Table of Contents

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

Registration No. 333-171700

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

Amendment No. 5
to
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

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

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

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

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

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

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

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

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

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

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

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

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

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

Table of Contents

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

SUBJECT TO COMPLETION, DATED APRIL 25, 2011

30,000,000 Shares

Kosmos Energy Ltd.

Common Shares

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

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

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

 	
 
	 	Price to Public
	 	Underwriting
Discounts and
Commissions
	 	Proceeds
to Us

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

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

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

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

Table of Contents

TABLE OF CONTENTS

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

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

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

i

Table of Contents
PROSPECTUS SUMMARY

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

Overview

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

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

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

1

Table of Contents

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

(1)
Kosmos is the operator under these licenses.

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

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

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

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

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

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

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

2

Table of Contents

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

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

Our History

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

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

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

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

3

Table of Contents

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

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

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

Our Competitive Strengths

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

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

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

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

4

Table of Contents

Well-defined production and growth plan

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

Significant upside potential from exploratory assets

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

Oil-weighted asset portfolio in key strategic regions

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

New ventures group focused on expanding our asset portfolio

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

5

Table of Contents

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

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

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

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

Strong financial position

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

Our Strategy

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

6

Table of Contents

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

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

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

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

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

Focus on rapidly developing our discoveries to initial production

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

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

7

Table of Contents

Identify, access and explore emerging exploratory regions and hydrocarbon plays

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

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

Acquire additional exploration assets

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

Jubilee Phase 1 Reserve and Development Information

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

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

8

Table of Contents

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

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

Discovery Information

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

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

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

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

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

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

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

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

9

Table of Contents

Prospect Information

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

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

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

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

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

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

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

10

Table of Contents

Recent Events

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

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

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

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

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

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

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

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

11

Table of Contents

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

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

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

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

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

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

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

Risks Associated with our Business

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

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

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

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

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

12

Table of Contents

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

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

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

Corporate Information

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

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

13

Table of Contents
The Offering

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

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

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

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

14

Table of Contents
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

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

Consolidated Statements of Operations Information:

	 	 

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

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

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

15

Table of Contents

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

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

Consolidated Balance Sheets Information:

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

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

Consolidated Statements of Cash Flows Information:

	 	 

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

Net cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	$	(9,617	)	$	(17,386	)	$	(65,671	)	$	(27,591	)	$	(191,800	)	$	(331,009	)	 	 	
Investing activities	 	 	(14,663	)	 	(58,161	)	 	(156,882	)	 	(500,393	)	 	(589,975	)	 	(1,329,026	)	 	 	
Financing activities	 	 	19,768	 	 	104,973	 	 	331,084	 	 	519,695	 	 	742,685	 	 	1,760,450	 	 	 	
16

Table of Contents
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.

17

Table of Contents

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.

18

Table of Contents

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

19

Table of Contents

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

20

Table of Contents

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;

21

Table of Contents

•
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.

22

Table of Contents

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

23

Table of Contents

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

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

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

•
oil and natural gas prices;

•
our ability to locate and acquire hydrocarbon reserves;

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

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

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

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

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

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

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

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

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

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

24

Table of Contents

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

•
global economic conditions;

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

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

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

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

•
weather conditions and natural disasters;

•
technological advances affecting energy consumption;

•
governmental regulations and taxation policies;

•
proximity and capacity of transportation facilities;

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

•
the price and availability of alternative fuels.

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

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

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

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

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

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

25

Table of Contents

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,

26

Table of Contents

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.

27

Table of Contents

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

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

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

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

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

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

28

Table of Contents

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

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

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

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

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

•
military conflicts.

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

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

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

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

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

•
disrupt our operations;

•
require us to incur greater costs for security;

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

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

•
limit access to markets for periods of time.

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

29

Table of Contents

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

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

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

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

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

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

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

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

30

Table of Contents

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

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

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

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

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

•
licenses for drilling operations;

•
tax increases, including retroactive claims;

•
unitization of oil accumulations;

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

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

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

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

31

Table of Contents

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

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

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

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

•
higher operating costs;

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

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

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

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

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

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

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

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

32

Table of Contents

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

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

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

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

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

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

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

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

33

Table of Contents

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

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

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

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

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

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

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

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

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

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

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

34

Table of Contents

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

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

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

•
our incurrence of additional indebtedness;

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

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

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

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

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

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

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

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

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

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

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

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

35

Table of Contents

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

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

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

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

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

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

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

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

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

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

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

•
recoverable reserves;

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

•
development and operating costs; and

•
potential environmental and other liabilities.

36

Table of Contents

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

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

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

•
difficulty associated with coordinating geographically separate organizations; and

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

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

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

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

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

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

37

Table of Contents

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

•
institute a more comprehensive compliance function;

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

•
comply with rules promulgated by the NYSE;

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

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

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

•
establish an investor relations function.

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

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

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

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

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

38

Table of Contents

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

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

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

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

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

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

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

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

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

39

Table of Contents

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

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

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

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

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

40

Table of Contents

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

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

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

•
the price of oil and natural gas;

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

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

•
the recruitment or departure of key personnel;

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

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

•
analysts' reports or recommendations;

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

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

•
the issuance of any additional securities of ours;

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

•
general economic, political and market conditions.

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

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

41

Table of Contents

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

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

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

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

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

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

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

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

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

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

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

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

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

42

Table of Contents

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

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

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

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

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

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

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

43

Table of Contents

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

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

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

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

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

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

44

Table of Contents

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.

45

Table of Contents
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;

46

Table of Contents

•
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.

47

Table of Contents
DIVIDEND POLICY

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

48

Table of Contents
USE OF PROCEEDS

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

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

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

•
$175.0 million for development in Ghana;

•
$225.0 million for exploration and appraisal in Ghana;

•
$30.0 million for exploration and appraisal in Cameroon;

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

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

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

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

49

Table of Contents
CORPORATE REORGANIZATION

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

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

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

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

50

Table of Contents
CAPITALIZATION

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

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

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

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

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

51

Table of Contents

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

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

52

Table of Contents
DILUTION

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

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

	 	Common Shares
Purchased	 	 

	 	 	
 
	 	 	 	Total Consideration	 	 

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

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

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

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

53

Table of Contents
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.

54

Table of Contents

Consolidated Statements of Operations Information:

	 	 

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

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

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

55

Table of Contents

Consolidated Balance Sheets Information:

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

	 	 

	 	 
	 	(Unaudited)

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

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

Consolidated Statements of Cash Flows Information:

	 	 

	 	 
	 	 
	 	Period
April 23, 2003
(Inception)
through
December 31
2010	 	 	
 
	 	Year Ended December 31	 	 	 	 	 	
 
	 	2006	 	2007	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	
Net cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	$	(9,617	)	$	(17,386	)	$	(65,671	)	$	(27,591	)	$	(191,800	)	$	(331,009	)	 	 	
Investing activities	 	 	(14,663	)	 	(58,161	)	 	(156,882	)	 	(500,393	)	 	(589,975	)	 	(1,329,026	)	 	 	
Financing activities	 	 	19,768	 	 	104,973	 	 	331,084	 	 	519,695	 	 	742,685	 	 	1,760,450	 	 	 	
56

Table of Contents
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Overview

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

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

Exploration and Other Agreements

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

57

Table of Contents

Factors Affecting Comparability of Future Results

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

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

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

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

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

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

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

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

58

Table of Contents

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

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

        We expect to earn income from:

•
oil and natural gas sales to international markets; and

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

        We expect that our expenses will include:

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

•
maintenance and repair of property and equipment;

•
depreciation of fixed assets;

•
depletion of oilfields and associated abandonment costs;

•
exploration and appraisal costs;

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

•
selling expenses and general and administrative expenses; and

•
financing expenses, interest expense and foreign exchange losses.

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

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

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

•
changes in fair value of derivative financial instruments;

•
our success in obtaining new licenses and other acquisitions;

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

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

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

59

Table of Contents

Results of Operations

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

Year Ended December 31, 2010 vs. 2009

	 	Years Ended
December 31	 	 

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

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

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

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

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

60

Table of Contents

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

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

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

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

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

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

Year Ended December 31, 2009 vs. 2008

	 	Years Ended
December 31	 	 

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

61

Table of Contents

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

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

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

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

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

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

Liquidity and Capital Resources

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

Significant Sources of Capital

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

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

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

62

Table of Contents

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

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

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

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

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

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

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

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

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

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

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

63

Table of Contents

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

Capital Expenditures and Investments

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

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

•
drill two exploration wells in Cameroon;

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

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

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

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

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

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

64

Table of Contents

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

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

•
$175.0 million for development in Ghana;

•
$225.0 million for exploration and appraisal in Ghana;

•
$30.0 million for exploration and appraisal in Cameroon;

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

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

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

Cash Flows

	 	 

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

	 	 
	 	 
	 	(Unaudited)

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

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

65

Table of Contents

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

Contractual Obligations

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

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

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

(2)
The amounts included in the table above represent principal maturities only. Pursuant to the terms in the commercial debt facilities, when any junior debt is outstanding, repayments may be required to be made under the agreement, whereby 75% of any funds remaining on any repayment date, after required payments are made, will be applied to prepay the junior facilities and the remaining 25% will be applied to prepay the senior facilities. The table of scheduled maturities assumes the outstanding borrowings under the junior facilities will be repaid on June 15, 2016. If repayments are required as noted above, amortization of the junior facilities will occur through such repayments. Subsequent to December 31, 2010 and prior to the date of the financial statements, we borrowed an additional $28.0 million under the senior facilities. As of the date of our audited financial statements, borrowings against the commercial debt facilities totaled $1.07 billion. Subsequent to the date of our audited financial statements, we borrowed an additional $65 million under the junior facilities. In March 2011 we entered into a new $2.0 billion commercial debt facility. At March 31, 2011 we had $700 million of committed undrawn capacity under such facility, as well as the ability to increase the commitments under the facility by $1.0 billion. As of April 13, 2011, borrowings against the new commercial debt facility totaled $1.3 billion. The scheduled principal maturities during the next five years and thereafter are: 2011—$—; 2012—$—; 2013—$—; 2014—$—; 2015—$300 million and thereafter—$1.0 billion.

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

66

Table of Contents

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

	 	 

	 	 

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

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

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

Off-Balance Sheet Arrangements

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

Critical Accounting Policies

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

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

67

Table of Contents

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

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

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

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

68

Table of Contents

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

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

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

69

Table of Contents

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

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

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

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

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

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

70

Table of Contents

the November 28, 2010 successful commencement of production confirmed our expectations that these assets could be utilized to successfully produce from the field with an economical cost structure.•
The recognition of our first revenues from oil production in January 2011. The Company was a development stage entity as of December 31, 2010, but upon recognition of our first revenues in January 2011, is no longer categorized as such.

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

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

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

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

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

Our projection of taxable income is based on a per barrel price of $79.35, which is also used to calculate our standardized measure, and our production forecast, which is based on our proved reserve estimates and our schedule for production. Based on this projection, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2012. Assuming a 25% decrease in prices or volumes, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2013. Assuming a 25% decrease in prices and volumes, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2015. Assuming a decrease in the price of oil to $50 per barrel and no change in anticipated production volumes, we estimate that we would utilize our $259.9 million net operating loss carryforward before the end of 2013. A $50 per barrel price represents an average price per barrel lower than the average price during 2008 and 2009 when oil prices sustained substantial price declines and a 57% decrease from the Dated Brent price of $116.45 per barrel on March 2, 2011. Conversely, assuming a 25% increase in prices (or $99.19 per barrel which would still be less than the $116.45 per barrel price of Dated Brent on March 2, 2011, the date of our financial statements for the year ended December 31, 2010 included herein) and no change in volume, we estimate that we would utilize our $295.9 million net operating loss carryforward before the end of 2011.•
There is an unlimited net operating loss carryforward period under Ghanaian tax law, which provides flexibility in utilization of the net operating loss.

71

Table of Contents

        ASC 740 provides a more-likely-than-not standard in evaluating whether a valuation allowance is necessary after weighing all of the available evidence. Using the more-likely-than-not standard and weighing all available positive and negative evidence, the Company concluded that the positive evidence outweighs the negative evidence of cumulative tax losses incurred during the development stage. Accordingly, we determined that it is more likely than not that the deferred tax asset for our Ghanaian operations would be realized and, therefore, released the $20.6 million valuation allowance that was recorded as of December 31, 2009 and recognized $56.9 million of deferred tax assets generated during 2010.

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

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

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

•
the engineering and geological interpretation of available data;

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

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

•
the judgments of the persons preparing the estimates.

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

72

Table of Contents

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 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.

73

Table of Contents

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

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

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

Qualitative and Quantitative Disclosures about Market Risk

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

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

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

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

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

74

Table of Contents

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.

75

Table of Contents
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.

76

Table of Contents

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

77

Table of Contents

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.

78

Table of Contents

Oil and Gas Industry

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

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

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

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

Tano Basin

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

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

Exploration History

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

79

Table of Contents

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

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

Cameroon

Country Overview

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

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

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

Oil and Gas Industry

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

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

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

80

Table of Contents

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,

81

Table of Contents

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

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

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

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

Morocco

Country Overview

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

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

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

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

82

Table of Contents

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.

83

Table of Contents
BUSINESS

Overview

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

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

Our Competitive Strengths

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

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

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

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

84

Table of Contents

Well-defined production and growth plan

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

Significant upside potential from exploratory assets

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

Oil-weighted asset portfolio in key strategic regions

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

New ventures group focused on expanding our asset portfolio

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

85

Table of Contents

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

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

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

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

Strong financial position

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

Our Strategy

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

86

Table of Contents

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

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

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

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

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

Focus on rapidly developing our discoveries to initial production

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

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

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

87

Table of Contents

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

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

Identify, access and explore emerging exploratory regions and hydrocarbon plays

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

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

Acquire additional exploration assets

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

Kosmos Exploration Approach

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

88

Table of Contents

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

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

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

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

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

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

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

89

Table of Contents

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

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

Our Discoveries and Prospects

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

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

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

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

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

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

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

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

90

Table of Contents

Ghana Well Information

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

	 	Operator	 	Spud Date(1)	 	Total
Depth
(feet)	 	Net
Hydrocarbon
Pay
(feet)	 	Status(2)	 	Comments	
Jubilee	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
J-09 (Mahogany-1)	 	Kosmos	 	05/30/07	 	 	12,553	 	 	321	 	Producing	 	Discovery well for Jubilee in WCTP Block. Drill stem tested at rates in excess of 20,500 bopd. Lower completion installed.	
Hyedua-1	 	Tullow	 	07/27/07	 	 	13,130	 	 	180	 	Plugged Back	 	Downdip confirmation well in DT Block.	
 	J-10 Water Injector ("WI") (Hyedua-1BP1)	 	Tullow	 	07/27/07	 	 	12,631	 	 	136	 	Completion Pending	 	Whole core obtained. Injectivity test conducted at rates in excess of 20,000 bwpd.	
J-16GI Gas Injectors ("GI") (Mahogany-2)	 	Tullow	 	03/06/08	 	 	11,296	 	 	164	 	Injection Ready	 	Updip confirmation well for Jubilee reservoirs. Whole core obtained. Two Drill Stem Tests ("DSTs") conducted.	
J-08 (Hyedua-2)	 	Tullow	 	10/09/08	 	 	12,018	 	 	180	 	Producing	 	Drill stem tested at rates in excess of 16,500 bopd. Whole core obtained.	
J-04	 	Tullow	 	01/17/09	 	 	15,121	 	 	90	 	Plugged Back	 	Tested the Southeastern edge of the Jubilee fairway.	
 	J-04 Sidetrack ("ST")	 	Tullow	 	01/17/09	 	 	13,803	 	 	199	 	Completion Pending	 	Observation well for interference testing.	
J-01	 	Tullow	 	03/18/09	 	 	12,411	 	 	140	 	Producing	 	 	
J-02	 	Tullow	 	03/25/09	 	 	13,829	 	 	186	 	Producing	 	Observation well for interference testing.	
J-11WI	 	Tullow	 	05/06/09	 	 	13,822	 	 	121	 	Completion Pending	 	Down structure water injector—net reservoir 281 feet.	
J-12WI	 	Tullow	 	05/11/09	 	 	14,081	 	 	188	 	Injecting	 	Down structure water injector—net reservoir 319 feet.	
J-15WI	 	Tullow	 	05/14/09	 	 	16,949	 	 	47	 	Completion Pending	 	Only drilled through Upper Mahogany—down structure water injector-net reservoir 87 feet.	
J-07	 	Tullow	 	05/19/09	 	 	13,599	 	 	121	 	Plugged Back	 	Whole core obtained.	
 	J-07ST	 	Tullow	 	05/19/09	 	 	13,701	 	 	116	 	Producing	 	 	
J-03	 	Tullow	 	09/29/09	 	 	12,507	 	 	173	 	Completion Pending	 	Lower completion installed.	
J-05	 	Tullow	 	07/08/09	 	 	13,753	 	 	193	 	Completion Pending	 	Lower completion installed.	
J-17	 	Tullow	 	10/07/09	 	 	19,390	 	 	174	 	Plugged Back	 	Only drilled through Upper Mahogany reservoirs.	
 	J-17STGI	 	Tullow	 	10/07/09	 	 	19,574	 	 	197	 	Completion Pending	 	 	
J-13WI	 	Tullow	 	10/10/09	 	 	13,058	 	 	143	 	Completion Pending	 	Down structure water injector—net reservoir 348 feet.	
J-14WI	 	Tullow	 	10/14/09	 	 	13,999	 	 	77	 	Injecting	 	Down structure water injector—net reservoir 334 feet.	
Mahogany East	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mahogany-3	 	Kosmos	 	11/27/08	 	 	14,262	 	 	108	 	Suspended	 	Discovery well for Mahogany Deep.	
Mahogany-4	 	Kosmos	 	08/28/09	 	 	12,074	 	 	141	 	Suspended	 	Updip confirmation well for the Mahogany East reservoirs.	
Mahogany Deep-2	 	Kosmos	 	09/29/09	 	 	14,193	 	 	49	 	Suspended	 	Drilled to delineate deep reservoirs—net reservoir of 384 feet.	
Mahogany-5	 	Kosmos	 	04/18/10	 	 	13,084	 	 	75	 	Suspended	 	Eastern confirmation of Mahogany East reservoirs.	
Odum	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Odum-1	 	Kosmos	 	01/18/08	 	 	11,109	 	 	72	 	Suspended	 	Discovery well for Odum.	
Odum-2	 	Kosmos	 	11/12/09	 	 	8,222	 	 	66	 	Suspended	 	Confirmation well for Odum.	
91

Table of Contents

	 	Operator	 	Spud Date(1)	 	Total
Depth
(feet)	 	Net
Hydrocarbon
Pay
(feet)	 	Status(2)	 	Comments	
Tweneboa	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Tweneboa-1	 	Tullow	 	01/26/09	 	 	13,002	 	 	69	 	Suspended	 	Discovery well for Tweneboa condensate pays.	
Tweneboa-2	 	Tullow	 	12/06/09	 	 	13,878	 	 	105	 	Suspended	 	Confirmation well for Tweneboa. Discovery of Central Oil Channel below condensate pays. Whole core obtained.	
Tweneboa-3	 	Tullow	 	11/26/10	 	 	12,811	 	 	29	 	Plugged back	 	Confirmation well for Tweneboa.	
Tweneboa-3ST	 	Tullow	 	12/22/10	 	 	12,816	 	 	112	 	Suspended	 	 	
Tweneboa-4	 	Tullow	 	1/16/11	 	 	13,146	 	 	59	 	Suspended	 	Surface hole section drilled early as part of batch program. Drilling resumed 3/15/11.	
Onyina	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Onyina-1	 	Tullow	 	09/25/10	 	 	 	 	 	—	 	Abandoned	 	Dry hole.	
Enyenra (formerly known as Owo)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Owo-1	 	Tullow	 	06/10/10	 	 	12,766	 	 	174	 	Plugged Back	 	Discovery well for Enyenra.	
 	Owo-1 ST1	 	Tullow	 	07/28/10	 	 	13,117	 	 	115	 	Suspended	 	Lateral confirmation well for Enyenra channels, and discovery wells for deeper condensate pays. Whole core obtained.	
Enyenra-2	 	Tullow	 	01/22/11	 	 	13,887	 	 	121	 	Suspended	 	Downdip confirmation well for Enyenra channels. Discovery well for Tweneboa Deep.	
Teak	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Teak-1	 	Kosmos	 	12/21/10	 	 	10,398	 	 	239	 	Suspended	 	Discovery well for Teak.	
Teak-2	 	Kosmos	 	2/12/11	 	 	11,184	 	 	89	 	Suspended	 	Drilled fault block adjacent to Teak-1 discovery.	
Dahoma	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Dahoma-1	 	Kosmos	 	02/04/10	 	 	14,403	 	 	—	 	Abandoned	 	Dry hole.	

