73709
Senior Vice President	 	By:	 	/s/ DANIEL T. WALKER

Daniel T. Walker, P.G. 1272
Senior Vice President	

 	

 	

Date Signed: February 3, 2010	 	Date Signed: February 3, 2010	
JJS:AMB

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc, (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintaind by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.
 
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.
 
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
 
(i)   Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii)  Same environment of deposition;
(iii) Similar geological structure; and
(iv) Same drive mechanism.
 
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
 
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
 
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
 
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
 
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
 
(i)            Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)         Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
Supplemental definitions from the 2007 Petroleum Resources Management System:
 
Developed Producing Reserves — Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.
 
Developed Non-Producing Reserves — Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
 
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
 
(i)            Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii)         Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
 
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(iii)      Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv)     Provide improved recovery systems.
 
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
 
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
 
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
 
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
 
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
 
(i)            Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.
(ii)         Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
(iii)      Dry hole contributions and bottom hole contributions.
(iv)     Costs of drilling and equipping exploratory wells.
(v)        Costs of drilling exploratory-type stratigraphic test wells.
 
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
 
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
 
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
 
(16) Oil and gas producing activities.
 
(i)   Oil and gas producing activities include:
 
(A)     The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;
(B)       The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C)       The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
 
(1)      Lifting the oil and gas to the surface; and
(2)      Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
 
2

 
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
 
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
 
a.              The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b.             In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
 
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
 
(ii)  Oil and gas producing activities do not include:
 
(A)     Transporting, refining, or marketing oil and gas;
(B)       Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C)       Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D)      Production of geothermal steam.
 
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
 
(i)            When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)         Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii)      Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv)     The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v)        Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi)     Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
 
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
 
(i)            When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
 
3

 
(ii)         Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii)      Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv)     See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
 
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
 
(20) Production costs.
 
(i)            Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
 
(A)     Costs of labor to operate the wells and related equipment and facilities.
(B)       Repairs and maintenance.
(C)       Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D)      Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E)        Severance taxes.
 
(ii)         Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
 
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
 
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
(i)   The area of the reservoir considered as proved includes:
 
(A)     The area identified by drilling and limited by fluid contacts, if any, and
(B)       Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
 
(ii)         In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii)      Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv)     Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
 
(A)     Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous
 
4

 
reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B)       The project has been approved for development by all necessary parties and entities, including governmental entities.
 
(v)        Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
(23) Proved properties. Properties with proved reserves.
 
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
 
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
 
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
 
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
 
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
 
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:
 
a.        Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.        Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
 
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
 
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
 
a.        Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b.        Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c.         Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.
d.        Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
 
5

 
e.         Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f.            Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.
 
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
 
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
 
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
 
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
 
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
 
(i)            Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)         Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
 
From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):
 
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
 
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
 
·       The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
·       The company’s historical record at completing development of comparable long-term projects;
·       The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
·       The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
·       The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
 
(iii)      Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
 
(32) Unproved properties. Properties with no proved reserves.
 
6

 

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EXHIBIT 99.2

WORLDWIDE PETROLEUM CONSULTANTS
ENGINEERING  •  GEOLOGY  •  GEOPHYSICS  •  PETROPHYSICS	 	CHAIRMAN & CEO
C.H.(SCOTT) REES III

PRESIDENT & COO
DANNY D. SIMMONS

EXECUTIVE VP
G. LANCE BINDER	 	EXECUTIVE COMMITTEE
P. SCOTT FROST - DALLAS
J. CARTER HENSON, JR. - HOUSTON
DAN PAUL SMITH - DALLAS
JOSEPH J. SPELLMAN - DALLAS
THOMAS J. TELLA II - DALLAS	

March 21, 2011

Mr. Tommy Fulford
Kosmos Energy
8176 Park Lane, Suite 500
Dallas, Texas 75231

Dear Mr. Fulford:

        In accordance with your request, we have estimated the gross (100 percent) original oil-in-place (OOIP); estimated ultimate recovery (EUR); and proved, probable, and possible reserves and future revenue, as of December 31, 2010, to the Kosmos Energy (Kosmos) interest in certain oil and gas properties located in the LM2, UM3, and UM2 Reservoirs located in the Jubilee Field Phase 1 Development Unit Area in the West Cape Three Points and Deepwater Tano license areas, offshore Ghana. We completed our evaluation on February 3, 2011. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Kosmos. The estimates in this report have been prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future corporate income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Kosmos' use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

        We estimate the gross (100 percent) OOIP and oil EUR and the net oil and gas reserves and future net revenue to the Kosmos interest in the Jubilee Field Phase 1 Development Unit Area, as of December 31, 2010, to be:

	 	Gross (100 Percent)	 	Net Reserves(1)	 	Future Net Revenue(1) (MM$)	 	
Category	 	OOIP
(MMBBL)	 	Oil EUR
(MMBBL)	 	Oil
(MMBBL)	 	Gas(2)
(BCF)	 	Total	 	Present Worth
at 10%	 	
Proved Developed Producing	 	 	 	(3)	 	44	 	 	10	 	 	7	 	 	338	 	 	309	 	
Proved Developed Non-Producing	 	 	 	(3)	 	113	 	 	27	 	 	11	 	 	972	 	 	747	 	
Proved Undeveloped	 	 	 	(3)	 	77	 	 	19	 	 	4	 	 	730	 	 	475	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total Proved	 	 	942	 	 	234	 	 	56	 	 	23	 	 	2,041	 	 	1,530	 	
Probable	 	 	
141	 	 	
94	 	 	
22	 	 	
2	 	 	
910	 	 	
563	 	
Possible	 	 	
149	 	 	
115	 	 	
26	 	 	
4	 	 	
1,045	 	 	
470	 	

Totals may not add because of rounding.(1)
Kosmos' unitized net interest is based on a currently agreed upon 50/50 split between the West Cape Three Points and Deepwater Tano license areas; this is subject to change as additional data are obtained.