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

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

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

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

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

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

Suspended	
 	
Exploration / appraisal well that has had production casing installed across the target interval. However, plans to utilize the well as part of a development have not yet been approved.	
92

Table of Contents

Prospect Information

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

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

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

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

93

Table of Contents

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

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

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

Ghana

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

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

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

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

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

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

94

Table of Contents

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

Our Ghanaian Discoveries

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

Jubilee Discovery

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

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

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

Geology

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

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

95

Table of Contents

Subsurface Engineering

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

Facilities and wells

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

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

Mahogany East Discovery

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

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

96

Table of Contents

Odum Discovery

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

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

Teak Discovery

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

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

Tweneboa Discovery

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

97

Table of Contents

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

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

Enyenra Discovery (formerly known as Owo)

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

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

Tweneboa Deep Discovery

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

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

Our Ghanaian Prospects

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

Banda Campanian

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

98

Table of Contents

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

Banda Cenomanian

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

Makore

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

Odum East

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

Sapele

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

Funtum

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

99

Table of Contents

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

Assin

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

Okoro

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

Late Cretaceous WCTP Play

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

Walnut

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

DT Sapele

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

Wassa

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

100

Table of Contents

Adinkra

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

Oyoko

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

Ananta

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

Cameroon

Overview

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

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

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

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

101

Table of Contents

Geology

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

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

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

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

Our Cameroon Prospects

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

N'gata

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

N'donga

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

102

Table of Contents

Disangue

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

Pongo Songo

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

Bonongo

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

Coco East

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

Liwenyi

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

Liwenyi South

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

Meme

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

103

Table of Contents

Bamusso

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

Morocco

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

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

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

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

Lower Cretaceous Play Concept

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

104

Table of Contents

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

Our Moroccan Prospects

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

Gargaa

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

Argane

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

Safsaf

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

Aarar

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

Zitoune

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

105

Table of Contents

Al Arz

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

Felline

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

Nakhil

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

Barremian Tilted Fault Block Play

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

Our Reserves

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

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

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

106

Table of Contents

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

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

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

(2)
Standardized Measure represents the present value of estimated future cash inflows to be generated from the production of proved oil and natural gas reserves, net of future development and production costs, future income tax expense related to our proved oil and gas reserves levied at a corporate parent and intermediate subsidiary level, royalties, additional oil entitlements and future tax expense levied at an asset level (in our case, future Ghanaian tax expense levied under the WCTP and DT Petroleum Agreements), discounted using an annual discount rate of 10% to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure often differs from PV-10 because Standardized Measure includes the effects of future income tax expense related to our proved oil and gas reserves levied at a corporate parent and intermediate subsidiary level on future net revenues. However, as we have been a tax exempted company incorporated pursuant to the laws of the Cayman Islands to date and will be a tax exempted company incorporated pursuant to the laws of Bermuda following the completion of the corporate reorganization to be completed in connection with this offering, and as the Company's intermediate subsidiaries positioned

107

Table of Contents

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

Estimated proved reserves

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

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

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

Independent petroleum engineers

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

108

Table of Contents

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

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

Technology used to establish proved reserves

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

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

109

Table of Contents

depositional environments, rock quality, and appraisal and development plans to assess the estimated ultimate recoverable reserves as a function of the original oil in place. These qualitative measures are benchmarked and validated against sound petroleum reservoir engineering principles and equations to estimate the ultimate recoverable reserves volume. These techniques include, but are not limited to, nodal analysis, material balance, and numerical flow simulation.

Internal controls over reserves estimation process

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

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

Price history

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

110

Table of Contents

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

License Areas

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

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

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

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

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

111

Table of Contents

Drilling activity

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

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

 
	 	Productive	 	Dry	 	Total	 	Productive	 	Dry	 	Total	 	 

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

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

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

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

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

	 	Wells in the Process
of Drilling or
in Active Completion	 	Wells Suspended or
Waiting on Completion	 	
 
	 	Exploration	 	Development	 	Exploration	 	Development	 	
 
	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	West Cape Three Points	 	 	1	 	 	0.31	 	 	1	 	 	0.23	 	 	8	 	 	2.47	 	 	4	 	 	0.94	 	
 	Deepwater Tano	 	 	1	 	 	0.18	 	 	—	 	 	—	 	 	5	 	 	0.9	 	 	2	 	 	0.47	 	
Cameroon	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Kombe-N'sepe	 	 	1	 	 	0.35	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
112

Table of Contents

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

113

Table of Contents

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

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

Deepwater Tano ("DT") Block

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

114

Table of Contents

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.

115

Table of Contents

        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.

116

Table of Contents

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

117

Table of Contents

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

Sales and Marketing

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

Competition

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

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

118

Table of Contents

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

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

Title to Property

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

Environmental Matters

General

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

•
require the acquisition of various permits before drilling commences;

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

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

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

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

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

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

119

Table of Contents

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

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

Climate Change

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

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

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

120

Table of Contents

Oil Spill Response

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

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

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

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

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

121

Table of Contents

by or on behalf of third party individuals in the event of such party's bodily injury or death. For example, if there were a well blowout in the Jubilee Unit (in which we have a 23.4913% working interest) our limit of well control, redrill and pollution clean up and containment coverage would be 23.4913% of $300 million (being $70.4 million) less a deductible of 23.4913% of $5 million (being $1.1 million), and our limit of liability coverage including pollution liability would be 23.4913% of $300 million (being $70.4 million).

Other Regulation of the Oil and Gas Industry

Ghana

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

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

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

Cameroon

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

122

Table of Contents

such contracts require the consent of the government. SNH, established in March 1980, participates in the form of joint ventures with the "contractors." Assignment of license interests requires the consent of SNH.

Morocco

        The two main legislative acts in Morocco relevant to petroleum exploration and production are (i) the Law 21-90 (1 April 1992) as amended and completed by the Law 27-99 (15 February 2000) and (ii) the Decree 2-93-786 (3 November 1993) as amended and completed by decree 2-99-210 (16 March 2000) (together, "Morocco's Petroleum Laws"). The regulatory authority in Morocco is the Ministry of Energy, Mines, Water and Environment and the national oil company acting on his behalf is the Office National des Hydrocarbures et des Mines  generally referred to as "ONHYM." ONHYM is a public establishment ( établissement public ) with the legal personality and financial autonomy created pursuant to the Law 33-01 (11 November 2003) which was further completed by the Decree 2-04-372 (29 December 2004).

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

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

Certain Bermuda Law Considerations

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

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

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

123

Table of Contents

Employees

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

Legal Proceedings

        We are not currently party to any material legal proceedings. However, from time to time we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, environmental, safety and health matters. It is not presently possible to determine whether any such matters will have a material adverse effect on our consolidated financial position, results of operations, or liquidity.

Corporate Information

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

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

124

Table of Contents
MANAGEMENT

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

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

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

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

125

Table of Contents

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.

126

Table of Contents

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

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

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

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

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

        William S. Hayes has served as our General Counsel since 2007. Prior to joining Kosmos, Mr. Hayes was Senior Vice President and General Counsel for Urals Energy PLC in 2007 and Cardinal Resources PLC from 2004 until 2007. Mr. Hayes has worked for or represented public and private,

127

Table of Contents

major and independent exploration and production companies in some 30 countries. Mr. Hayes holds a Juris Doctor from St. Mary's University School of Law and a Bachelor of Journalism from the University of Texas. He is a member of the State Bar of Texas, the International Bar Association and the Association of International Petroleum Negotiators.

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

Board of Directors

Board Composition

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

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

Director Independence

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

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

Committees of the Board of Directors

        We are a "controlled company" as that term is set forth in Section 303A of the NYSE Listed Company Manual because more than 50% of our voting power is held by funds affiliated with our Investors, acting as a group. Under the NYSE rules, a "controlled company" may elect not to comply with certain NYSE corporate governance requirements, including (1) the requirement that a majority of the board of directors consist of independent directors, (2) the requirement that the nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities, (3) the requirement that the compensation committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities and (4) the requirement for an annual performance evaluation of the nominating and corporate governance and compensation committees. After completion of this offering more than 50% of our voting power will continue to be held by the Investors, and we intend to elect to be treated as a controlled company and thus avail ourselves of these exemptions. As a result, although we have adopted charters for our audit, nominating and corporate governance and

128

Table of Contents

compensation committees and intend to conduct annual performance evaluations of these committees, our board of directors does not consist of a majority of independent directors nor do our nominating and corporate governance and compensation committees consist of independent directors. Accordingly, so long as we are a "controlled company," you will not have the same protections afforded to shareholders of companies that are subject to all of the corporate governance requirements of the NYSE.

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

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

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

•
review the proposed scope and results of the audit;

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

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

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

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

•
recognize and prevent prohibited non-audit services;

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

•
oversee internal audit functions; and

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

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

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

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

•
administer our equity based incentive plan; and

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

129

Table of Contents

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

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

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

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

Compensation Committee Interlocks and Insider Participation

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

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

Code of Business Conduct and Ethics

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

Corporate Governance Guidelines

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

Shareholders Agreement

        Prior to the consummation of this offering, we will enter into a shareholders agreement with affiliates of the Investors pursuant to which the Investors, collectively, will have the right to designate four members of our board of directors. Upon the consummation of this offering, each Investor will have the right to designate: (i) two directors (or, if the size of the board is increased, 25% of the board, rounded to the nearest whole number) if it owns 20% or more of the issued and outstanding common shares eligible to vote at an annual general meeting of shareholders and 50% or more of the common shares owned by such Investor immediately prior to the consummation of this offering, and (ii) one director (or, if the size of the board is increased, 12.5% of the board, rounded to the nearest whole number) if it owns 7.5% or more of the issued and outstanding common shares eligible to vote at an annual general meeting of shareholders. Under the shareholders agreement, subject to the corporate governance requirements of the NYSE, and for as long as the Investors constitute a group that beneficially owns more than 50% of the Company's voting power, the Investors shall have the right to designate 50% of the members of the nominating and corporate governance committee and a majority of the members of the compensation committee. After the Investors no longer constitute a group beneficially owning more than 50% of the Company's voting power, each Investor entitled to designate a director shall have the right to nominate one of its director designees to each committee of the board (other than the audit committee, which will include Investor-designated directors on a transition basis to the extent consistent with the corporate governance requirements of the NYSE). An Investor shall cease to have the right to designate committee members in the event that the Investor holds less than 7.5% of the issued and outstanding common shares eligible to vote at an annual general meeting of shareholders.

130

Table of Contents

Compensation Discussion and Analysis

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

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

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

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

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

•
Dennis McLaughlin, Senior Vice President, Development.

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

Objectives

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

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

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

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

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

Elements of Compensation

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

Base Salary

        Each of our named executive officers receives a base salary that comprises a relatively modest portion of his compensation. In determining our named executive officers' base salaries, we consider factors such as the executive's experience and responsibilities and the salaries paid to our other executives and employees. We review their salaries annually for possible increases. In December 2010, each of our named executives (other than Mr. Musselman, who retired effective December 31, 2010) received a salary increase as follows: Mr. Maxted from $533,000 to $600,000, Mr. Dunlevy from $427,000 to $450,000, Mr. Hayes from $337,050 to $350,000 and Mr. McLaughlin from $331,700 to

131

Table of Contents

$350,000. For the amounts of base salary that the executives received in 2010, see "Summary Compensation Table—Salary".

Annual Bonus

        Each of our named executive officers is eligible for a discretionary annual cash bonus in an amount determined based on one or more of the following performance factors as related to his responsibilities: financial performance, operating performance, significant strategic initiatives, resolution of unforeseen events and organizational leadership. Although our compensation committee considers the level of achievement of each of these factors, other factors may be considered, and the bonuses are not calculated formulaically. The table below summarizes our named executive officers' achievement of the performance factors for 2010 (other than for Mr. Musselman, who, due to his retirement, was not eligible for a bonus for 2010). For the amounts of the bonuses paid to the executives for 2010, see "Summary Compensation Table—Bonus".
 	 	 	 	 	
Executive	 	Performance Factor	 	Achievement of Factor	
Mr. Maxted	 	Significant strategic initiatives	 	•       Pursued consummation of a commercial agreement to sell our Ghanaian assets to ExxonMobil	
 	 	 	 	•       Positioned Kosmos to pursue this offering	
 	 	Resolution of unforeseen events	 	•       Strengthened relationships with U.S. and Ghanaian governmental agencies	
 	 	Organizational leadership	 	•       Managed and expanded business and maintained employee morale during challenging period	
Messrs. Dunlevy and Hayes	 	Financial performance	 	•       Secured increase in project finance commercial bank facilities from $900 million to $1.25 billion to support Kosmos' share of Jubilee Field Phase 1 development expenditure	
 	 	Significant strategic initiatives	 	•       Initiated accelerated public offering and private placement funding processes	
 	 	Resolution of unforeseen events	 	•       Received DOJ letter of declination regarding closure of inquiry into alleged FCPA violations in connection with the WCTP Petroleum Agreement	
 	 	 	 	•       Managed ongoing FCPA review	
 	 	Organizational leadership	 	•       Engaged in ongoing corporate development in support of this offering and business growth	
 	 	 	 	•       Developed and enhanced existing internal controls to ensure compliance with laws applicable to public companies (e.g., Sarbanes-Oxley Act and NYSE listing requirements)	
Mr. McLaughlin	 	Operating performance	 	•       Actual total recordable incident rate and lost time incident rate of 1.38 and 0.46, respectively, substantially exceeded goals of 2.5 and 0.6, respectively	
 	 	Resolution of unforeseen events	 	•       Implemented recovery plans from potential delay-causing events with no material impact on first oil production	
 	 	Organizational leadership	 	•       Integrated project activities with internal functions and external unit operator, achieving seamless transition to production asset	
 	 	 	 	•       Assumed interim team leader role for Mahogany East	
132

Table of Contents

        Following this offering, we expect that our named executive officers will continue to be eligible for annual cash bonuses on terms to be determined by our compensation committee. For additional information on the annual bonuses for which our named executive officers and employees are eligible, see "Annual Incentive Plan."

Equity-based incentive awards

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

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

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

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

Retirement and Health and Welfare Benefits

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

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

Severance and Change in Control Benefits

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

133

Table of Contents

Compensation Process

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

Summary Compensation Table

        The following table summarizes the compensation of our named executive officers for 2010: our Chief Executive Officer, our Chief Financial Officer and our three other most highly compensated executive officers as determined by their total compensation set forth in the table. Mr. Musselman, who served as our Chief Executive Officer during 2010, retired from his employment with Kosmos effective as of December 31, 2010. Mr. Maxted, who served as our Chief Operating Officer during 2010, became our Chief Executive Officer effective as of January 1, 2011.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Name and
Principal Position	 	Year	 	Salary
($)(1)	 	Bonus
($)	 	Stock
Awards
($)	 	Option
Awards
($)(2)	 	Non-Equity
Incentive Plan
Compensation
($)	 	Change in
Pension
Value and
Non-qualified
Deferred
Compensation
Earnings
($)	 	All Other
Compensation
($)(3)	 	Total
($)	 	
James C. Musselman
Chairman and Chief Executive Officer	 	 	2010	 	 	593,000	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	11,792,648	 	 	12,385,648	 	
W. Greg Dunlevy
Executive Vice President and Chief Financial Officer	 	 	
2010	 	 	
428,917	 	 	
469,700	 	 	
—	 	 	
—	 	 	
—	 	 	
—	 	 	
14,785	 	 	
913,402	 	
Brian F. Maxted
Executive Vice President and Chief Operating Officer	 	 	
2010	 	 	
538,583	 	 	
900,000	 	 	
—	 	 	
—	 	 	
—	 	 	
—	 	 	
85	 	 	
1,438,668	 	
William S. Hayes
Senior Vice President and General Counsel	 	 	
2010	 	 	
338,130	 	 	
337,050	 	 	
—	 	 	
782,550	 	 	
—	 	 	
—	 	 	
26,900	 	 	
1,484,630	 	
Dennis C. McLaughlin
Senior Vice President of Development	 	 	
2010	 	 	
333,225	 	 	
406,700	 	 	
—	 	 	
782,550	 	 	
—	 	 	
—	 	 	
28,247	 	 	
1,550,722	 	

(1)
The amounts in this column are the actual amounts of salary paid to our named executive officers in 2010. Effective December 1, 2010, the annual salary rates of Messrs. Dunlevy, Maxted, Hayes and McLaughlin were increased to the following: Mr. Dunlevy ($450,000), Mr. Maxted ($600,000), Mr. Hayes ($350,000) and Mr. McLaughlin ($350,000). Mr. Musselman, who retired effective as of December 31, 2010, was not eligible for a salary increase.

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

134

Table of Contents

(3)
The following items are reported in this column:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Name	 	401(k) Matching
Contributions
($)(4)	 	Vacation
Payments
($)(5)	 	Life
Insurance
($)(6)	 	Retirement
Payments
($)(7)	 	Total
($)	 	
James C. Musselman	 	 	—	 	 	—	 	 	85	 	 	11,792,563	 	 	11,792,648	 	
W. Greg Dunlevy	 	 	14,700	 	 	—	 	 	85	 	 	—	 	 	14,785	 	
Brian F. Maxted	 	 	—	 	 	—	 	 	85	 	 	—	 	 	85	 	
William S. Hayes	 	 	14,700	 	 	12,115	 	 	85	 	 	—	 	 	26,900	 	
Dennis C. McLaughlin	 	 	14,700	 	 	13,462	 	 	85	 	 	—	 	 	28,247	 	

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

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

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

(7)
Includes severance in the amount of $593,000, accelerated vesting of unvested profit units in the amount of $11,107,063 and payment of $92,500 in legal fees provided to Mr. Musselman under his retirement agreement. The actual amount of severance that Mr. Musselman receives may be less than $593,000, as the monthly severance payments will cease prior to payment of the full amount on the completion of the lock-up period under agreements entered into with the underwriters of this offering. The value of such accelerated vesting is based on the valuation of the profit units as of December 31, 2010. See "—Potential Payments on Termination or Change in Control—Mr. Musselman."

2010 Grants of Plan-Based Awards

        The following table provides information on grants of plan-based awards made to our named executive officers during 2010. The awards were granted in the form of profit units in Kosmos Energy Holdings and will be exchanged for awards on common shares in connection with this offering (see "—Awards under the LTIP"). The share numbers set forth in the table assume solely for this purpose that this exchange had occurred as of the grant date of these units (based on an assumed initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price range set forth on the cover page of this prospectus).

	 	 

	 	 

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

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

	 	 	 	 	 	 	 	 	 	Exercise or
Base Price of
Option
Awards
($/Sh)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Name	 	Grant
Date(1)	 	Threshold
($)	 	Target
($)	 	Maximum
($)	 	Threshold
(#)	 	Target
(#)	 	Maximum
(#)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
James C. Musselman	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	
W. Greg Dunlevy	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	
Brian F. Maxted	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	
William S. Hayes	 	 	12/9/2010	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	351,850	 	 	—	 	 	782,550	 	 	 	 	 	 	 	 	 	 	 	 	
Dennis C. McLaughlin	 	 	12/9/2010	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	351,850	 	 	—	 	 	782,550	 	 	 	 	 	 	 	 	 	 	 	 	

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

135

Table of Contents

Outstanding Equity Awards at 2010 Fiscal Year End

        The following table provides information on the outstanding equity awards held by our named executive officers as of December 31, 2010. These awards were granted in the form of profit units in Kosmos Energy Holdings and will be exchanged for common shares and awards on common shares in connection with this offering (see "—Awards under the LTIP"). The amounts set forth in the table assume solely for this purpose that this exchange had occurred as of December 31, 2010 (based on an assumed initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price range set forth on the cover page of this prospectus).

	 	 
	 	Option Awards	 	Stock Awards	 	
Name	 	Grant
Date	 	Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable	 	Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable	 	Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexercised
Unearned
Options
(#)	 	Option
Exercise
Price
($)	 	Option
Expiration
Date	 	Number of
Shares or
Units of
Stock
That Have
Not
Vested
(#)(1)	 	Market
Value of
Shares or
Units of
Stock
That Have
Not
Vested
($)	 	Equity
Incentive
Plan
Awards:
Number of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested
(#)	 	Equity
Incentive
Plan
Awards:
Market or
Payout
Value of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested
($)	 	
W. Greg Dunlevy	 	6/13/2007	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	123,311	 	 	2,096,285	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	1,134,108	 	 	19,279,829	 	 	—	 	 	—	 	
Brian F. Maxted	 	6/13/2007	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	184,965	 	 	3,144,412	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	1,701,160	 	 	28,919,721	 	 	—	 	 	—	 	
William S. Hayes	 	10/11/2007	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	82,208	 	 	1,397,528	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	38,163	 	 	648,764	 	 	—	 	 	—	 	
 	 	12/10/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	48,311	 	 	821,291	 	 	—	 	 	—	 	
 	 	12/9/2010	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	351,850	 	 	5,981,458	 	 	—	 	 	—	 	
Dennis C. McLaughlin	 	2/6/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	82,208	 	 	1,397,528	 	 	—	 	 	—	 	
 	 	6/11/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	9,541	 	 	162,191	 	 	—	 	 	—	 	
 	 	12/10/2008	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	48,311	 	 	821,292	 	 	—	 	 	—	 	
 	 	12/9/2010	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	351,850	 	 	5,981,458	 	 	—	 	 	—	 	

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

2010 Option Exercises and Stock Vested

        The following table provides information on our named executive officers' equity awards that vested in 2010. These awards were granted in the form of profit units in Kosmos Energy Holdings and will be exchanged for common shares in connection with this offering. The number of shares and value realized in the table assume solely for this purpose that this exchange had occurred as of the vesting date of the interests (based on an assumed initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price on the cover page of this prospectus).

	 	Option Awards	 	Stock Awards	 	
Name	 	Number of Shares
Acquired on Exercise
(#)	 	Value Realized
on Exercise
($)	 	Number of Shares
Acquired on Vesting
(#)	 	Value Realized
on Vesting
($)	 	
James C. Musselman	 	 	—	 	 	—	 	 	4,220,193	 	 	71,743,283	 	
W. Greg Dunlevy	 	 	—	 	 	—	 	 	690,365	 	 	11,736,200	 	
Brian F. Maxted	 	 	—	 	 	—	 	 	1,036,545	 	 	17,604,272	 	
William S. Hayes	 	 	—	 	 	—	 	 	86,474	 	 	1,470,056	 	
Dennis C. McLaughlin	 	 	—	 	 	—	 	 	140,060	 	 	2,381,010	 	
136

Table of Contents

Pension Benefits

        We do not maintain any defined benefit pension plans.

Nonqualified Deferred Compensation

        We do not maintain any nonqualified deferred compensation plans.

Potential Payments Upon Termination or Change in Control

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

Messrs. Dunlevy, Maxted, Hayes and McLaughlin

        Each of Messrs. Dunlevy, Maxted, Hayes and McLaughlin holds profit units in Kosmos Energy Holdings that were unvested as of December 31, 2010 (see "—Outstanding Equity Awards at Fiscal Year End"). Under Kosmos Energy Holdings' current operating agreement, these profit units would have become fully vested on December 31, 2010 if on such date the executives' employment had terminated due to their death or "disability" (as defined below) or had we undergone a "change in control" (as defined below). The estimated aggregate values of these units (based on an assumed initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price on the cover page of this prospectus) are as follows: Mr. Dunlevy ($21,376,115), Mr. Maxted ($32,064,133), Mr. Hayes ($8,849,041) and Mr. McLaughlin ($8,362,468).

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

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

        "Change in control" generally means:

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

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

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

Mr. Musselman

        On December 17, 2010, we entered into a retirement agreement with our then chief executive officer Mr. Musselman, which sets forth the terms of his retirement from his employment with Kosmos effective as of December 31, 2010. Pursuant to the retirement agreement, in consideration of

137

Table of Contents

Mr. Musselman's release of claims against us and our affiliates and his agreement to the restrictions described below, we provided him with the following payments and benefits:

•
Severance in an aggregate amount equal to his annual base salary of $593,000, paid in monthly installments through December 31, 2011. However, these payments will cease on the completion of the lock-up period under agreements to be entered into with the underwriters of this offering (but in no event earlier than March 31, 2011);

•
1,176,961 profit units in Kosmos Energy Holdings that were unvested as of his retirement date became fully vested as of such date. The estimated aggregate value of such interests is $46,314,878 (based on an assumed initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price on the cover page of this prospectus);

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

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

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

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

Employment Agreements

        We anticipate entering into an employment agreement with each of our named executive officers (other than Mr. Musselman, who retired from his employment with Kosmos effective December 31, 2010). The following is a summary of the material terms of these agreements.

        Terms.    The employment agreements will become effective immediately prior to the closing of this offering and will remain in effect for two years, in the case of Mr. Maxted, and one year, in the case of each of Messrs. Dunlevy, Hayes and McLaughlin. The term of each agreement will automatically extend for successive one-year periods unless either we or the executive provides the other with at least six months' written notice to the contrary.

        Positions.    The employment agreements set forth the executives' positions as follows: Mr. Maxted (Chief Executive Officer), Mr. Dunlevy (Executive Vice President and Chief Financial Officer), Mr. Hayes (Senior Vice President and General Counsel) and Mr. McLaughlin (Senior Vice President, Development).

        Base Salaries and Annual Bonuses.    The agreements provide for initial base salaries in the following amounts: Mr. Maxted ($600,000), Mr. Dunlevy ($450,000), Mr. Hayes ($350,000) and Mr. McLaughlin ($350,000). The salaries may be increased at the discretion of our board of directors. Each executive is eligible to receive an annual bonus based on the attainment of performance criteria determined by our board of directors or a board committee. Each agreement specifies a target annual bonus, which is expressed as a percentage of base salary, as follows: Mr. Maxted (150%), Mr. Dunlevy (100%), Mr. Hayes (75%) and Mr. McLaughlin (75%).

138

Table of Contents

        Benefits.    Each agreement provides that the executive is entitled to participate in our benefit plans and programs and to sick leave and paid vacation on the same terms as apply to our senior executives. In addition, each executive is entitled to club dues, financial planning and an executive health program.

        Death or Disability.    If the executive's employment terminates due to his death or "disability" (as defined in the agreement), he will be entitled to a pro rata portion of the annual bonus, if any, that he would have received for the year of termination, based on actual performance through the end of the year.

        Termination by Us without Cause or by the Executive for Good Reason.    If the executive's employment is terminated by us without "cause" or by the executive for "good reason" (as such terms are defined below), subject to his execution of a release in our favor, he will be entitled to the following payments and benefits:

•
a lump sum cash payment in an amount equal to the sum of his base salary and target bonus, and, for Messrs. Maxted and Dunlevy, if such termination occurs on or within two years after a "change in control" (as defined below), the lump sum cash payment will equal two times the sum of his base salary and target bonus;

•
a pro rata portion of the annual bonus, if any, that he would have received for the year of termination, based on actual performance through the end of the year; and

•
continued coverage under our group health plans at a cost to the executive that does not exceed the amount, if any, that we charge active senior executives for similar coverage until the earlier of 18 months after such termination or December 31 of the year after such termination. If such coverage ends before the expiration of the 18 month period, then, for the balance of the 18 month period, the executive will receive a cash payment equal to the company's portion of such coverage for active senior executives.

        The employment agreements generally define "cause" to mean the executive's:

•
willful failure to substantially perform his duties;

•
having engaged in willful misconduct, gross negligence, a breach of fiduciary duty or willful breach of his employment agreement that results in demonstrable harm to us;

•
conviction of a felony under U.S. law or a crime of similar import in a foreign jurisdiction;

•
breach of any of the restrictive covenants in the employment agreement, other than any such breach that causes no demonstrable or non-trivial damage to us;

•
material breach of any company policy, including any such policy that relates to expense management, human resources or the Foreign Corrupt Practices Act;

•
unlawful use or possession of illegal drugs on our premises or while performing his duties; or

•
commission of an act of fraud, embezzlement or misappropriation against us.

In each case other than for conviction, use or possession of illegal drugs or commission of fraud, embezzlement or misappropriation, we are required to provide the executive with written notice specifying the circumstances alleged to constitute cause, and, if possible, the executive will have 30 days to cure such circumstances.

        The employment agreements generally define "good reason" to mean:

•
a reduction in the executive's base salary or target bonus, other than any such reduction that applies generally to similarly situated employees;

139

Table of Contents

•
relocation of the geographic location of the executive's principal place of employment by more than 50 miles from Dallas, Texas;

•
the expiration of the term of the agreement after our election not to extend the term; or

•
a material reduction in the executive's duties or responsibilities that occurs within two years after a change in control.

In each case, the executive must provide us with written notice specifying the circumstances alleged to constitute good reason within 90 days after the first occurrence of such circumstances, and we will have 30 days to cure such circumstances. If we fail to cure such circumstances within 30 days, then the executive must terminate his employment not later than 60 days after the end of such 30-day period.

        Restrictive Covenants.    Each employment agreement prohibits the executive from competing with us or soliciting our employees, consultants, customers, suppliers, licensees and other business relations during his employment and for one year thereafter. Each agreement also contains perpetual restrictions on disclosing our confidential and proprietary information, a covenant regarding assignment of inventions and a mutual non-disparagement provision.

Long Term Incentive Plan and Awards

        We have adopted the Kosmos Energy Ltd. Long Term Incentive Plan, or LTIP, which permits us to grant an array of equity-based and cash incentive awards to our named executive officers and other employees and service providers. On the closing of this offering, we intend to issue restricted stock awards under the LTIP in exchange for unvested profit units in Kosmos Energy Holdings held by our named executive officers (other than Mr. Musselman, who retired effective December 31, 2010) and other employees. We also intend to issue additional equity awards to these named executive officers and to other employees on the closing of this offering. The following is a summary of the material terms of the LTIP and these awards.

Long Term Incentive Plan

        Purpose.    The purpose of the LTIP is to motivate and reward those employees and other individuals who are expected to contribute significantly to our success to perform at the highest level and to further our best interests and those of our shareholders.

        Eligibility.    Our employees, consultants, advisors, other service providers and non-employee directors are eligible to receive awards under the LTIP.

        Authorized Shares.    Subject to adjustment as described below, 24,503,000 shares of our common stock will be available for awards to be granted under the LTIP. Other than during the current calendar year, no participant may receive under the plan in any calendar year more than 2,450,300 shares in respect of each of the following three categories of awards: stock options and stock appreciation rights; restricted stock, restricted stock units and other stock-based awards; and performance awards. Shares underlying replacement awards (i.e., awards granted as replacements for awards granted by a company that we acquire or with which we combine) and awards that we grant on the closing of this offering will not reduce the number of shares available for issuance under the plan. If an award (other than a replacement award or an award granted on the closing of this offering) expires or is canceled or forfeited, the shares covered by the award again will be available for issuance under the plan. Shares tendered or withheld in payment of an exercise price or for withholding taxes also again will be available for issuance under the plan.

        Administration.    Our compensation committee administers the LTIP and has authority to:

•
designate participants;

140

Table of Contents

•
determine the types of awards to grant, the number of shares to be covered by awards, the terms and conditions of awards, whether awards may be settled or exercised in cash, shares, other awards, other property or net settlement, the circumstances under which awards may be canceled, repurchased, forfeited or suspended, and whether awards may be deferred automatically or at the election of the holder or the committee;

•
interpret and administer the plan and any instrument or agreement relating to, or award made under, the plan;

•
establish, amend, suspend or waive rules and regulations and appoint agents; and

•
make any other determination and take any other action that it deems necessary or desirable to administer the plan.

        Types of Awards.    The LTIP provides for grants of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units (RSUs), performance awards and other stock-based awards.

•
Stock Options.  A stock option is a contractual right to purchase shares at a future date at a specified exercise price. The per share exercise price of a stock option (other than a replacement award) will be determined by our compensation committee and may not be less than the closing price of a share of our common stock on the grant date. The committee will determine the date after which each stock option may be exercised and the expiration date of each option, provided that no option will be exercisable more than ten years after the grant date. Options that are intended to qualify as incentive stock options must meet the requirements of Section 422 of the Internal Revenue Code.

•
SARs.  SARs represent a contractual right to receive, in cash or shares, an amount equal to the appreciation of one share of our common stock from the grant date. Any SAR will be granted subject to the same terms and conditions as apply to stock options.

•
Restricted Stock.  Restricted stock is an award of shares of our common stock that are subject to restrictions on transfer and a substantial risk of forfeiture.

•
RSUs.  RSUs represent a contractual right to receive the value of a share of our common stock at a future date, subject to specified vesting and other restrictions.

•
Performance Awards.  Performance awards, which may be denominated in cash or shares, will be earned on the satisfaction of performance conditions specified by our compensation committee. The committee has authority to specify that any other award granted under the LTIP will constitute a performance award by conditioning the exercisability or settlement of the award on the satisfaction of performance conditions. The performance conditions for awards that are intended to qualify as "performance-based compensation" for purposes of Section 162(m) of the Internal Revenue Code will be limited to the following: captured prospects, prospecting licenses signed, operated prospects matured to drill ready, drilling programs commenced, drillable prospects, capabilities and critical path items established, operating budget, third-party capital sourcing, captured net risked resource potential, acquisition cost efficiency, acquisitions of oil and gas interests, increases in proved, probable or possible reserves, finding and development costs, recordable or lost time incident rates, overhead costs, general and administration expense, market price of a share of our common stock, cash flow, reserve value, net asset value, earnings, net income, operating income, cash from operations, revenue, margin, EBITDA (earnings before interest, taxes, depreciation and amortization), EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration expense), net capital employed, return on assets, shareholder return, reserve replacement, return on equity, return on capital employed, production, assets, unit volume, sales, market share, or strategic business criteria consisting of one or more objectives based on meeting specified goals relating to acquisitions or divestitures,

141

Table of Contents

each as determined in accordance with generally accepted accounting principles, where applicable, as consistently applied by us. These performance criteria may be measured on an absolute (e.g., plan or budget) or relative basis. Relative performance may be measured against a group of peer companies, a financial market index or other acceptable objective and quantifiable indices.•
Other Stock-Based Awards.  Our compensation committee is authorized to grant other stock-based awards, which may be denominated in shares of our common stock or factors that may influence the value of our shares, including convertible or exchangeable debt securities, other rights convertible or exchangeable into shares, purchase rights for shares, awards with value and payment contingent on our performance or that of our business units or any other factors that the committee designates.

        Adjustments.    In the event that, as a result of any dividend or other distribution, recapitalization, stock split, reverse stock split, reorganization, merger, amalgamation, consolidation, split-up, spin-off, combination, repurchase or exchange of shares of our common stock or other securities, issuance of warrants or other rights to purchase our shares or other securities, issuance of our shares pursuant to the anti-dilution provisions of our securities, or other similar corporate transaction or event affecting our shares, an adjustment is appropriate to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the LTIP, the compensation committee will adjust equitably any or all of:

•
the number and type of shares or other securities that thereafter may be made the subject of awards, including the aggregate and individual limits under the plan;

•
the number and type of shares or other securities subject to outstanding awards; and

•
the grant, purchase, exercise or hurdle price for any award or, if deemed appropriate, make provision for a cash payment to the holder of an outstanding award.

        Termination of Service and Change in Control.    Our compensation committee will determine the effect of a termination of employment or service on outstanding awards, including whether the awards will vest, become exercisable, settle or be forfeited (including by way of repurchase by the company at par value). The committee may set forth in the applicable award agreement the treatment of an award on a change in control. In addition, in the case of a stock option or SAR, except as otherwise provided in the applicable award agreement, on a change in control, a merger or consolidation involving us or any other event for which the committee deems it appropriate, the committee may cancel the award in consideration of:

•
a substitute award that preserves the intrinsic value of the canceled award; or

•
the full acceleration of the award and either:

•
a period of ten days to exercise the award; or

•
a payment in cash or other consideration in an amount equal to the intrinsic value of the canceled award.

        The LTIP generally defines a "change in control" to mean the occurrence any one or more of the following events:

•
the acquisition (other than by our Investors) of 50% or more of the combined voting power of our outstanding securities (other than by any company owned, directly or indirectly, by our shareholders in substantially the same proportions as their ownership of our common stock);

•
the replacement of the majority of our directors during any 12-month period (other than by directors approved by a majority of our remaining directors);

142

Table of Contents

•
the consummation of our merger or consolidation with another entity (unless our voting securities outstanding immediately prior to such transaction continue to represent more than 50% of the combined voting power of the surviving or resulting entity outstanding immediately after such transaction); or

•
the consummation of a transaction (or series of transactions within a 12-month period) that constitutes the sale or disposition of all or substantially all of our consolidated assets having a gross fair market value of 50% or more of the total gross fair market value of all of our consolidated assets (other than any such transaction immediately after which such assets will be owned directly or indirectly by our shareholders in substantially the same proportions as their ownership of our common stock immediately prior to such transaction), and the subsequent distribution of proceeds from such transaction (or series of transactions) to our shareholders having a fair market value that is greater than 50% of our fair market value immediately prior to such transaction (or series of transactions).

        Amendment and Termination.    Our board of directors may amend, alter, suspend, discontinue or terminate the LTIP, subject to approval of our shareholders if required by the rules of the stock exchange on which our shares are principally traded. Our compensation committee may amend, alter, suspend, discontinue or terminate any outstanding award. However, no such board or committee action that would materially adversely affect the rights of a holder of an outstanding award may be taken without the holder's consent, except to the extent that such action is taken to cause the LTIP to comply with applicable law, stock market or exchange rules and regulations or accounting or tax rules and regulations. In addition, the committee may amend the LTIP in such manner as may be necessary to enable the plan to achieve its stated purposes in any jurisdiction in a tax efficient manner and in compliance with local rules and regulations.

        Term.    The LTIP expires after ten years, unless prior to that date the maximum number of shares available for issuance under the plan has been issued or our board of directors terminates the plan.

Awards under the LTIP

        Unvested profit units in Kosmos Energy Holdings held by our employees, including our named executive officers (other than Mr. Musselman, as his unvested units became fully vested on his retirement effective December 31, 2010) will be exchanged in connection with this offering for an aggregate of 9,507,336 restricted shares of our common stock. In addition, on or shortly after the closing of this offering, we intend to grant to our named executive officers (other than Mr. Musselman) and other employees restricted shares in respect of an aggregate of approximately 14,080,000 shares of our common stock. These restricted shares will be governed by the LTIP and individual award agreements.

        The following table sets forth the number of restricted shares that each of our named executive officers (other than Mr. Musselman) is anticipated to hold on or shortly after the closing of this offering. Additional information about these awards follows the table.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Name	 	Restricted
Shares
(Exchange)
(#)	 	Restricted
Shares
(Service)
(#)	 	Restricted
Shares
(Performance)
(#)	 	Total
(#)	 	
Brian F. Maxted	 	 	1,886,125	 	 	2,588,235	 	 	647,059	 	 	5,121,419	 	
W. Greg Dunlevy	 	 	1,257,419	 	 	1,552,941	 	 	388,235	 	 	3,198,595	 	
William S. Hayes	 	 	520,532	 	 	705,882	 	 	176,471	 	 	1,402,885	 	
Dennis C. McLaughlin	 	 	491,910	 	 	470,588	 	 	117,647	 	 	1,080,145	 	
143

Table of Contents

        The share numbers set forth above are calculated based on an assumed initial public offering price of $17.00 per common share, the midpoint of the estimated public offering price on the cover page of this prospectus.

        Each of Messrs. Maxted, Dunlevy, Hayes and McLaughlin will receive the restricted shares of our common stock in exchange for his unvested profit units and service-vesting restricted shares in connection with this offering. The restricted shares received in exchange for unvested profit units will be scheduled to vest on the same dates as his profit units were scheduled to vest, subject generally to his continued employment through each vesting date. The profit units granted to Messrs. Maxted and Dunlevy were granted 20% vested, with an additional 20% scheduled to vest on each of the first four anniversaries of the grant date. The profit units granted to Messrs. Hayes and McLaughlin are scheduled to vest 50% on each of the second and fourth anniversaries of the grant date. For additional information on these profit units, see "Grants of Plan-Based Awards" and "Outstanding Equity Awards at Fiscal Year-End".

        The executives are expected to receive additional service-vesting restricted shares on the closing of this offering that will be scheduled to vest 25% on each of the first four anniversaries of the grant date. Vesting of both the restricted shares received in exchange for the executives' unvested profit units and the additional service-vesting restricted shares will fully accelerate if the executive's employment is terminated due to his death or "disability," by us without "cause" or by him for "good reason" (as such terms are defined in his employment agreement). In addition, if we undergo a change in control, the shares will vest on the first anniversary of the change in control (or, if earlier, the regularly scheduled vesting date or on termination of the executive's employment by us or the acquiror without cause or by the executive for good reason). If the executive's employment is terminated by us for cause or by him without good reason at any time, he will forfeit any then unvested shares (or, in the committee's sole discretion, if required pursuant to applicable law to effect such forfeiture, the company may repurchase such shares at their par value).