(2)
Net gas reserves are based on gas volumes consumed in operations as fuel; for the purposes of this report, all other produced gas is expected to be reinjected. Contingent resources for gas volumes to be exported pending completion of gas export infrastructure and commercial agreements are summarized under separate cover.

(3)
OOIP was estimated for total proved only.

4500 THANKSGIVING TOWER • 1601 ELM STREET • DALLAS, TEXAS 75201-4754 • PH: 214-969-5401 • FAX: 214-969-5411	 	NSAI@NSAI-PETRO.COM	
1221 LAMAR STREET, SUITE 1200 • HOUSTON, TEXAS 77010-3072 • PH: 713-654-4950 • FAX: 713-654-4951	 	NETHERLANDSEWELL.COM	

        The oil reserves shown include crude oil only. Oil volumes are expressed in millions of barrels (MMBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in billions of cubic feet (BCF) at standard temperature and pressure bases. Net reserves are the share of reserves attributable to the Kosmos interest. Monetary values shown in this report are expressed in United States dollars ($) or millions of United States dollars (MM$).

        The estimates shown in this report are for proved, probable, and possible reserves. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

        Future gross revenue to the Kosmos interest is after deductions for royalties and additional oil entitlement. Future net revenue is after deductions for production sharing oil revenue, future capital costs, operating expenses, abandonment costs, and estimated Ghanaian taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

        For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Our estimates of future net revenue do not include any salvage value for the lease and well equipment but do include Kosmos' estimates of the costs to abandon the wells, pipelines, and production facilities.

        The oil price used in this report is based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2010. The average Brent crude price of $79.35 per barrel is adjusted for crude handling, quality, transportation fees, and a regional price differential. Based largely on the high quality of the crude, these adjustments are estimated to add $0.35 per barrel. The adjusted oil price of $79.70 per barrel is held constant throughout the lives of the properties. There is no gas price used in this report because gas reserves are consumed in operations as fuel.

        Operating costs used in this report are based on operating expense estimates of Kosmos. These costs are intended to include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Kosmos are not included. Operating costs are held constant throughout the lives of the properties. Capital costs are included as required for new development wells and production equipment. The future capital costs are held constant to the date of expenditure.

        The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of Kosmos to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

        For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using a combination of deterministic and probabilistic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and guidelines. A substantial portion of these reserves are for non-producing zones, undeveloped locations, and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

        The data used in our estimates were obtained from Kosmos, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting geoscience, performance, and work data are on file in our office. The contractual rights to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.
 	 	 	 	 	 	 	
 	 	 	 	Sincerely,	

 	

 	

 	 	 	 	NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-002699	

 	

By:	
 	
/s/ C.H. (SCOTT) REES III

C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer	

By:	
 	
/s/ JOSEPH J. SPELLMAN

	
 	
By:	
 	
/s/ DANIEL T. WALKER  

	
 	 	Joseph J. Spellman, P.E. 73709	 	 	 	Daniel T. Walker, P.G. 1272	
 	 	Senior Vice President	 	 	 	Senior Vice President	

 	

 	

Date Signed: March 21, 2011	 	Date Signed: March 21, 2011	
JJS:AMB

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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.
 
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.
 
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
 
(i)     Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii)    Same environment of deposition;
(iii)   Similar geological structure; and
(iv)   Same drive mechanism.
 
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
 
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
 
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
 
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
 
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
 
(i)   Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)  Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
Supplemental definitions from the 2007 Petroleum Resources Management System:
 
Developed Producing Reserves — Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.
 
Developed Non-Producing Reserves — Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
 
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
 
(i)   Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii)  Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
 
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(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv) Provide improved recovery systems.
 
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
 
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
 
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
 
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
 
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
 
(i)   Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.
(ii)  Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
(iii) Dry hole contributions and bottom hole contributions.
(iv) Costs of drilling and equipping exploratory wells.
(v)  Costs of drilling exploratory-type stratigraphic test wells.
 
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
 
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
 
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
 
(16) Oil and gas producing activities.
 
(i) Oil and gas producing activities include:
 
(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;
(B)  The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C)  The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
 
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(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
 
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
 
a.    The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b.    In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
 
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
 
(ii)  Oil and gas producing activities do not include:
 
(A) Transporting, refining, or marketing oil and gas;
(B)  Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C)  Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D) Production of geothermal steam.
 
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
 
(i)   When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)  Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v)  Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
 
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
 
(i)   When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
 
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(ii)  Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
 
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
 
(20) Production costs.
 
(i)   Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
 
(A) Costs of labor to operate the wells and related equipment and facilities.
(B)  Repairs and maintenance.
(C)  Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E)  Severance taxes.
 
(ii)  Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
 
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
 
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
(i)   The area of the reservoir considered as proved includes:
 
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B)  Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
 
(ii)  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
 
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous
 
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reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
 
(B)  The project has been approved for development by all necessary parties and entities, including governmental entities.
 
(v)  Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
(23) Proved properties. Properties with proved reserves.
 
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
 
(25) Reliable technology.Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
 
(26) Reserves.Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
 
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
 
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
 
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:
 
a.  Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.  Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
 
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
 
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
 
a.  Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b.  Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c.  Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.
d.  Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
 
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e.  Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f.   Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.
 
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
 
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
 
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
 
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
 
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
 
(i)   Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)  Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
 
From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):
 
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
 
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
 
·   The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
·   The company’s historical record at completing development of comparable long-term projects;
·   The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
·   The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
·   The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
 
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
 
(32) Unproved properties. Properties with no proved reserves.
 
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EXHIBIT 99.2