        Each of Messrs. Maxted, Dunlevy, Hayes and McLaughlin also are expected to receive restricted shares on or shortly following the closing of this offering that will be subject to both service and performance conditions. On each of the first four anniversaries of the grant date, 25% of the service condition applicable to these restricted shares will be deemed met, subject generally to the executive's continued employment through each anniversary date. The performance condition will be determined prior to grant of these restricted shares.

        On termination of the executive's employment due to his death or disability, by us without cause or by him for good reason, the service condition will be deemed met, and the restricted shares will remain subject to the performance condition to the extent not yet met. If the executive terminates his employment without good reason, any restricted shares for which the service condition has been met will remain subject to the performance condition to the extent not yet met, and any restricted shares for which the service condition has not been met will be forfeited (or, in the committee's sole discretion, if required pursuant to applicable law to effect such forfeiture, such shares may be repurchased at their par value). If we undergo a change in control, the performance condition will be deemed met, and the service condition, to the extent not met as of the change in control, will be deemed met on the first anniversary of the change in control (or, if earlier, the regularly scheduled vesting date or on termination of the executive's employment by us or the acquiror without cause or by the executive for good reason). If the executive terminates his employment without good reason, any restricted shares for which the service condition is met will remain subject to the performance condition, and any restricted shares for which the service condition is not met will be forfeited (or, in the committee's sole discretion, if required pursuant to applicable law to effect such forfeiture, such shares may be repurchased at their par value). If the executive's employment is terminated by us for cause, he will forfeit any restricted shares for which either the service or performance condition is not

144

Table of Contents

met (or, in the committee's sole discretion, if required pursuant to applicable law to effect such forfeiture, such shares may be repurchased at their par value).

        On vesting of any of these restricted shares, the restrictions will lapse and, subject to the restrictions on transfer that apply to our officers and directors and certain of our shareholders (see "Underwriting") and any additional restrictions under any applicable lock up agreement, the shares will be fully transferable. Prior to vesting, the executives will have the right to vote the restricted shares and to receive current payment in respect of dividends paid on shares of our common stock.

Annual Incentive Plan

        We have adopted the Kosmos Energy Ltd. Annual Incentive Plan, under which our named executive officers and other employees are eligible for annual cash bonuses. The following is a summary of the material terms of the plan.

        Purpose.    The Annual Incentive Plan is designed to incentivize our executives and other employees to attain annual performance objectives, thereby furthering our best interests and those of our shareholders.

        Eligibility.    Each of our employees is eligible to receive an annual cash bonus under the plan for each fiscal year. Each employee who is employed for less than a full fiscal year will be eligible for a pro rata bonus for the year.

        Executive and Senior Manager Bonuses.    For each fiscal year, our compensation committee will:

•
identify each executive and senior manager who is eligible for an annual cash bonus under the plan;

•
establish objective criteria for determining the bonus payable to each executive and senior manager based on his or her base salary, a specified target bonus percentage, specified key performance indicators, individual performance goals and/or any other objective criteria that the committee deems appropriate, including, without limitation, performance goals based on the performance measures enumerated in our LTIP and summarized above (see "—Long Term Incentive Plan"); and

•
approve the actual amount of the bonus payable to each executive and senior manager based on the attainment of the applicable objective criteria, which amount the committee may increase or decrease based on such subjective criteria as the committee deems appropriate, including without limitation, such executive's or senior manager's individual performance.

        Staff Bonuses.    For each fiscal year, the committee will approve a bonus pool for employees who are not executives or senior managers. The amount of the bonus pool will be based on the employees' base salaries, specified target bonus percentages, specified key performance indicators, individual performance goals and/or any other objective criteria that the committee deems appropriate, including, without limitation, performance goals based on the performance measures enumerated in our LTIP and summarized above (see "—Long Term Incentive Plan"). Our chief executive officer will recommend for the committee's approval the actual amount of each employee's bonus, based on the attainment of the applicable objective criteria and any subjective criteria as the chief executive officer deems appropriate, including, without limitation, such employee's individual performance. The aggregate amount of the employees' bonuses for a fiscal year may not exceed the amount of the bonus pool approved by the committee for the year.

        Maximum Annual Bonus.    The annual cash bonus paid under the plan to any eligible employee for a single fiscal year shall not exceed $10 million.

        Amendment and Termination.    The committee may amend or terminate the plan at any time.

145

Table of Contents

2010 Director Compensation

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

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

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

Consulting Agreement with Mr. Kemp

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

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

Restricted Stock Award to Mr. Tong

        In February 2011, we appointed Chris Tong to our board of directors. Mr. Tong also serves as the Chairman of our audit committee. As compensation for his service as a director and Chairman of our audit committee, on April 11, 2011, our compensation committee approved the grant to Mr. Tong of an award of 6,000 restricted shares. These restricted shares will be granted under the LTIP on or shortly after the closing of this offering and will be subject to the same four-year vesting schedule and

146

Table of Contents

accelerated vesting provisions as are described above for the service-vesting restricted stock awards that we intend to grant to Messrs. Maxted, Dunlevy, Hayes and McLaughlin (see "—Long Term Incentive Plan and Awards-Awards under the LTIP"). In addition, on or shortly after the closing of this offering, we intend to grant to Mr. Tong an award of 7,353 restricted shares. These restricted shares will also be granted under the LTIP and will be subject to a one-year vesting schedule.

147

Table of Contents
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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

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

        Pursuant to the terms of the corporate reorganization that will occur prior to or concurrently with the closing of the offering described in this prospectus, all of the interests in Kosmos Energy Holdings will be exchanged for common shares of Kosmos Energy Ltd., and the OA will be terminated and a new memorandum of association and articles of association will be put in place for Kosmos Energy Holdings. See "Corporate Reorganization." We have agreed to reimburse our Investors for their fees and expenses incurred in connection with this offering and the related corporate reorganization.

        We have entered into customary indemnification agreements with our directors. In addition, prior to the completion of this offering, we will become a party to the existing registration rights agreement by and among Kosmos Energy Holdings and its unitholders pursuant to which we will grant certain registration rights to the unitholders with respect to the common shares they will receive in the corporate reorganization. See "Shares Eligible for Future Sale—Registration Rights." Also prior to the completion of this offering, we will enter into a shareholders agreement with affiliates of the Investors. See "Management—Shareholders Agreement."

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

148

Table of Contents
PRINCIPAL SHAREHOLDERS

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

•
each of our current executive officers;

•
each of our current directors;

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

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

        Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Common shares that may be acquired by an individual or group within 60 days of December 31, 2010, pursuant to the exercise of options or warrants, are deemed to be outstanding for the purpose of computing the percentage ownership of such individual or group, but are not deemed to be outstanding for the purpose of computing the percentage ownership of any other person shown in the table. Percentage of ownership is based on 341,176,471 common shares issued and outstanding on December 31, 2010, after giving effect to our corporate reorganization, plus 30,000,000 common shares that we are selling in this offering. The underwriters have an option to purchase up to 4,500,000 additional common shares from us to cover over-allotments.

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

149

Table of Contents

	 	 
	 	Percentage of Shares
Beneficially Owned(1)(2)	 	
Name and Address of Beneficial Owner	 	Number of Shares
Beneficially
Owned(1)	 	Before the Offering	 	After the Offering	 	
Directors and Executive Officers	 	 	 	 	 	 	 	 	 	 	
John R. Kemp III	 	 	732,933	 	 	0.21	%	 	0.20	%	
David I. Foley(4)	 	 	—	 	 	—	 	 	—	 	
Jeffrey A. Harris(3)	 	 	—	 	 	—	 	 	—	 	
David Krieger(3)	 	 	—	 	 	—	 	 	—	 	
Prakash A. Melwani(4)	 	 	—	 	 	—	 	 	—	 	
Adebayo O. Ogunlesi	 	 	1,373,312	 	 	0.40	%	 	0.37	%	
Chris Tong	 	 	—	 	 	—	 	 	—	 	
Christopher A. Wright	 	 	662,545	 	 	0.19	%	 	0.18	%	
Brian F. Maxted(5)	 	 	10,657,197	 	 	3.12	%	 	2.87	%	
W. Greg Dunlevy(6)	 	 	7,237,972	 	 	2.12	%	 	1.95	%	
William S. Hayes(7)	 	 	805,192	 	 	0.24	%	 	0.22	%	
Dennis C. McLaughlin(8)	 	 	691,729	 	 	0.20	%	 	0.19	%	
All directors and executive officers as a group (12 individuals)	 	 	22,160,880	 	 	6.50	%	 	5.97	%	
Five Percent Shareholders	 	 	 	 	 	 	 	 	 	 	
Warburg Pincus Funds(3)	 	 	155,099,918	 	 	45.46	%	 	41.79	%	
Blackstone Funds(4)	 	 	126,899,910	 	 	37.19	%	 	34.19	%	

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

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

(3)
The Warburg Pincus Funds are comprised of the following entities: Warburg Pincus International Partners, L.P., a Delaware limited partnership, together with two affiliated partnerships ("WPIP") who collectively hold 77,549,959 shares, and Warburg Pincus Private Equity VIII, L.P., a Delaware limited partnership, together with two affiliated partnerships ("WP VIII") who collectively hold 77,549,959 shares. Warburg Pincus Partners, LLC, a New York limited liability company ("WP Partners"), and direct subsidiary of Warburg Pincus & Co., a New York general partnership ("WP"), is the sole general partner of WPIP and WP VIII. WP is the managing member of WP Partners. WPIP and WP VIII are managed by Warburg Pincus LLC, a New York limited liability company ("WP LLC"). Messrs. Harris and Krieger, directors of Kosmos Energy Ltd., are Partners of WP and Managing Directors and Members of WP LLC. All shares indicated as owned by Messrs. Harris and Krieger are included because of their affiliation with the Warburg Pincus entities. Messrs. Harris and Krieger disclaim beneficial ownership of all shares owned by the Warburg Pincus entities. Charles R. Kaye and Joseph P. Landy are Managing General Partners of WP and Managing Members and Co-Presidents of WP LLC and may be deemed to control the Warburg Pincus entities. Messrs. Kaye and Landy disclaim beneficial ownership of all shares held by the Warburg Pincus entities. The address of Messrs. Harris, Krieger, Kaye and Landy, WP VIII, WPIP, WP Partners, WP, WP LLC is 450 Lexington Avenue, New York, New York 10017.

(4)
The Blackstone Funds (as hereinafter defined) are comprised of the following entities: Blackstone Capital Partners (Cayman) IV L.P. ("BCP IV"), Blackstone Capital Partners (Cayman) IV-A L.P. ("BCP IV-A"), Blackstone Family Investment Partnership (Cayman) IV-A L.P ("Family"), Blackstone Participation Partnership (Cayman) IV L.P. ("Participation") and Blackstone Family Investment Partnership (Cayman) IV-A SMD L.P. ("Family SMD", and together with BCP IV,

150

Table of Contents

BCP IV-A, Family and Participation, the "Blackstone Funds"). The Blackstone Funds beneficially own (i) 118,867,656 shares, which are held by BCP IV, (ii) 1,938,499 shares, which are held by BCP IV-A, (iii) 3,136,210 shares, which are held by Family, (iv) 353,568 shares, which are held by Participation, and (v) 2,603,976 shares, which are held by Family SMD. Blackstone Management Associates (Cayman) IV L.P. ("BMA") is a general partner of each of BCP IV and BCP IV-A. Blackstone LR Associates (Cayman) IV Ltd. ("BLRA") and BCP IV GP L.L.C. are general partners of each of BMA, Family and Participation. Blackstone Holdings III L.P. is the sole member of BCP IV GP L.L.C. and a shareholder of BLRA. Blackstone Holdings III L.P. is indirectly controlled by The Blackstone Group L.P. and is owned, directly or indirectly, by Blackstone professionals and The Blackstone Group L.P. The Blackstone Group L.P. is controlled by its general partner, Blackstone Group Management L.L.C., which is in turn, wholly owned by Blackstone's senior managing directors and controlled by its founder, Stephen A. Schwarzman. In addition, Mr. Schwarzman is a director and controlling person of BLRA. Family SMD is controlled by its general partner, Blackstone Family GP L.L.C., which is in turn wholly owned by Blackstone's senior managing directors and controlled by its founder, Mr. Schwarzman. Each of such Blackstone entities and Mr. Schwarzman may be deemed to beneficially own the shares beneficially owned by the Blackstone Funds directly or indirectly controlled by it or him, but each disclaims beneficial ownership of such shares except to the extent of its or his indirect pecuniary interest therein. Mr. Foley and Mr. Melwani are senior managing directors of Blackstone Group Management L.L.C. and neither is deemed to beneficially own the shares beneficially owned by the Blackstone Funds. The address of each of the Blackstone Funds, BMA and BLRA is c/o Walkers Corporate Services Limited, 87 Mary Street, George Town, Grand Cayman KY1-9005, Cayman Islands and the address for Mr. Schwarzman and each of the other entities listed in this footnote is c/o The Blackstone Group, L.P., 345 Park Avenue, New York, New York 10154.(5)
Includes 1,391,447 restricted shares issued to Mr. Maxted in connection with our corporate reorganization but excludes 3,235,294 restricted shares intended to be issued to Mr. Maxted on or shortly after the closing of this offering pursuant to our LTIP. Also includes 494,678 restricted shares and 2,920,299 common shares issued to Maxted Family Investments, Ltd., an entity which Mr. Maxted is a beneficial owner of, in connection with our corporate reorganization.

(6)
Includes 593,924 restricted shares issued to Mr. Dunlevy in connection with our corporate reorganization but excludes 1,941,176 restricted shares intended to be issued to Mr. Dunlevy on or shortly after the closing of this offering pursuant to our LTIP. Also includes 663,493 restricted shares and 1,092,140 common shares issued to 2008 Carnegie, Ltd., an entity which Mr. Dunlevy is a beneficial owner of, in connection with our corporate reorganization.

(7)
Includes 520,531 restricted shares issued to Mr. Hayes in connection with our corporate reorganization but excludes 882,353 restricted shares intended to be issued to Mr. Hayes on or shortly after the closing of this offering pursuant to our LTIP.

(8)
Includes 491,910 restricted shares issued to Mr. McLaughlin in connection with our corporate reorganization but excludes 588,235 restricted shares intended to be issued to Mr. McLaughlin on or shortly after the closing of this offering pursuant to our LTIP.

151

Table of Contents
DESCRIPTION OF SHARE CAPITAL

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

General

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

Share Capital

        Our authorized share capital consists of 2,000,000,000 common shares, par value $0.01 per share, and 200,000,000 preference shares, par value $0.01 per share. Upon completion of this offering, there will be 371,176,471 common shares and no preference shares issued and outstanding. All of our issued and outstanding common shares will be fully paid and non-assessable.

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

Common Shares

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

Preference Shares

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

Board Composition

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

152

Table of Contents

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

Election and Removal of Directors

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

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

Proceedings of Board of Directors

        Our bye-laws provide that our business shall be managed by or under the direction of our board of directors. Our board of directors may act by the affirmative vote of a majority of the directors present at a meeting at which a quorum is present. A majority of the total number of directors then in office shall constitute a quorum; provided that, in the case of special meetings, for as long as the Investors collectively beneficially own more than 25% of the issued and outstanding common shares, if at least one director designated by each Investor then entitled to designate a director is not present at a special meeting, such meeting will be postponed for at least 24 hours, after which it may be held as long as a quorum consisting of a majority of the total number of directors is present. The board may also act by unanimous written consent.

Duties of Directors

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

153

Table of Contents

faith, with a view to the best interests of the company, and to exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. In addition, the Bermuda Companies Act imposes various duties on directors with respect to certain matters of management and administration of the company.

        The Bermuda Companies Act provides that in any proceedings for negligence, default, breach of duty or breach of trust against any director, if it appears to a court that such officer is or may be liable in respect of the negligence, default, breach of duty or breach of trust, but that he has acted honestly and reasonably, and that, having regard to all the circumstances of the case, including those connected with his appointment, he ought fairly to be excused for the negligence, default, breach of duty or breach of trust, that court may relieve him, either wholly or partly, from any liability on such terms as the court may think fit. This provision has been interpreted to apply only to actions brought by or on behalf of the company against the directors.

        Under Delaware law, the business and affairs of a corporation are managed by or under the direction of its board of directors. In exercising their powers, directors are charged with a duty of care and a duty of loyalty. The duty of care requires that directors act in an informed and deliberate manner and to inform themselves, prior to making a business decision, of all relevant material information reasonably available to them. The duty of care also requires that directors exercise care in overseeing the conduct of corporate employees. The duty of loyalty is the duty to act in good faith, not out of self-interest, and in a manner which the director reasonably believes to be in the best interests of the shareholders. A party challenging the propriety of a decision of a board of directors bears the burden of rebutting the presumptions afforded to directors by the "business judgment rule." If the presumption is not rebutted, the business judgment rule attaches to protect the directors and their decisions. Where, however, the presumption is rebutted, the directors bear the burden of demonstrating the fairness of the relevant transaction. Notwithstanding the foregoing, Delaware courts subject directors' conduct to enhanced scrutiny in respect of defensive actions taken in response to a threat to corporate control and approval of a transaction resulting in a sale of control of the corporation.

Interested Directors

        Under Bermuda law and our bye-laws, as long as a director discloses a direct or indirect interest in any contract or arrangement with us as required by law, such director is entitled to vote in respect of any such contract or arrangement in which he or she is interested, unless disqualified from doing so by the chairman of the meeting, and such a contract or arrangement will not be voidable solely as a result of the interested director's participation in its approval. In addition, the director will not be liable to us for any profit realized from the transaction. In contrast, under Delaware law, such a contract or arrangement is voidable unless it is approved by a majority of disinterested directors or by a vote of shareholders, in each case if the material facts as to the interested director's relationship or interests are disclosed or are known to the disinterested directors or shareholders, or such contract or arrangement is fair to the corporation as of the time it is approved or ratified. Additionally, such interested director could be held liable for a transaction in which such director derived an improper personal benefit.

Indemnification of Directors and Officers

        Bermuda law provides generally that a Bermuda company may indemnify its directors and officers against any loss arising from or liability which by virtue of any rule of law would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust except in cases where such liability arises from fraud or dishonesty of which such director or officer may be guilty in relation to the company.

154

Table of Contents

        Our bye-laws provide that we shall indemnify our officers and directors in respect of their actions and omissions, except in respect of their fraud or dishonesty, and that we shall advance funds to our officers and directors for expenses incurred in their defense upon receipt of an undertaking to repay the funds if any allegation of fraud or dishonesty is proved. Our bye-laws provide that the company and the shareholders waive all claims or rights of action that they might have, individually or in right of the company, against any of the company's directors or officers for any act or failure to act in the performance of such director's or officer's duties, except in respect of any fraud or dishonesty.

Meetings of Shareholders

        Under Bermuda law, a company is required to convene at least one general meeting of shareholders each calendar year. Under Bermuda law and our bye-laws, a special general meeting of shareholders may be called by the board of directors or the chairman and must be called upon the request of shareholders holding not less than 10% of the paid-up capital of the company carrying the right to vote at general meetings of shareholders.

        Unless otherwise provided in our bye-laws, at any general meeting of shareholders the presence in person or by proxy of shareholders representing a majority of the issued and outstanding shares entitled to vote shall constitute a quorum for the transaction of business. Unless otherwise required by law or our bye-laws, shareholder action requires the affirmative vote of a majority of the issued and outstanding shares voting at a meeting at which a quorum is present.

Shareholder Proposals

        Under Bermuda law, shareholders holding at least 5% of the total voting rights of all the shareholders having at the date of the requisition a right to vote at the meeting to which the requisition relates or any group comprised of at least 100 or more shareholders may require a proposal to be submitted to an annual general meeting of shareholders. Under our bye-laws, any shareholders wishing to nominate a person for election as a director or propose business to be transacted at a meeting of shareholders must provide advance notice.

Shareholder Action by Written Consent

        Our bye-laws will provide that, until the first date on which the Investors no longer beneficially own more than 50% of the issued and outstanding shares entitled to vote, shareholders can act by written consent. Thereafter, shareholders can only act at a meeting of shareholders.

Amendment of Memorandum of Association and Bye-laws

        Our memorandum of association and bye-laws provide that our memorandum of association and bye-laws may not be rescinded, altered or amended except with the approval of our board of directors and shareholders owning a majority of the issued and outstanding shares entitled to vote.

Business Combinations

        A Bermuda company may engage in a business combination pursuant to a tender offer, amalgamation or sale of assets.

        The amalgamation of a Bermuda company with another company requires the amalgamation agreement to be approved by the company's board of directors and by its shareholders. Unless the company's bye-laws provide otherwise, the approval of 75% of the shareholders voting at a meeting is required to approve the amalgamation agreement, and the quorum for such meeting must be two persons holding or representing more than one-third of the issued shares of the company. Our bye-laws provide that an amalgamation must be approved by our board of directors and by shareholders owning

155

Table of Contents

a majority of the issued and outstanding shares entitled to vote. Shareholders who did not vote in favor of the amalgamation may apply to court for an appraisal within one month of notice of the shareholders meeting.

        Under the Bermuda Companies Act, we are not required to seek the approval of our shareholders for the sale of all or substantially all of our assets. However, our bye-laws provide that for so long as any of the Investors or their respective affiliates continue to retain the right to designate at least one director of our board of directors any sale, lease or exchange by us of all or substantially all of our assets will require the approval of either (1) our board of directors, acting by a majority (including at least one director designated by each Investor then entitled to designate a director) or (2) our board of directors and shareholders owning a majority of the outstanding shares entitled to vote.

        Under Bermuda law, where an offer is made for shares of a company and, within four months of the offer, the holders of not less than 90% of the shares not owned by the offeror, its subsidiaries or their nominees accept such offer, the offeror may by notice require the non-tendering shareholders to transfer their shares on the terms of the offer. Dissenting shareholders do not have express appraisal rights but are entitled to seek relief (within one month of the compulsory acquisition notice) from the court, which has power to make such orders as it thinks fit. Additionally, where one or more parties hold not less than 95% of the shares of a company, such parties may, pursuant to a notice given to the remaining shareholders, acquire the shares of such remaining shareholders. Dissenting shareholders have a right to apply to the court for appraisal of the value of their shares within one month of the compulsory acquisition notice. If a dissenting shareholder is successful in obtaining a higher valuation, that valuation must be paid to all shareholders being squeezed out.

Dividends and Repurchase of Shares

        Pursuant to our bye-laws, our board of directors has the authority to declare dividends and authorize the repurchase of shares subject to applicable law.

        Under Bermuda law, a company may not declare or pay a dividend if there are reasonable grounds for believing that the company is, or would after the payment be, unable to pay its liabilities as they become due or the realizable value of its assets would thereby be less than the aggregate of its liabilities and its issued share capital and its share premium accounts. Issued share capital is the aggregate par value of the company's issued and outstanding shares, and the share premium account is the aggregate amount paid for issued and outstanding shares over and above their par value. Share premium accounts may be reduced in certain limited circumstances. Under Bermuda law, a company cannot purchase its own shares if there are reasonable grounds for believing that the company is, or after the repurchase would be, unable to pay its liabilities as they become due.

Transactions with Significant Shareholders

        The Bermuda Companies Act does not have, and our bye-laws do not provide for, the equivalent of the "business combination" provisions of Section 203 of the Delaware General Corporate Law.

Corporate Opportunities

        Our bye-laws provide that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in, or in being offered an opportunity to participate in, any business opportunity that may be from time to time be presented to the Investors or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (other than us and our subsidiaries) or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such person shall be liable to us for breach of any fiduciary or other duty, as a director or controlling shareholder or otherwise, by reason of the fact that such

156

Table of Contents

person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity to us unless, in the case of any such person who is one of our directors, such person fails to present any business opportunity that is expressly offered to such person solely in his or her capacity as our director.

Shareholder Suits

        Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company's memorandum of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of the company's shareholders than that which actually approved it.

        When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply to the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company's affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company.

        Our bye-laws contain a provision by virtue of which we and our shareholders waive any claim or right of action that they have, both individually and on our behalf, against any director or officer in relation to any action or failure to take action by such director or officer, except in respect of any fraud or dishonesty of such director or officer. We have been advised by the SEC that in the opinion of the SEC, the operation of this provision as a waiver of the right to sue for violations of federal securities laws would likely be unenforceable in U.S. courts.

Access to Books and Records and Dissemination of Information

        Members of the general public have a right to inspect the public documents of a company available at the office of the Registrar of Companies in Bermuda. These documents include the company's memorandum of association and any amendments thereto. The shareholders have the additional right to inspect the bye-laws of the company, minutes of general meetings of shareholders and the company's audited financial statements. The company's audited financial statements must be presented at the annual general meeting of shareholders. The company's share register is open to inspection by shareholders and by members of the general public without charge. A company is required to maintain its share register in Bermuda but may, subject to the provisions of the Bermuda Companies Act, establish a branch register outside of Bermuda. Bermuda law does not, however, provide a general right for shareholders to inspect or obtain copies of any other corporate records.

Registrar or Transfer Agent

        A register of holders of the common shares will be maintained by Codan Services Limited in Bermuda, and a branch register will be maintained in the United States by Computershare Trust Company, N.A., who will serve as branch registrar and transfer agent.

Listing

        Our common shares have been approved for listing on the NYSE under the symbol "KOS." Settlement will take place through The Depository Trust Company in U.S. dollars. Shortly after the closing of this offering we intend to apply to list our common shares on the GSE, although there can be no assurance that this listing will be completed in a timely manner, or at all.

157

Table of Contents
SHARES ELIGIBLE FOR FUTURE SALE

        Prior to this offering, there has been no market for our common shares, and a liquid trading market for our common shares may not develop or be sustained after this offering. Future sales of substantial amounts of our common shares in the public market could adversely affect market prices prevailing from time to time. Furthermore, because only a limited number of common shares will be available for sale shortly after this offering due to existing contractual and legal restrictions on resale as described below, there may be sales of substantial amounts of our common shares in the public market after the restrictions lapse. This may adversely affect the prevailing market price and our ability to raise equity capital in the future. Our common shares have been approved for listing on the NYSE under the symbol "KOS." Shortly after the closing of this offering we intend to apply to list our common shares on the GSE, although there can be no assurance that this listing will be completed in a timely manner, or at all.

        Based on the number of common shares issued and outstanding as of December 31, 2010 after giving effect to our reorganization, upon completion of this offering, 371,176,471 common shares will be issued and outstanding, assuming no exercise of the underwriters' over-allotment option. Of the common shares to be issued and outstanding immediately after the closing of this offering, the            common shares to be sold in this offering will be freely tradable without restriction under the Securities Act unless purchased by our "affiliates," as that term is defined in Rule 144 under the Securities Act. The remaining common shares are "restricted securities" under Rule 144. Substantially all of these restricted securities will be subject to the provisions of the lock-up agreements referred to below.

        After the expiration of any lock-up period, these restricted securities may be sold in the public market only if registered or if they qualify for an exemption from registration under Rule 144 or 701 under the Securities Act, which exemptions are summarized below.

Rule 144

        In general, under Rule 144 under the Securities Act, as in effect on the date of this prospectus, a person who is not one of our affiliates at any time during the three months preceding a sale, and who has beneficially owned our common shares to be sold for at least six months, would be entitled to sell an unlimited number of our common shares, provided current public information about us is available. In addition, under Rule 144, a person who is not one of our affiliates at any time during the three months preceding a sale, and who has beneficially owned our common shares to be sold for at least one year, would be entitled to sell an unlimited number of common shares beginning one year after this offering without regard to whether current public information about us is available. Our affiliates who have beneficially owned our common shares for at least six months are entitled to sell within any three month period a number of common shares that does not exceed the greater of:

•
1% of the number of our common shares then issued and outstanding, which will equal approximately 3,711,765 common shares immediately after this offering, and

•
the average weekly trading volume in our common shares on the NYSE during the four calendar weeks preceding the date of filing of a Notice of Proposed Sale of Securities Pursuant to Rule 144 with respect to the sale.

        Sales by affiliates under Rule 144 are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us. Rule 144 also provides that affiliates relying on Rule 144 to sell our common shares that are not restricted common shares must nonetheless comply with the same restrictions applicable to restricted common shares, other than the holding period requirement.

        Upon expiration of any lock-up period and the six-month holding period, approximately 304,160,708 of our common shares will be eligible for sale under Rule 144 by our affiliates, subject to

158

Table of Contents

the above restrictions. Upon the expiration of any lock-up period and the six-month holding period, approximately 37,015,763 of our common shares will be eligible for sale by non-affiliates under Rule 144. We cannot estimate the number of common shares that our existing shareholders will elect to sell under Rule 144.

Lock-up Agreements

        In connection with this offering, we, our officers and directors, and certain shareholders have each entered into a lock-up agreement with the underwriters of this offering that restricts the sale of our common shares for a period of 180 days after the date of this prospectus, subject to extension in certain circumstances. The Representatives (as defined in "Underwriting"), on behalf of the underwriters, may, in their sole discretion, choose to release any or all of our common shares subject to these lock-up agreements at any time prior to the expiration of the lock-up period without notice. For more information, see "Underwriting."

Registration Rights

        Prior to the completion of this offering, we will become a party to the existing registration rights agreement by and among Kosmos Energy Holdings and its unitholders pursuant to which we will grant certain registration rights to the unitholders with respect to the common shares they will receive in the corporate reorganization. Pursuant to the lock-up agreements described above, certain of our shareholders have agreed not to exercise those rights during the lock-up period without the prior written consent of the Representatives of the underwriters of this offering.

159

Table of Contents
CERTAIN TAX CONSIDERATIONS

Bermuda Tax Considerations

        At the present time, there is no Bermuda income or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance tax payable by us or by our shareholders in respect of our shares. We have obtained an assurance from the Bermuda Minister of Finance under the Exempted Undertakings Tax Protection Act 1966 that, in the event that any legislation is enacted in Bermuda imposing any tax computed on profits or income, or computed on any capital asset, gain or appreciation or any tax in the nature of estate duty or inheritance tax, such tax shall not, until March 31, 2035, be applicable to us or to any of our operations or to our shares, debentures or other obligations except insofar as such tax applies to persons ordinarily resident in Bermuda or is payable by us in respect of real property owned or leased by us in Bermuda.

U.S. Federal Income Tax Considerations

        The following is a description of the material U.S. federal income tax consequences to the U.S. Holders described below of owning and disposing of our common shares, but it does not purport to be a comprehensive description of all tax considerations that may be relevant to a particular person's decision to acquire our common shares. This discussion does not discuss any state, local or foreign tax considerations. This discussion applies only to a U.S. Holder that acquires our common shares pursuant to this offering and holds them as capital assets for tax purposes. In addition, it does not describe all of the tax consequences that may be relevant in light of the U.S. Holder's particular circumstances, including alternative minimum tax consequences and tax consequences applicable to U.S. Holders subject to special rules, such as:

•
certain financial institutions;

•
dealers or traders in securities who use a mark-to-market method of tax accounting;

•
persons holding our common shares as part of a hedging transaction, straddle, wash sale, conversion transaction or integrated transaction or persons entering into a constructive sale with respect to our common shares;

•
persons whose functional currency for U.S. federal income tax purposes is not the U.S. dollar;

•
entities classified as partnerships for U.S. federal income tax purposes;

•
tax-exempt entities, including "individual retirement accounts"; or

•
persons that own or are deemed to own ten percent or more of our voting shares.

        If an entity that is classified as a partnership for U.S. federal income tax purposes holds our common shares, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the activities of the partnership. Partnerships holding our common shares and partners in such partnerships should consult their tax advisers as to the particular U.S. federal income tax consequences of holding and disposing of our common shares.

        This discussion is based on the Internal Revenue Code of 1986, as amended (the "Code"), administrative pronouncements, judicial decisions, and final, temporary and proposed Treasury regulations, all as of the date of this prospectus, any of which is subject to change, possibly with retroactive effect. U.S. Holders should consult their tax advisers concerning the U.S. federal, state, local and foreign tax consequences of owning and disposing of our common shares in their particular circumstances.

160

Table of Contents

        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

161

Table of Contents

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.

162

Table of Contents
UNDERWRITING

        Under the terms and subject to the conditions contained in an underwriting agreement dated            , 2011, we have agreed to sell to the underwriters named below, for whom Citigroup Global Markets Inc., Barclays Capital Inc. and Credit Suisse Securities (USA) LLC are acting as representatives (the "Representatives"), the following respective numbers of common shares:
 	 	 	 	 	 	
Underwriter	 	Number of
Common Shares	 	
Citigroup Global Markets Inc. 	 	 	            	 	
Barclays Capital Inc. 	 	 	            	 	
Credit Suisse Securities (USA) LLC	 	 	            	 	
BNP Paribas Securities Corp. 	 	 	            	 	
SG Americas Securities, LLC	 	 	            	 	
Credit Agricole Securities (USA) Inc. 	 	 	            	 	
Howard Weil Incorporated	 	 	            	 	
HSBC Securities (USA) Inc. 	 	 	            	 	
Jefferies & Company, Inc. 	 	 	            	 	
Natixis Bleichroeder LLC	 	 	            	 	
RBC Capital Markets, LLC	 	 	            	 	
 	Total	 	 	            	 	
 	 	 	 	
        The underwriting agreement provides that the underwriters are obligated to purchase all the common shares in the offering if any are purchased, other than those shares covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated.

        We have granted to the underwriters a 30-day option to purchase on a pro rata basis up to            additional common shares from us at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common shares.

        The underwriters propose to offer the common shares initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $    per common share. The underwriters and selling group members may allow a discount of $        per common share on sales to other broker/dealers. After the initial public offering the Representatives may change the public offering price and concession and discount to broker/dealers. The offering of the common shares by the underwriters is subject to receipt and acceptance and subject to the underwriters' right to reject any order in whole or in part.

        The following table summarizes the compensation and estimated expenses we will pay:

	 	Per Common Share	 	Total	 	
 
	 	Without
Over-allotment	 	With
Over-allotment	 	Without
Over-allotment	 	With
Over-allotment	 	
Underwriting discounts and commissions paid by us	 	$	            	 	$	            	 	$	            	 	$	            	 	
Expenses payable by us	 	$	            	 	$	            	 	$	            	 	$	            	 	
        The Representatives have informed us that the underwriters do not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the common shares being offered.

        We have agreed, subject to certain exceptions, that we will not offer, sell, issue, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the SEC a registration statement

163

Table of Contents

under the Securities Act relating to, any of our common shares or securities convertible into or exchangeable or exercisable for any of our common shares, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of the Representatives for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the "lock-up" period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the "lock-up" period, we announce that we will release earnings results during the 16-day period beginning on the last day of the "lock-up" period, then in either case the expiration of the "lock-up" will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless the Representatives waive, in writing, such an extension.

        Our officers, directors and certain shareholders have agreed, subject to certain exceptions, that they will not offer, sell, contract to sell or otherwise dispose of, directly or indirectly, any of our common shares or securities convertible into or exchangeable or exercisable for any of our common shares, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common shares, whether any of these transactions are to be settled by delivery of our common shares or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of the Representatives for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the "lock-up" period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the "lock-up" period, we announce that we will release earnings results during the 16-day period beginning on the last day of the "lock-up" period, then in either case the expiration of the "lock-up" will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless the Representatives waive, in writing, such an extension.

        We have agreed to indemnify the underwriters against liabilities under the Securities Act or contribute to payments that the underwriters may be required to make in that respect.

        The underwriters have reserved for sale at the initial public offering price up to            common shares for employees, directors and other persons associated with us who have expressed an interest in purchasing common shares in the offering. The number of common shares available for sale to the general public in the offering will be reduced to the extent these persons purchase the reserved common shares. Any reserved common shares not so purchased will be offered by the underwriters to the general public on the same terms as the other common shares.

        Our common shares have been approved for listing on the NYSE under the symbol "KOS." Shortly after the closing of this offering we intend to apply to list our common shares on the GSE, although there can be no assurance that this listing will be completed in a timely manner, or at all.

        In connection with the listing of the common shares on the NYSE, the underwriters will undertake to sell round lots of 100 shares or more to a minimum of 400 beneficial owners.

        Prior to this offering, there has been no public market for our common shares. The initial public offering price has been determined by a negotiation among us and the Representatives and will not necessarily reflect the market price of our common shares following the offering. The principal factors that were considered in determining the public offering price included:

•
the information presented in this prospectus;

•
the history of and prospects for the industry in which we will compete;

•
the ability of our management;

164

Table of Contents

•
the prospects for our future earnings;

•
the present state of our development and current financial condition;

•
the recent market prices of, and the demand for, publicly traded shares of generally comparable companies; and

•
the general condition of the securities markets at the time of this offering.

        We offer no assurances that the initial public offering price will correspond to the price at which the common shares will trade in the public market subsequent to the offering or that an active trading market for our common shares will develop and continue after the offering.

        In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act.

•
Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

•
Over-allotment involves sales by the underwriters of common shares in excess of the number of common shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of common shares over-allotted by the underwriters is not greater than the number of common shares that they may purchase in the over-allotment option. In a naked short position, the number of common shares involved is greater than the number of common shares in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing common shares in the open market.

•
Syndicate covering transactions involve purchases of the common shares in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of common shares to close out the short position, the underwriters will consider, among other things, the price of common shares available for purchase in the open market as compared to the price at which they may purchase common shares through the over-allotment option. If the underwriters sell more common shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying common shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common shares in the open market after pricing that could adversely affect investors who purchase in the offering.

•
Penalty bids permit the Representatives to reclaim a selling concession from a syndicate member when the common shares originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

        These stabilizing transactions, syndicate covering transactions and penalty bids, as well as purchases by the underwriters for their own accounts, may have the effect of raising or maintaining the market price of our common shares or preventing or retarding a decline in the market price of the common shares. As a result the price of our common shares may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

        Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory, lending and investment banking services for us and our affiliates, for which they received or will receive customary fees and expenses. Affiliates of

165

Table of Contents

Citigroup Global Markets Inc., Barclays Capital Inc. and Credit Suisse Securities (USA) LLC have extended commitments to an affiliate of Kosmos in conjunction with Kosmos' previous and new commercial debt facilities. An affiliate of Credit Suisse Securities (USA) LLC also acted as a project finance advisor for a portion of such facilities.

        The common shares are offered for sale in those jurisdictions in the United States, Europe, Asia and elsewhere where it is lawful to make such offers.

        Each of the underwriters has represented and agreed that it has not offered, sold or delivered and will not offer, sell or deliver any of the common shares directly or indirectly, or distribute this prospectus or any other offering material relating to the common shares, in or from any jurisdiction except under circumstances that will result in compliance with the applicable laws and regulations thereof and that will not impose any obligations on us except as set forth in the underwriting agreement.

        In relation to each member state of the European Economic Area which has implemented the Prospectus Directive (each, a "Relevant Member State"), including each Relevant Member State that has implemented amendments to Article 3(2) of the Prospectus Directive with regard to persons to whom an offer of securities is addressed and the denomination per unit of the offer of securities (each, an "Early Implementing Member State"), with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the "Relevant Implementation Date"), no offer of common shares will be made to the public in that Relevant Member State (other than offers (the "Permitted Public Offers") where a prospectus will be published in relation to the common shares that has been approved by the competent authority in a Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive), except that with effect from and including that Relevant Implementation Date, offers of common shares may be made to the public in that Relevant Member State at any time:

(a)
to "qualified investors" as defined in the Prospectus Directive, including:

(A)
(in the case of Relevant Member States other than Early Implementing Member States), legal entities which are authorised or regulated to operate in the financial markets or, if not so authorised or regulated, whose corporate purpose is solely to invest in securities, or any legal entity which has two or more of (i) an average of at least 250 employees during the last financial year; (ii) a total balance sheet of more than €43.0 million and (iii) an annual turnover of more than €50.0 million as shown in its last annual or consolidated accounts; or

(B)
(in the case of Early Implementing Member States), persons or entities that are described in points (1) to (4) of Section I of Annex II to Directive 2004/39/EC, and those who are treated on request as professional clients in accordance with Annex II to Directive 2004/39/EC, or recognised as eligible counterparties in accordance with Article 24 of Directive 2004/39/EC unless they have requested that they be treated as non-professional clients; or

(b)
to fewer than 100 (or, in the case of Early Implementing Member States, 150) natural or legal persons (other than "qualified investors" as defined in the Prospectus Directive) subject to obtaining the prior consent of the Subscribers; or

(c)
in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of common shares shall result in a requirement for the publication of a prospectus pursuant to Article 3 of the Prospectus Directive or of a supplement to a prospectus pursuant to Article 16 of the Prospectus Directive.

166

Table of Contents

        Each person in a Relevant Member State (other than a Relevant Member State where there is a Permitted Public Offer) who initially acquires any common shares or to whom any offer is made will be deemed to have represented, acknowledged and agreed that (A) it is a "qualified investor", and (B) in the case of any common shares acquired by it as a financial intermediary, as that term is used in Article 3(2) of the Prospectus Directive, (x) the common shares acquired by it have not been acquired on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than "qualified investors" as defined in the Prospectus Directive, or in circumstances in which the prior consent of the Representatives has been given to the offer or resale, or (y) where common shares have been acquired by it on behalf of persons in any Relevant Member State other than "qualified investors" as defined in the Prospectus Directive, the offer of those common shares to it or not treated under the Prospectus Directive as having been made to such persons.

        For the purpose of the above provisions, the expression "an offer to the public" in relation to any common shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer of any common shares to be offered so as to enable an investor to decide to purchase any common shares, as the same may be varied in the Relevant Member State by any measure implementing the Prospectus Directive in the Relevant Member State and the expression "Prospectus Directive" means Directive 2003/71 EC (including that Directive as amended, in the case of Early Implementing Member States) and includes any relevant implementing measure in each Relevant Member State.

        Each of the underwriters has severally represented, warranted and agreed as follows:

(a)
it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of section 21 of FSMA) to persons who have professional experience in matters relating to investments falling with Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 or in circumstances in which section 21 of FSMA does not apply to the company; and

(b)
it has complied with, and will comply with all applicable provisions of FSMA with respect to anything done by it in relation to the common shares in, from or otherwise involving the United Kingdom.

        Neither this prospectus nor any other offering material relating to the common shares described in this prospectus has been submitted to the clearance procedures of the Autorité des Marchés Financiers  or of the competent authority of another member state of the European Economic Area and notified to the Autorité des Marchés Financiers . The common shares have not been offered or sold and will not be offered or sold, directly or indirectly, to the public in France. Neither this prospectus nor any other offering material relating to the common shares has been or will be:

•
released, issued, distributed or caused to be released, issued or distributed to the public in France; or

•
used in connection with any offer for subscription or sale of the shares to the public in France.

        Such offers, sales and distributions will be made in France only:

•
to qualified investors (investisseurs qualifiés) and/or to a restricted circle of investors (cercle restreint d'investisseurs), in each case investing for their own account, all as defined in, and in accordance with articles L.411-2, D.411-1, D.411-2, D.734-1, D.744-1, D.754-1 and D.764-1 of the French Code monétaire et financier ;

•
to investment services providers authorized to engage in portfolio management on behalf of third parties; or

167

Table of Contents

•
in a transaction that, in accordance with article L.411-2-II-1°-or-2°-or 3° of the FrenchCode monétaire et financier  and article 211-2 of the General Regulations ( Règlement Général ) of the Autorité des Marchés Financiers , does not constitute a public offer (appel public à l'épargne ).

        The common shares may be resold directly or indirectly, only in compliance with articles L.411-1, L.411-2, L.412-1 and L.621-8 through L.621-8-3 of the French Code monétaire et financier .

        The common shares may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to "professional investors" within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a "prospectus" within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), and no advertisement, invitation or document relating to the common shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to "professional investors" within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

        This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the "SFA"), (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA. Where the common shares are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries' rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the common shares under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.

        The common shares have not been and will not be registered under the Financial Instruments and Exchange Law of Japan (the Financial Instruments and Exchange Law) and each underwriter has agreed that it will not offer or sell any common shares, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

        This prospectus as well as any other material relating to the common shares does not constitute an issue prospectus pursuant Articles 652a or 1156 of the Swiss Code of Obligations. The common shares

168

Table of Contents

will not be listed on the SWX Swiss Exchange and, therefore, the documents relating to the common shares, including, but not limited to, this prospectus, do not claim to comply with the disclosure standards of the listing rules of SWX Swiss Exchange and corresponding prospectus schemes annexed to the listing rules of the SWX Swiss Exchange. None of this offering and the common shares has been or will be approved by any Swiss regulatory authority. The common shares are being offered by way of a private placement to a limited and selected circle of investors in Switzerland without any public offering and only to investors who do not subscribe for the common shares with the intention to distribute them to the public. The investors will be individually approached by the Issuer from time to time. This prospectus as well as any other material relating to the common shares is personal and confidential to each offeree and do not constitute an offer to any other person. This prospectus may only be used by those investors to whom it has been handed out in connection with the offer described herein and may neither directly nor indirectly be distributed or made available to other persons without express consent of the Issuer. It may not be used in connection with any other offer and shall in particular not be copied and/or distributed to the public in Switzerland or from Switzerland.

        The common shares described in this prospectus may not be, are not and will not be offered, distributed, sold, transferred or delivered, directly or indirectly, to any person in the Dubai International Financial Centre other than in accordance with the Offered Securities Rules of the Dubai Financial Services Authority.

        This offering is restricted in the Kingdom of Bahrain to banks, financial institutions and professional investors and any person receiving this prospectus in the Kingdom of Bahrain and not falling within those categories is ineligible to purchase our common shares.

        This prospectus does not constitute a public offer of securities in the Kingdom of Saudi Arabia and is not intended to be a public offer. No action has been or will be taken in the Kingdom of Saudi Arabia that would permit a public offering or private placement of our common shares in the Kingdom of Saudi Arabia, or possession or distribution of any offering materials in relation thereto. Our common shares may only be offered or sold in the Kingdom of Saudi Arabia in accordance with Part 5 (Exempt Offers) of the Offers of Securities Regulations dated 20/8/1425 AH (corresponding to 4/10/2004) (the "Regulations") and, in accordance with Part 5 (Exempt Offers) Article 1716(a)(3) of the Regulations, common shares will be offered to no more than 60 offerees in the Kingdom of Saudi Arabia with each such offeree paying an amount not less than Saudi Riyals one million or its equivalent. Investors are informed that Article 19 of the Regulations places restrictions on secondary market activity with respect to our common shares. Any resale or other transfer, or attempted resale or other transfer, made other than in compliance with the above-stated restrictions shall not be recognized by us. Prospective purchasers of the common shares offered hereby should conduct their own due diligence on the accuracy of the information relating to the securities. If you do not understand the contents of this document you should consult an authorized financial adviser.

        This prospectus does not constitute an invitation or public offer of securities in the State of Qatar and should not be construed as such. This prospectus is intended only for the original recipient and must not be provided to any other person. It is not for general circulation in the State of Qatar and may not be reproduced or used for any other purpose.

        No marketing or sale of the common shares may take place in Kuwait unless the same has been duly authorized by the Kuwait Ministry of Commerce and Industry pursuant to the provisions of Law No. 31/1990 and the various ministerial regulations issued thereunder. Persons into whose possession this offering memorandum comes are required to inform themselves about and to observe such restrictions. Investors in Kuwait who approach us or obtain copies of this offering memorandum are required to keep such prospectus confidential and not to make copies thereof or distribute the same to any other person and are also required to observe the restrictions provided for in all jurisdictions with respect to offering, marketing and the sale of common shares.

169

Table of Contents

        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.

170

Table of Contents
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.

171

Table of Contents
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.	
172

Table of Contents
 	 	 	
"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.	
173

Table of Contents
 	 	 	
"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.	
174

Table of Contents
 	 	 	
"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.	
175

Table of Contents
 	 	 	
"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.	
176

Table of Contents
 	 	 	
"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.	
177

Table of Contents
 	 	 	
"Production costs"	 	The production or operational costs incurred while extracting and producing, storing, and transporting oil and/or natural gas. Typical of these costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes, and insurance.	

"Producing well"	
 	
A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.	

"Prospect(s)"	
 	
A potential trap which may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of them fail neither oil nor natural gas will be present, at least not in commercial volumes.	

"Proved reserves"	
 	
Estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).	

"Proved developed reserves"	
 	
Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.	

"Proved undeveloped reserves"	
 	
Proved undeveloped reserves are those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.	

"Reserves"	
 	
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, a revenue interest in the production, installed means of delivering oil, gas, or related substances to market, and all permits and financing required to implement the project.	

"Reservoir"	
 	
A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.	
178

Table of Contents
 	 	 	
"Royalty"	 	A fractional undivided interest in the production of oil and natural gas wells or the proceeds therefrom, to be received free and clear of all costs of development, operations or maintenance.	

"Seal"	
 	
A relatively impermeable rock, commonly shale, anhydrite or salt, that forms a barrier or cap above and around reservoir rock such that fluids cannot migrate beyond the reservoir. A seal is a critical component of a complete petroleum system.	

"Seismic data"	
 	
Seismic data is used by scientists to interpret the composition, fluid content, extent and geometry of rocks in the subsurface. Seismic data is acquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflected beneath the earth's surface and a receiver is used to collect and record these reflections.	

"Sequence"	
 	
A sequence refers to a series of geological events, processes, or rocks, arranged in chronological order.	

"Shale"	
 	
A fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.	

"Shelf margin"	
 	
The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.	

"Shut in"	
 	
To close the valves on a well so that it stops producing.	

"Sidetrack"	
 	
To drill a secondary wellbore within the original wellbore away from an original wellbore.	

"Source rock"	
 	
This term refers to rocks with sufficient organic material from which hydrocarbons have been generated or are capable of being generated. They typically have a deeper, warmer, and higher pressure than reservoir rocks which allows the expelled hydrocarbons to accumulate.	

"Spud"	
 	
The very beginning of drilling operations of a new well, occurring when the drilling bit penetrates the surface utilizing a drilling rig capable of drilling the well to the authorized total depth.	

"Structural trap"	
 	
A structural strap is a topographic feature in the earth's subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and gas in the strata.	

"Structural-stratigraphic trap"	
 	
A structural-stratigraphic trap is a combination trap with structural and stratigraphic features.	

"Stratigraphy"	
 	
The study of the composition, relative ages and distribution of layers of sedimentary rock.	
179

Table of Contents
 	 	 	
"Stratigraphic trap"	 	A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.	

"Submarine fan"	
 	
A fan-shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.	

"Tertiary"	
 	
A geological time period ranging between 65 million and 2.6 million years ago.	

"Three-way fault trap"	
 	
A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.	

"Thrust Fault"	
 	
A thrust fault occurs where rocks of lower (older) stratigraphic position are pushed up and over higher (younger) strata. Thrust faults are the result of compression forces.	

"Thrust Sheet"	
 	
Thrust sheet is the body of rock within a thrust fault.	

"Total depth"	
 	
The maximum depth reached by a well.	

"Trap"	
 	
A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.	

"Transform fault"	
 	
A transform fault or transform boundary is a type of fault at the margin of a tectonic plate. Transform faults occur where tectonic plates slide past or move apart from each other. Most transform faults are found on the ocean floor, however, the best-known transform faults are found on land.	

"Turbidite"	
 	
A turbidite is a sediment transported and deposited by a turbidity current. A turbidity current is an underwater current of rapidly moving sand-laden water moving down a slope, comparable to an underwater avalanche.	

"Turbidite fan"	
 	
A turbidite fan is a fan shaped deposit of sand deposted on the seabed by a turbidity current. The architecture of these fans is constructed through many repeated depositional events or cycles. See "—Turbidite."	

"Turbidite fan lobe"	
 	
A turbidite fan lobe is one depositional cycle within the overall larger turbidite fan. These turbidite fan lobes often consist of excellent reservoir rock.	

"Turonian"	
 	
A geological time period ranging between 93.5 million and 89.3 million years ago.	

"Updip"	
 	
This term refers to a relative location up the slope of a dipping surface or formation.	
180

Table of Contents
 	 	 	
"Undeveloped acreage"	 	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.	

"Unitized production"	
 	
Pooled production from wells or a reservoir. The proceeds of this pooled production are distributed to the participants according to the agreed-upon formula.	

"West African Transform Margin"	
 	
A portion of the West African continental margin extending approximately 2,400 miles (1,500 kilometers) along the coast from eastern Ghana, across the Ivory Coast and Liberia, and to the west of Sierra Leone. The area is associated with a series of transform faults.	

"Working interest"	
 	
A percentage of ownership in an oil and gas lease granting its owner the right to explore, drill and produce oil and gas from a tract of property. Working interest owners are obligated to pay a corresponding percentage of the cost of leasing, drilling, producing and operating a well or unit. The working interest also entitles its owner to share in production revenues with other working interest owners, based on the percentage of working interest owned.	

"Workover"	
 	
Operations in a producing well to restore or increase production.	
181

Table of Contents
INDEX TO FINANCIAL STATEMENTS

 
	 	Page	 	
Kosmos Energy Holdings	 	 	 	 	
Audited Consolidated Financial Statements (a Development Stage Entity)	 	 	 	 	
 	Report of Independent Registered Public Accounting Firm	 	 	
F-2	 	
 	Consolidated Balance Sheets as of December 31, 2009 and 2010	 	 	
F-3	 	
 	Consolidated Statements of Operations for the years ended December 31, 2008, 2009 and 2010 and for the Period April 23, 2003 (Inception) through December 31, 2010	 	 	
F-4	 	
 	Consolidated Statements of Unit Holdings Equity for the Period April 23, 2003 (Inception) through December 31, 2003 and for each of the seven years in the period ended December 31, 2010	 	 	
F-5	 	
 	Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2009 and 2010 and for the Period April 23, 2003 (Inception) through December 31, 2010	 	 	
F-6	 	
 	Consolidated Statements of Comprehensive Loss for the years ended December 31, 2008, 2009 and 2010 and for the Period April 23, 2003 (Inception) through December 31, 2010	 	 	
F-7	 	
 	Notes to Consolidated Financial Statements	 	 	
F-8	 	
 	Supplementary Oil and Gas Data (Unaudited)	 	 	
F-39	 	
F-1

Table of Contents
Report of Independent Registered Public Accounting Firm

The Unit Holders
Kosmos Energy Holdings

        We have audited the accompanying consolidated balance sheets of Kosmos Energy Holdings (a development stage entity) (the "Company") as of December 31, 2009 and 2010, and the related consolidated statements of operations, unit holdings equity, cash flows and comprehensive loss for each of the three years in the period ended December 31, 2010, and for the period April 23, 2003 (Inception) through December 31, 2010. Our audits also included the financial statement schedules included at Item 16(b). These consolidated financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and schedules based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Kosmos Energy Holdings at December 31, 2009 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, and for the period April 23, 2003 (Inception) through December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the consolidated financial statements taken as a whole, presents fairly, in all material respects, the financial information set forth therein.
 	 	 	
 	 	/s/ Ernst & Young LLP	
Dallas, Texas
March 2, 2011

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, except share
and per share data)
	 	 	
Assets	 	 	 	 	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	139,505	 	$	100,415	 	$	100,415	 	 	
 	Restricted cash	 	 	—	 	 	80,000	 	 	80,000	 	 	
 	Receivables:	 	 	 	 	 	 	 	 	 	 	 	
 	 	Joint interest billings	 	 	42,616	 	 	124,449	 	 	124,449	 	 	
 	 	Notes	 	 	52,318	 	 	113,889	 	 	113,889	 	 	
 	 	Other	 	 	1,693	 	 	615	 	 	615	 	 	
 	Inventories	 	 	19,621	 	 	37,674	 	 	37,674	 	 	
 	Prepaid expenses and other	 	 	848	 	 	13,278	 	 	13,278	 	 	
 	Current deferred tax assets	 	 	127	 	 	89,600	 	 	89,600	 	 	
 	 	 	 	 	 	 	 	 	
Total current assets	 	 	256,728	 	 	559,920	 	 	559,920	 	 	
Property and equipment:	 	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas properties, net of accumulated depletion of zero and $6,430, respectively	 	 	595,091	 	 	989,869	 	 	989,869	 	 	
 	Other property, net of accumulated depreciation of $3,193 and $5,343, respectively	 	 	8,916	 	 	8,131	 	 	8,131	 	 	
 	 	 	 	 	 	 	 	 	
Property and equipment—net	 	 	604,007	 	 	998,000	 	 	998,000	 	 	
Other assets:	 	 	 	 	 	 	 	 	 	 	 	
 	Restricted cash	 	 	30,000	 	 	32,000	 	 	32,000	 	 	
 	Long-term receivables—joint interest billings, net of allowance	 	 	41,593	 	 	21,897	 	 	21,897	 	 	
 	Debt issue costs and other assets, net of accumulated amortization of $3,266 and $32,093, respectively	 	 	89,729	 	 	78,217	 	 	78,217	 	 	
 	Derivatives	 	 	—	 	 	1,501	 	 	1,501	 	 	
 	 	 	 	 	 	 	 	 	
Total assets	 	$	1,022,057	 	$	1,691,535	 	$	1,691,535	 	 	
 	 	 	 	 	 	 	 	 	
Liabilities and unit holdings/shareholders' equity	 	 	 	 	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	 	 	 	 	
 	Current maturities of long-term debt	 	$	—	 	$	245,000	 	$	245,000	 	 	
 	Accounts payable	 	 	97,837	 	 	163,495	 	 	163,495	 	 	
 	Accrued liabilities	 	 	41,810	 	 	53,208	 	 	53,208	 	 	
 	Derivatives	 	 	—	 	 	20,354	 	 	20,354	 	 	
 	 	 	 	 	 	 	 	 	
Total current liabilities	 	 	139,647	 	 	482,057	 	 	482,057	 	 	
Long-term debt	 	 	285,000	 	 	800,000	 	 	800,000	 	 	
Long-term derivatives	 	 	—	 	 	15,104	 	 	15,104	 	 	
Long-term asset retirement obligations	 	 	—	 	 	16,752	 	 	16,752	 	 	
Leasehold improvement allowance—long-term	 	 	1,369	 	 	1,014	 	 	1,014	 	 	
Long-term deferred tax liability	 	 	653	 	 	12,513	 	 	12,513	 	 	
Convertible preferred units, 100,000,000 units authorized:	 	 	 	 	 	 	 	 	 	 	 	
 	Series A—30,000,000 units issued at December 31, 2009 and 2010	 	 	300,000	 	 	383,246	 	 	—	 	 	
 	Series B—20,000,000 units issued at December 31, 2009 and 2010	 	 	500,000	 	 	568,163	 	 	—	 	 	
 	Series C—884,956 units issued at December 31, 2009 and 2010	 	 	13,244	 	 	27,097	 	 	—	 	 	
Unit holdings/shareholders' equity:	 	 	 	 	 	 	 	 	 	 	 	
 	Common units, 100,000,000 units authorized; 18,666,667 and 19,069,662 issued at December 31, 2009 and 2010, respectively	 	 	516	 	 	516	 	 	—	 	 	
 	Common shares, $0.01 par value; 371,176,471 common shares issued and outstanding, pro forma as adjusted for the effect of our corporate reorganization and this offering	 	 	—	 	 	—	 	 	3,412	 	 	
 	Additional paid-in capital	 	 	19,108	 	 	—	 	 	975,610	 	 	
 	Deficit accumulated during development stage	 	 	(237,480	)	 	(615,515	)	 	(615,515	)	 	
 	Accumulated other comprehensive income	 	 	—	 	 	588	 	 	588	 	 	
 	 	 	 	 	 	 	 	 	
Total unit holdings/shareholders' equity	 	 	(217,856	)	 	(614,411	)	 	364,095	 	 	
 	 	 	 	 	 	 	 	 	
Total liabilities, convertible preferred units and unit holdings/shareholders' equity	 	$	1,022,057	 	$	1,691,535	 	$	1,691,535	 	 	
 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-3

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Operations

	 	 

	 	Period
April 23, 2003
(Inception)
Through
December 31
2010	 	 	
 
	 	Years Ended December 31	 	 	 	 	 	
 
	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands, except share and per share data)
	 	 	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas revenue	 	$	—	 	$	—	 	$	—	 	$	—	 	 	 	
 	Interest income	 	 	1,637	 	 	985	 	 	4,231	 	 	9,142	 	 	 	
 	Other income	 	 	5,956	 	 	9,210	 	 	5,109	 	 	26,699	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total revenues and other income	 	 	7,593	 	 	10,195	 	 	9,340	 	 	35,841	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Exploration expenses, including dry holes	 	 	15,373	 	 	22,127	 	 	73,126	 	 	166,450	 	 	 	
 	General and administrative	 	 	40,015	 	 	55,619	 	 	98,967	 	 	236,165	 	 	 	
 	Depletion, depreciation and amortization	 	 	719	 	 	1,911	 	 	2,423	 	 	6,505	 	 	 	
 	Amortization—debt issue costs	 	 	—	 	 	2,492	 	 	28,827	 	 	31,319	 	 	 	
 	Interest expense	 	 	1	 	 	6,774	 	 	59,582	 	 	66,389	 	 	 	
 	Derivatives, net	 	 	—	 	 	—	 	 	28,319	 	 	28,319	 	 	 	
 	Equity in losses of joint venture	 	 	—	 	 	—	 	 	—	 	 	16,983	 	 	 	
 	Doubtful accounts expense	 	 	—	 	 	—	 	 	39,782	 	 	39,782	 	 	 	
 	Other expenses, net	 	 	21	 	 	46	 	 	1,094	 	 	1,949	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total costs and expenses	 	 	56,129	 	 	88,969	 	 	332,120	 	 	593,861	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Loss before income taxes	 	 	(48,536	)	 	(78,774	)	 	(322,780	)	 	(558,020	)	 	 	
 	Income tax expense (benefit)	 	 	269	 	 	973	 	 	(77,108	)	 	(75,148	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(245,672	)	$	(482,872	)	 	 	
Accretion to redemption value of convertible preferred units	 	 	
(21,449	
)	 	
(51,528	
)	 	
(77,313	
)	 	
(165,262	
)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net loss attributable to common unit holders	 	$	(70,254	)	$	(131,275	)	$	(322,985	)	$	(648,134	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	(Unaudited)	 	 	 	 	 	 	
Pro forma basic and diluted net loss per common share	 	 	 	 	 	 	 	$	(0.75	)	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pro forma weighted average number of shares used to compute pro forma net loss per share, basic and diluted	 	 	 	 	 	 	 	 	325,799	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-4

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Unit Holdings Equity

	 	 

	 	Deficit
Accumulated
During
Development
Stage	 	 

 
	 	Common Units	 	 
	 	 	 	Accumulated
Other
Comprehensive
Income	 	 

	 	 	 	Additional
Paid-in
Capital	 	 	 	 	 	 

	 	Units	 	Amount	 	 	 	 	 	 	 	Total	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 
	 	(In thousands)

Inception (April 23, 2003)	 	 	—	 	$	—	 	$	—	 	$	—	 	$	—	 	$	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of Kosmos Energy, LLC units	 	 	350	 	 	350	 	 	—	 	 	—	 	 	—	 	 	350	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(1,232	)	 	—	 	 	(1,232	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2003	 	 	350	 	 	350	 	 	—	 	 	(1,232	)	 	—	 	 	(882	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Exchanged Kosmos Energy, LLC units	 	 	(350	)	 	(350	)	 	—	 	 	—	 	 	—	 	 	(350	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	for Kosmos Energy Holdings units	 	 	3,500	 	 	350	 	 	—	 	 	—	 	 	—	 	 	350	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	2,850	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(3,951	)	 	—	 	 	(3,951	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2004	 	 	6,350	 	 	350	 	 	—	 	 	(5,183	)	 	—	 	 	(4,833	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	392	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(765	)	 	(42	)	 	—	 	 	—	 	 	—	 	 	(42	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	6	 	 	—	 	 	—	 	 	6	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(17,949	)	 	—	 	 	(17,949	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2005	 	 	5,977	 	 	308	 	 	6	 	 	(23,132	)	 	—	 	 	(22,818	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	409	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(784	)	 	(42	)	 	—	 	 	(205	)	 	—	 	 	(247	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	10	 	 	—	 	 	—	 	 	10	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(24,728	)	 	—	 	 	(24,728	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2006	 	 	5,602	 	 	266	 	 	16	 	 	(48,065	)	 	—	 	 	(47,783	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	1,067	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(25	)	 	—	 	 	—	 	 	(75	)	 	—	 	 	(75	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	447	 	 	—	 	 	—	 	 	447	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(60,788	)	 	—	 	 	(60,788	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2007	 	 	6,644	 	 	266	 	 	463	 	 	(108,928	)	 	—	 	 	(108,199	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	9,595	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(67	)	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	3,671	 	 	—	 	 	—	 	 	3,671	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(48,805	)	 	—	 	 	(48,805	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2008	 	 	16,172	 	 	266	 	 	4,134	 	 	(157,733	)	 	—	 	 	(153,333	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	10	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(15	)	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of C1 units	 	 	2,500	 	 	250	 	 	11,506	 	 	—	 	 	—	 	 	11,756	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	3,468	 	 	—	 	 	—	 	 	3,468	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(79,747	)	 	—	 	 	(79,747	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2009	 	 	18,667	 	 	516	 	 	19,108	 	 	(237,480	)	 	—	 	 	(217,856	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Issuance of profit units	 	 	411	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Relinquishments	 	 	(8	)	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Unit-based compensation	 	 	—	 	 	—	 	 	13,791	 	 	—	 	 	—	 	 	13,791	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Derivatives, net	 	 	—	 	 	—	 	 	—	 	 	—	 	 	588	 	 	588	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Accrete convertible preferred units to redemption amount	 	 	—	 	 	—	 	 	(21,143	)	 	(132,363	)	 	—	 	 	(153,506	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Accrete value of Series C Convertible Preferred Units	 	 	—	 	 	—	 	 	(11,756	)	 	—	 	 	—	 	 	(11,756	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Net loss	 	 	—	 	 	—	 	 	—	 	 	(245,672	)	 	—	 	 	(245,672	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2010	 	 	19,070	 	$	516	 	$	—	 	$	(615,515	)	$	588	 	$	(614,411	)	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-5

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Cash Flows

	 	 

	 	Period
April 23, 2003
(Inception)
Through
December 31
2010	 	 	
 
	 	Years Ended December 31	 	 	 	 	 	
 
	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	
Operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(245,672	)	$	(482,872	)	 	 	
Adjustments to reconcile net loss to net cash used in operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Equity in losses of joint venture	 	 	—	 	 	—	 	 	—	 	 	16,983	 	 	 	
 	 	Depletion, depreciation and amortization	 	 	719	 	 	4,403	 	 	31,250	 	 	37,824	 	 	 	
 	 	Deferred income taxes	 	 	428	 	 	99	 	 	(77,614	)	 	(77,086	)	 	 	
 	 	Deferred rent income	 	 	—	 	 	(266	)	 	(355	)	 	(621	)	 	 	
 	 	Leasehold improvement incentive	 	 	—	 	 	1,989	 	 	—	 	 	1,989	 	 	 	
 	 	Loss on disposal of inventory and other property	 	 	—	 	 	564	 	 	1,076	 	 	1,658	 	 	 	
 	 	Unsuccessful well costs	 	 	90	 	 	74	 	 	59,401	 	 	102,792	 	 	 	
 	 	Doubtful accounts expense	 	 	—	 	 	—	 	 	39,782	 	 	39,782	 	 	 	
 	 	Derivative related activity	 	 	—	 	 	—	 	 	34,545	 	 	34,545	 	 	 	
 	 	Unit-based compensation	 	 	3,671	 	 	3,468	 	 	13,791	 	 	21,393	 	 	 	
 	 	Leasehold impairment	 	 	—	 	 	—	 	 	—	 	 	3,000	 	 	 	
 	 	Changes in assets and liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Increase in receivables	 	 	(28,701	)	 	(34,531	)	 	(100,605	)	 	(186,747	)	 	 	
 	 	 	Increase in inventories	 	 	(2,412	)	 	(14,465	)	 	(12,699	)	 	(32,541	)	 	 	
 	 	 	(Increase) decrease in prepaid expenses and other	 	 	(88	)	 	61	 	 	(12,429	)	 	(12,671	)	 	 	
 	 	 	Increase in accounts payable	 	 	7,051	 	 	80,883	 	 	65,800	 	 	163,494	 	 	 	
 	 	 	Increase in accrued liabilities	 	 	2,376	 	 	9,877	 	 	11,929	 	 	38,069	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net cash used in operating activities	 	 	(65,671	)	 	(27,591	)	 	(191,800	)	 	(331,009	)	 	 	
Investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas assets	 	 	(156,283	)	 	(411,939	)	 	(444,712	)	 	(1,068,405	)	 	 	
Other property	 	 	(3,799	)	 	(6,376	)	 	(1,452	)	 	(14,038	)	 	 	
Leasehold acquisition	 	 	—	 	 	—	 	 	—	 	 	(3,831	)	 	 	
Contribution to investment under equity method	 	 	—	 	 	—	 	 	—	 	 	(16,983	)	 	 	
Increase in cash due to acquisition	 	 	—	 	 	—	 	 	—	 	 	893	 	 	 	
Deferred organizational costs	 	 	—	 	 	—	 	 	—	 	 	(773	)	 	 	
Notes receivable	 	 	—	 	 	(52,078	)	 	(61,811	)	 	(113,889	)	 	 	
Restricted cash	 	 	3,200	 	 	(30,000	)	 	(82,000	)	 	(112,000	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net cash used in investing activities	 	 	(156,882	)	 	(500,393	)	 	(589,975	)	 	(1,329,026	)	 	 	
Financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Borrowings under long-term debt	 	 	—	 	 	285,000	 	 	760,000	 	 	1,045,000	 	 	 	
Net proceeds from issuance of units	 	 	332,656	 	 	325,344	 	 	—	 	 	824,986	 	 	 	
Debt issue costs	 	 	(1,572	)	 	(90,649	)	 	(17,315	)	 	(109,536	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by financing activities	 	 	331,084	 	 	519,695	 	 	742,685	 	 	1,760,450	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net increase (decrease) in cash and cash equivalents	 	 	108,531	 	 	(8,289	)	 	(39,090	)	 	100,415	 	 	 	
Cash and cash equivalents at beginning of period	 	 	39,263	 	 	147,794	 	 	139,505	 	 	—	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	 	$	147,794	 	$	139,505	 	$	100,415	 	$	100,415	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Supplemental cash flow information	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash paid for:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Interest	 	$	12	 	$	6,765	 	$	52,472	 	$	59,273	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Income taxes (net of refunds received)	 	$	856	 	$	(65	)	$	762	 	$	1,553	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Non cash activity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Deemed repayment and termination of notes receivable	 	$	—	 	$	—	 	$	90,197	 	$	90,197	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-6

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Consolidated Statements of Comprehensive Loss

	 	 

	 	Period
April 23, 2003
(Inception)
Through
December 31
2010	 	 	
 
	 	Years Ended December 31	 	 	 	 	 	
 
	 	2008	 	2009	 	2010	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	
Net loss	 	$	(48,085	)	$	(79,747	)	$	(245,672	)	$	(482,872	)	 	 	
Other comprehensive income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Change in fair value of cash flow hedges	 	 	—	 	 	—	 	 	(4,838	)	 	(4,838	)	 	 	
 	Loss on cash flow hedge included in operations	 	 	—	 	 	—	 	 	5,426	 	 	5,426	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Other comprehensive income	 	 	—	 	 	—	 	 	588	 	 	588	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Comprehensive loss	 	$	(48,085	)	$	(79,747	)	$	(245,084	)	$	(482,284	)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes.

F-7

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements

1. Organization

        Kosmos Energy Holdings is a privately held Cayman Islands company that was formed March 5, 2004. As a holding company, its management operations are conducted through a wholly-owned subsidiary, Kosmos Energy, LLC. Kosmos Energy, LLC is a privately held Texas limited liability company that was formed April 23, 2003. Kosmos Energy, LLC became a wholly-owned subsidiary of Kosmos Energy Holdings on March 9, 2004. The terms "Kosmos," the "Company," "we," "us," "our," "ours," and similar terms refer to Kosmos Energy Holdings and its wholly-owned subsidiaries, unless the context indicates otherwise. We are an independent oil and gas exploration and production company focused on underexplored regions in Africa.

        We have one business segment which is the exploration and production of oil and natural gas in Africa.

        On August 29, 2003, contributions were made by the seven founding partners in the amount of $350 thousand, for which they received 350,000 units in Kosmos Energy, LLC. On March 9, 2004, the seven founding partners exchanged their 350,000 units in Kosmos Energy, LLC for 3,500,000 units in Kosmos Energy Holdings.

        On October 9, 2009, upon execution and delivery and per Section 1.4 of the Kosmos Energy Holdings Second Amended and Restated Contribution Agreement, the Company issued a total of 2,500,000 C1 common units ("C1 Common Units") to the Series C Convertible Preferred investors. The proceeds of $25 million from the November 2, 2009 issuance of Series C Convertible Preferred Units ("Series C") was allocated on a relative fair value basis between the C1 Common Units and the Series C of $11.8 million and $13.2 million, respectively. See Note 13—Convertible Preferred Units.

        Basic and diluted net loss per common unit holder is not presented since the ownership structure of the Company is not a common unit of ownership.

        As of December 31, 2010, Kosmos Energy Holdings has nine members on the Board of Managers (directors). Warburg Pincus and The Blackstone Group appointed two directors each, one director is a company executive, and there are four independent directors.

        Kosmos Energy Holdings was a development stage entity as of December 31, 2010. In January 2011, we recognized our first revenue from oil production and, as a result we were no longer categorized as a development stage entity beginning in 2011.

2. Accounting Policies

Principles of Consolidation

        The accompanying consolidated financial statements include the accounts of Kosmos Energy Holdings and its wholly-owned subsidiaries. All intercompany transactions have been eliminated.

Use of Estimates

        The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.

F-8

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

Cash and Cash Equivalents

        Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.

Restricted Cash

        At December 31, 2009 and 2010, Kosmos had a total of $30.0 million and $112.0 million of restricted cash on hand included in current and long-term assets. In accordance with our project financing commercial debt facilities agreement, we have the following types of restricted cash on hand: (1) a balance at all times of not less than $30.0 million is required during the year prior to Project Completion of the Jubilee Phase 1 Development (as defined in the agreement); (2) not less than $50.0 million in the Reserve Equity account which may only be withdrawn from the account to pay Jubilee Phase 1 costs under certain circumstances, or after Project Completion is available for withdrawal; and (3) not less than $9.0 million in the Stamp Duty Reserve account which may be utilized to meet any payment of stamp duty taxes in Ghana. We have the option to invest the restricted cash in an account which is satisfactory to the facility agents. As of December 31, 2010, $80.0 million was classified as current to offset maturing debt. This restricted cash will be released after Project Completion in mid-2011. The remaining $9.0 million is included in long-term assets.

        Effective December 30, 2010, Kosmos Energy Finance provided a $23.0 million cash collateralized irrevocable standby Letter of Credit ("LOC") in respect of Kosmos Ghana's Jubilee paying interest share of Tullow Ghana Limited's LOC related to their drilling contract for the Eirik Raude. The LOC expires on September 14, 2011. As of December 31, 2010, the LOC is included in long-term assets as it relates to oil and gas properties.

Receivables

        The Company's receivables consist of joint interest billings, notes and other receivables for which the Company generally does not require collateral security. Receivables from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor's ownership interest in oil and natural gas properties we operate, and the owner's ability to pay its obligation, among other things.

Inventories

        Inventories were comprised of $19.6 million and $25.2 million of materials and supplies and zero and $12.5 million of hydrocarbons as of December 31, 2009 and 2010, respectively. The Company's materials and supplies inventory is primarily comprised of casing and wellheads and is stated at the lower of cost, using the weighted average cost method or market. Write downs of zero and $1.1 million as of December 31, 2009 and 2010, respectively, for materials and supplies were recorded as reductions to the carrying values for materials and supplies inventories in the Company's consolidated balance sheets and as other expenses, net in the accompanying consolidated statement of operations.

        Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or market. Hydrocarbon inventory costs include expenditures and other charges (including depletion) directly and indirectly incurred in bringing the inventory to its existing condition. Selling expenses and general and administration expenses are reported as period costs and excluded from inventory costs.

F-9

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

Exploration and Development Costs

        The Company follows the successful efforts method of accounting for costs incurred in oil and natural gas exploration and production operations. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when proved reserves are found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are charged to expense as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed.

        During the years ended December 31, 2008, 2009 and 2010, Kosmos recognized exploration expense of $15.4 million, $22.1 million and $73.1 million, respectively.

Depletion, Depreciation and Amortization

        Proved properties and support equipment and facilities are depleted using the unit-of-production method based on estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in discovery of proved reserves and development costs are amortized using the unit-of-production method based on estimated proved developed oil and natural gas reserves.

        As of December 31, 2010, depletion costs of $6.4 million are recorded in inventory on the consolidated balance sheets. Oil production commenced on November 28, 2010 and we received revenues from oil production in early 2011 at which time depletion costs were transferred to the consolidated statements of operations.

        Depreciation and amortization of other property is computed using the straight-line method over estimated useful lives ranging from 3 to 7 years.

	 	Years
Depreciated	
Leasehold improvements	 	6	
Office furniture, fixtures and computer equipment	 	3 to 7	
Vehicles	 	5	
        Amortization of debt issue costs is computed using the straight-line method over the life of the related commercial debt facilities. Amortization of other assets is computed using the straight-line method over an estimated useful life of five years.

Capitalized Interest

        Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets.

F-10

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

Asset Retirement Obligations

        The Company accounts for asset retirement obligations as required by the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long-lived asset with an existing asset retirement obligation is acquired, a liability for that obligation shall be recognized at the asset's acquisition date as if that obligation were incurred on that date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long-lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time as accretion expense in the consolidated statement of operations.

Investments in Nonconsolidated Companies

        The Company uses the equity method of accounting for long-term investments for which it owns between 20% and 50% of the investee's outstanding voting shares or has the ability to exercise significant influence over operating and financial policies of the investee. The equity method requires periodic adjustments to the investment account to recognize our proportionate share in the investee's results, reduced by receipt of the investee's dividends.

Variable Interest Entity

        A variable interest entity ("VIE"), as defined by FASB ASC 810—Consolidation, is an entity that by design has insufficient equity to permit it to finance its activities without additional subordinated financial support or equity holders that lack the characteristics of a controlling financial interest. VIE's are consolidated by the primary beneficiary, which is the entity that has the power to direct the activities of the VIE that most significantly impact the VIE's performance and will absorb losses, or receive benefits from the VIE that could potentially be significant to the VIE. Kosmos Energy Finance, a wholly-owned subsidiary whose ultimate parent is Kosmos Energy Holdings, meets the definition of a VIE and the Company is the primary beneficiary. As a result, Kosmos Energy Finance is consolidated in these financial statements. Kosmos Energy Finance's assets and liabilities are shown separately on the face of the consolidated balance sheets in the following line items: current and long-term restricted cash; debt issue costs; long-term derivatives asset; current and long-term debt; and current and long-term derivatives liabilities. Included in cash and cash equivalents is $58.0 million related to Kosmos Energy Finance.

Impairment of Long-Lived Assets

        The Company reviews its long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. FASB ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual

F-11

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long-lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell.

        During 2006, Kosmos recognized an impairment of $3.0 million for the Morocco Boujdour Reconnaissance license which expired in April 2006.

Derivative Instruments and Hedging Activities

        We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of deferred premium puts and compound options (calls on puts). We also use interest rate swap contracts to mitigate our exposure to interest rate fluctuations related to our commercial debt facilities. Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We do not apply hedge accounting to our oil derivative contracts and effective June 1, 2010 discontinued hedge accounting on our interest rate swap contracts and accordingly the changes in the fair value of the instruments are recognized in income in the period of change. See Note 11—Derivative Financial Instruments.

Estimates of Proved Oil and Natural Gas Reserves

        Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are found in the future, estimated reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the SEC and the FASB. The accuracy of these reserve estimates is a function of:

•
the engineering and geological interpretation of available data;

•
estimates regarding the amount and timing of future operating cost, production taxes, development cost and workover cost;

•
the accuracy of various mandated economic assumptions (such as the future prices of oil and natural gas); and

•
the judgments of the persons preparing the estimates.

Revenue Recognition

        We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. Oil production commenced on November 28, 2010 and we

F-12

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

received revenues from oil production in early 2011. As of December 31, 2010, no revenues have been recognized in our financial statements.

Income Taxes

        The Company accounts for income taxes as required by the FASB ASC 740—Income Taxes. Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.

Foreign Currency Translation

        The U.S. dollar is the functional currency for all of the Company's foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are de minimis, and as such, the effect of exchange rate changes is not material to any reporting period.

Profit Units

        The Company issues common units designated as profit units at various times to employees and certain directors with a threshold value of $0.85 to $90. The Company accounts for these units using FASB ASC 718—Compensation—Stock Compensation. The fair value of the profit units is expensed and recognized on a straight-line basis over the vesting periods of the awards. See Note 18—Profit Units.

Employees

        The majority of our full-time employees were leased through TriNet Acquisition Corp. TriNet Acquisition Corp. administered all salaries, benefits and payment of taxes, and billed Kosmos semimonthly for its cost. This contract was cancelled effective September 30, 2010 at which time all full-time employees previously leased through TriNet Acquisition Corp. became employees of the Company.

Recent Accounting Standards

        In June 2009, the FASB issued Statement of Financial Accounting Standards ("SFAS") No. 166, "Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140." This Statement was codified into FASB ASC 860—Transfers and Servicing. This Statement removes the concept of qualifying special purpose entity ("SPE") and the exception for qualifying SPEs from the consolidation guidance. Additionally, the Statement clarifies the requirements for financial asset transfers eligible for sale accounting. The Company adopted this Statement on its effective date, January 1, 2010, and it did not have a material impact on the Company's financial position or results of operations.

F-13

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

        Also in June 2009, the FASB issued SFAS No. 167, "Amendments to FASB Interpretation No. 46(R)," to address the effects of the elimination of the qualifying SPE concept in SFAS No. 166, and other concerns about the application of key provisions of consolidation guidance for VIEs. This Statement was codified into FASB ASC 810—Consolidation. More specifically, SFAS No. 167 requires a qualitative rather than a quantitative approach to determine the primary beneficiary of a VIE, it amends certain guidance pertaining to the determination of the primary beneficiary when related parities are involved, and it amends certain guidance for determining whether an entity is a VIE. Additionally, this Statement requires continuous assessments of whether an enterprise is the primary beneficiary of a VIE. The Company adopted this Statement on its effective date, January 1, 2010, and it did not have a material impact on the Company's financial position or results of operations.

        In January 2010, the FASB issued Accounting Standards Update ("ASU") No. 2010-03—Oil and Gas Reserve Estimation and Disclosures. This ASU amends the FASB's ASC Topic 932—Extractive Activities—Oil and Gas to align the accounting requirements of this topic with the Securities and Exchange Commission's final rule, "Modernization of the Oil and Gas Reporting Requirements" issued on December 31, 2008. In summary, the revisions in ASU No. 2010-03 modernize the disclosure rules to better align with current industry practices and expand the disclosure requirements for equity method investments so that more useful information is provided. More specifically, the main provisions include the following:

•
An expanded definition of oil and gas producing activities to include nontraditional resources such as bitumen extracted from oil sands.

•
The use of an average of the first-day-of-the-month price for the 12-month period, rather than a year-end price for determining whether reserves can be produced economically.

•
Amended definitions of key terms such as "reliable technology" and "reasonable certainty" which are used in estimating proved oil and gas reserve quantities.

•
A requirement for disclosing separate information about reserve quantities and financial statement amounts for geographical areas representing 15 percent or more of proved reserves.

•
Clarification that an entity's equity investments must be considered in determining whether it has significant oil and gas activities and a requirement to disclose equity method investments in the same level of detail as is required for consolidated investments.

        ASU No. 2010-03 is effective for annual reporting periods ended on or after December 31, 2009, and it requires (1) the effect of the adoption to be included within each of the dollar amounts and quantities disclosed, (2) qualitative and quantitative disclosure of the estimated effect of adoption on each of the dollar amounts and quantities disclosed, if significant and practical to estimate and (3) the effect of adoption on the financial statements, if significant and practical to estimate. Adoption of these requirements did not significantly impact our reported reserves or our consolidated financial statements.

        In January 2010, the FASB issued ASU No. 2010-06—Improving Disclosures and Fair Value Measurements to improve disclosure requirements and thereby increase transparency in financial reporting. We adopted the update as of December 31, 2009, and it did not have a material impact on our financial position or results of operations.

F-14

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

3. Investment and Acquisition—Pioneer Natural Resources (Nigeria) 320 Limited

        In 2005, the Company acquired, through its wholly-owned subsidiary PNR Nigeria (320) Limited (subsequently renamed Kosmos Energy Nigeria (320) Limited), a 41.17647% interest in Pioneer Natural Resources (Nigeria) 320 Limited (subsequently renamed Kosmos Energy Deepwater Nigeria Limited—"KEDNL"). Between 2005 and 2007, Kosmos made capital contributions on its investment of $17.0 million. On July 16, 2007, Pioneer Natural Resources announced its decision to divest its interest in the OPL 320 block offshore Nigeria and took a charge on its investment. Kosmos recognized an impairment in 2006 of $4.0 million of its investment in Pioneer Natural Resources (Nigeria) 320 Limited, bringing its balance to zero.

        In September 2007, the Company, per an agreement with PNR Nigeria, acquired PNR Nigeria's interest in KEDNL. Kosmos Energy NHC I, a subsidiary of Kosmos Energy Holdings, now indirectly holds 100% of the stock of KEDNL. The transaction was accounted for as a business combination. No goodwill was recorded as a result of this transaction and no consideration was paid. The fair value of the assets obtained, consisting of cash, prepaid expenses and property and equipment was $2.1 million. The fair value of the accrued liabilities assumed was $2.1 million.

        On June 29, 2009, Kosmos provided notice of its withdrawal from OPL 320 to the Nigerian government and its block partners. The effective date of the withdrawal was July 31, 2009. All of the Company's Nigerian subsidiaries were dissolved as of November 16, 2010.

4. Notes Receivable

        During the fourth quarter of 2009, Kosmos Energy Ghana HC ("Kosmos Ghana") entered into four participation agreements totaling $185.0 million with Tullow Group Services Limited ("TGSL"). The participation agreements allowed Kosmos Ghana to participate in TGSL's advances to MODEC, Inc. ("MODEC") to fund the construction of the floating production, storage and offloading ("FPSO") facility. The FPSO facility is now connected to the Jubilee Field. The amounts loaned to TGSL were recorded as short-term notes receivables and accrued interest at rates between 3.74% and 3.78% per annum. The total participation limit for Kosmos Ghana was $52.1 million which was fully funded as of December 31, 2009. Also, included in the notes receivable balance at December 31, 2009, was total interest income of $0.2 million for the year then ended. Effective May 7, 2010, the loan agreements and associated participation agreements were deemed paid and terminated under the Advance Payments Agreement discussed below.

        Effective May 7, 2010, Tullow Ghana Limited ("TGL"), acting on behalf of the Unitization and Unit Operating Agreement ("UUOA") parties, entered into the Advance Payments Agreement with MODEC related to partially financing the construction of the FPSO facility. The payments limit for the Advance Payments Agreement is $466.3 million of which Kosmos Ghana's share is $122.2 million. Of the $466.3 million, a total of $341.1 million was deemed to have been advanced from TGL to MODEC. This amount included $188.9 million, principal and interest, related to the loan agreements, $127.3 million representing cash calls made between January 2010 and May 7, 2010, by MODEC to TGL under the Letter of Intent and $25.0 million representing the payment made by TGL for the variation order request 025 dated January 15, 2010, to enable MODEC to pay fees in connection with its long-term financing. MODEC is required to repay TGL the earlier of September 15, 2011 or the date of the first drawdown under MODEC's long-term financing. TGL is required, based on the terms of the joint operating agreement for the Jubilee Unit, to reimburse us the amounts MODEC reimburses to TGL within ten business days of repayment by MODEC. As of December 31, 2010,

F-15

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

4. Notes Receivable (Continued)

Kosmos Ghana's share of the payments made under the Advance Payments Agreement is $113.9 million (includes accrued interest of $0.3 million) and is recorded as notes receivable.

5. Jubilee Field Unitization

        The Jubilee Field in Ghana, discovered by the Mahogany-1 well in June 2007, covers an area within both the West Cape Three Points ("WCTP") and Deepwater Tano ("DT") Blocks. Consistent with the Ghanaian Petroleum Law, the WCTP and DT Petroleum Agreements and as required Ghana's Ministry of Energy, it was agreed the Jubilee Field would be unitized for optimal resource recovery. In late February 2008, the contractors in the WCTP and DT Blocks agreed to an interim unit agreement ("the Pre Unit Agreement"). According to the Pre Unit Agreement, the initial Jubilee Field unit area, which boundary at the time was an approximation of the boundaries of the Jubilee field, was deemed to consist of 35% of an area from the WCTP Block and 65% of an area from the DT Block. However, the tract participations were allocated 50% for the WCTP Block and 50% for the DT Block pending the results of the Mahogany-2 well. The Mahogany-2 well was announced as an oil discovery on May 5, 2008. Pursuant to the Pre Unit Agreement, the unit boundaries were modified to include the Mahogany-2 well and the tract participations remained 50% for each block. Pursuant to the Pre Unit Agreement, Kosmos Ghana, Tullow Ghana Limited, Anadarko WCTP Company, Sabre Oil & Gas Holdings Limited, EO Group Limited ("EO Group") and Ghana National Petroleum Corporation's ("GNPC") unit participating interests were 24.4375%, 36.423%, 24.4375%, 2.952%, 1.75% and 10%, respectively.

        Kosmos Ghana and its partners subsequently commenced development operations and negotiated a more comprehensive unit agreement, the UUOA, for the purpose of unitizing the Jubilee Field and governing each party's respective rights and duties in the Jubilee Unit. On July 13, 2009, the Ministry of Energy provided its written approval of the UUOA. The UUOA was executed by all parties and was effective as of July 16, 2009, the date the final condition precedent to effectiveness was satisfied. As a result, for the Jubilee Unit, based on existing tract allocations (50% for each Block), and GNPC electing to acquire their additional paying interest under both the WCTP and DT Blocks, Kosmos Ghana, Tullow Ghana Limited, Anadarko WCTP Company, Sabre Oil & Gas Holdings Limited, EO Group and GNPC's unit participating interest became 23.4913%, 34.7047%, 23.4913%, 2.8127%, 1.75% and 13.75%, respectively. Tullow Ghana Limited, a subsidiary of Tullow Oil plc, is the Unit Operator, while Kosmos Ghana is the Technical Operator for the development of the Jubilee Unit. The accounting for the Jubilee Unit included in these consolidated financial statements is in accordance with the tract participation stated in the UUOA, which is 50% for WCTP Block and 50% for the DT Block. Although the Jubilee Field is unitized, Kosmos Ghana's working interests in each block outside the boundary of the Jubilee Unit area remains the same. Kosmos Ghana remains operator of the WCTP Block outside the Jubilee Unit area.

        Pursuant to the requirements of the WCTP and DT Petroleum Agreements, Kosmos Ghana (for the WCTP Block) and Tullow Ghana Limited (for the DT Block) submitted a declaration of commerciality for each block and a plan for the initial phase of development of the Jubilee Field ("Jubilee PoD") to Ghana's Ministry of Energy in late 2008. A declaration of commerciality is a formal designation made pursuant to each of the Petroleum Agreements. Pursuant to discussions between Jubilee Unit partners, GNPC and the Ministry of Energy, the contractor parties for the two blocks resubmitted a revised Jubilee PoD to GNPC who then submitted it to the Ministry of Energy for

F-16

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

5. Jubilee Field Unitization (Continued)

approval in April 2009. On July 13, 2009, the Ministry of Energy provided its written approval of the Jubilee Field Phase 1 Development Plan. Jubilee Field development operations are ongoing.

6. Joint Interest Billings

        The Company's joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. EO Group's share of costs to first production were paid by Kosmos Ghana. EO Group is required to reimburse Kosmos Ghana for all development costs paid by Kosmos Ghana on EO Group's behalf, with repayment expected to be funded through EO Group's future production revenues. The related receivable of $61.7 million became due upon commencement of production. In August 2009, GNPC notified us and our applicable unit partners that it would exercise its right for the applicable contractor group to pay its 2.5% WCTP Block share and 5.0% DT Block share of the Jubilee Field development costs and be reimbursed for such costs plus interest out of a portion of GNPC's production revenues under the terms of the WCTP Petroleum Agreement and DT Petroleum Agreement, respectively. Oil production commenced on November 28, 2010. Joint interest billings are classified on the face of the consolidated balance sheets between current and long-term based on when recovery is expected to occur. Long-term balances of $41.6 million and $21.9 million are shown net of allowances of zero and $39.8 million as of December 31, 2009 and 2010, respectively.

7. Property and Equipment

        Property and equipment is stated at cost and consisted of the following:

	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Oil and gas properties, net:	 	 	 	 	 	 	 	
 	Proved properties	 	$	251,814	 	$	426,831	 	
 	Unproved properties	 	 	128,557	 	 	198,149	 	
 	Support equipment and facilities	 	 	214,720	 	 	371,319	 	
 	Less: accumulated depletion	 	 	—	 	 	(6,430	)	
 	 	 	 	 	 	
 	 	$	595,091	 	$	989,869	 	
 	 	 	 	 	 	
Other property, net:	 	 	 	 	 	 	 	
 	Leasehold improvements	 	$	5,041	 	$	4,978	 	
 	Computer equipment and software	 	 	3,539	 	 	4,947	 	
 	Office equipment and furniture	 	 	3,529	 	 	3,549	 	
 	Less: accumulated depreciation	 	 	(3,193	)	 	(5,343	)	
 	 	 	 	 	 	
 	 	$	8,916	 	$	8,131	 	
 	 	 	 	 	 	
        The Company recorded $0.6 million, $1.9 million and $2.2 million of depreciation expense for the years ended December 31, 2008, 2009 and 2010, respectively.

F-17

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

8. Suspended Well Costs

        The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or is impaired. The capitalized exploratory well costs are presented in oil and gas properties in the consolidated balance sheets. If the exploratory well is determined to be impaired, the well costs are charged to expense.

        The following table reflects the Company's capitalized exploratory well activities during the years ended December 31, 2008, 2009 and 2010, respectively. The table excludes costs related to exploratory dry holes of $56.0 million which were incurred and subsequently expensed in 2010.

	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Beginning balance	 	$	11,938	 	$	71,883	 	$	114,307	 	
Additions to capitalized exploratory well costs pending the determination of proved reserves	 	 	59,945	 	 	508,197	 	 	55,706	 	
Reclassification due to determination of proved reserves	 	 	—	 	 	(465,773	)	 	—	 	
Capitalized exploratory well costs charged to expense	 	 	—	 	 	—	 	 	(2,502	)	
 	 	 	 	 	 	 	 	
Ending balance	 	$	71,883	 	$	114,307	 	$	167,511	 	
 	 	 	 	 	 	 	 	
        The following table provides aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands, except well counts)
	 	
Exploratory well costs capitalized for a period of one year or less	 	$	59,945	 	$	91,909	 	$	49,022	 	
Exploratory well costs capitalized for a period greater than one year	 	 	11,938	 	 	22,398	 	 	118,489	 	
 	 	 	 	 	 	 	 	
Ending balance	 	$	71,883	 	$	114,307	 	$	167,511	 	
 	 	 	 	 	 	 	 	
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	 	 	2	 	 	1	 	 	6	 	
 	 	 	 	 	 	 	 	
        As of December 31, 2010, the exploratory well costs capitalized in excess of one year since the completion of drilling relate to the Odum-1, Odum-2, Mahogany-3, Mahogany-4 and Mahogany Deep-2 exploration wells in the WCTP Block and Tweneboa-1 well in the DT Block. All costs incurred are approximately one to two years old.

        Odum Discovery—Results of the Odum-2 well drilled during late 2009 indicate that additional evaluation and studies, including the identification of nearby prospects, is required before making a decision on whether the Odum field can be declared as a commercial discovery. Due to the technical challenges presented by the gravity of the oil encountered to date, development planning is ongoing under Article 8.17 of the WCTP Petroleum Agreement which, in certain circumstances, allows additional time for further evaluation, studies, planning and potential well operations, including exploration activities. Provided the technical solutions can be properly engineered, a declaration of commerciality may be submitted for the Odum discovery by July 2011 with a plan of development submittal within the subsequent six months.

F-18

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

8. Suspended Well Costs (Continued)

        Mahogany East Area—Three appraisal wells, Mahogany-4, Mahogany-5 and Mahogany Deep-2, have been drilled and suspended. The Mahogany Deep reservoir and the reservoirs encountered in the appraisal section of the Mahogany-3 well will be included in the Mahogany East Field. The Mahogany East Area was declared commercial on September 6, 2010, and a plan of development is currently being prepared for submission to Ghana's Ministry of Energy in early 2011.

        Tweneboa Discovery—Two appraisal wells, Tweneboa-2 and Tweneboa-3, have been drilled and suspended. Following additional appraisal, drilling and evaluation, a decision regarding commerciality of the Tweneboa discovery is expected to be made by the DT block partners in 2012. Following such a declaration, a plan of development would be prepared for submission to Ghana's Ministry of Energy within six months.

9. Accounts Payable and Accrued Liabilities

        At December 31, 2009 and 2010, $97.8 million and $163.5 million were recorded for invoices received but not paid in 2009 and 2010, respectively. Accrued liabilities were $41.8 million and $53.2 million at December 31, 2009 and 2010, respectively. Accrued liabilities consist of the following:

	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Accrued liabilities:	 	 	 	 	 	 	 	
 	Accrued exploration and development	 	$	34,723	 	$	26,843	 	
 	Accrued general and administrative expenses	 	 	2,236	 	 	23,393	 	
 	Accrued debt issue costs	 	 	3,232	 	 	—	 	
 	Taxes other than income	 	 	979	 	 	1,936	 	
 	Accrued interest	 	 	—	 	 	655	 	
 	Income taxes	 	 	640	 	 	381	 	
 	 	 	 	 	 	
 	 	$	41,810	 	$	53,208	 	
 	 	 	 	 	 	
10. Commercial Debt Facilities

        On July 13, 2009, Kosmos signed definitive documentation for $750 million project finance commercial debt facilities. The security package for the facilities included, among other things and subject to necessary consents, a pledge collateralization over the shares of the Company's subsidiaries, Kosmos Energy Development and Kosmos Ghana, and an assignment by way of security of their interest in the WCTP and DT Petroleum Agreements. The facilities were amended effective October 29, 2009, by revising the conditions precedent to initial utilization by putting in place an alternative security package that included a charge over the shares of additional subsidiaries of the Company. The Company completed an internal reorganization that included the interposition of a new subsidiary, Kosmos Energy Operating ("KEO"), between Kosmos Energy Holdings and the following subsidiaries: Kosmos Energy International, Kosmos Energy Development, Kosmos Ghana, Kosmos Energy Finance, Kosmos Energy Offshore Morocco HC, Kosmos Energy Cameroon HC, Longhorn Offshore Drilling Ltd. and Kosmos Energy Cote d'Ivoire. Kosmos Energy Holdings granted a charge over the shares of KEO to the lenders in order to secure the facilities. The facilities were further amended on December 24, 2009, increasing the total commercial debt facilities for up to $900.0 million,

F-19

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

10. Commercial Debt Facilities (Continued)

($825.0 million was committed as of December 31, 2009) and adding a new lender as a party to the facilities agreement. On March 31, 2010, Kosmos delivered a request notice to the senior facility agent to increase the commitment under the commercial debt facilities for the remaining $75.0 million by adding a new lender. The conditions set forth in the commercial debt facilities were met and both the increase and new lender were approved as of April 27, 2010. Effective August 23, 2010, the Company signed definitive documentation to increase the facilities by $350.0 million, raising the total amount of its debt commitments to $1.25 billion.

        The revised $1.25 billion of commercial debt facilities are divided among a senior facility of $950.0 million, a junior facility of $200.0 million and additional facilities of $100.0 million ($50.0 million senior facility and $50.0 million junior facility) from the International Finance Corporation ("IFC"), a member of the World Bank Group. The senior and junior facilities of $950.0 million and $200.0 million include a syndicate of institutions led by Standard Chartered Bank, the Global Coordinator for the facilities. Standard Chartered Bank is also the Co-Technical and Modeling Bank and Senior Facility Agent, BNP Paribas SA is the Security Trustee, Junior Facility Agent, and has the role of Hedging Coordinator Bank, and Société Générale is the Lead Technical and Modeling Bank. The senior facilities have a final maturity date of December 15, 2015, while the junior facilities have a final maturity date of June 15, 2016.

        The amount of funds available to be borrowed under the senior facilities, the Borrowing Base Amount, is determined twice a year on June 15 and December 15 of each year as part of the Forecast that is prepared and agreed by the Company and the Technical and Modeling Banks. The formula to calculate the Borrowing Base Amount is based, in part, on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages. As of December 31, 2010, borrowings against the commercial debt facilities totaled $1.05 billion, of which $970.0 million is senior debt and $75.0 million is junior debt. As of December 31, 2010, the availability under our commercial debt facilities was $203.0 million, with $205.0 million of committed undrawn capacity provided for in such facilities (with the difference being the result of borrowing base constraints). See Note 21—Subsequent Events.

        The interest is the aggregate of the applicable margin (5% to 6% on the senior facilities and 9% to 9.5% on the junior facilities); LIBOR; and mandatory cost (if any, as defined in the relevant documentation). Interest on each loan is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). The Company pays commitment fees on the undrawn and uncancelled portion of the total commitments. Commitment fees for the senior and junior lenders are equal to 50% per annum of the then applicable respective margin. Interest expense was $2.0 million and $39.0 million (net of capitalized interest of $0.6 million and $9.8 million) and commitment fees were $4.8 million and $8.2 million for the years ended December 31, 2009 and 2010, respectively.

        Certain facilities contain certain financial covenants, which include:

•
Before project completion, maintenance of the funding sufficiency ratio, not less than 1:1x; and;

•
After project completion, maintenance of:

          (i)  the debt service coverage ratio, not less than 1.2x;

F-20

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. We have recorded an asset retirement obligation for fields that have commenced production, including wells in progress in such fields. Accordingly, the Company recognized a liability in the quarterly period ending December 31, 2010 related to our asset retirement obligations.

13. Convertible Preferred Units

        On February 11, 2004, under the Kosmos Energy Holdings Contribution Agreement, Kosmos received provisional commitments of up to $300.0 million from Warburg Pincus, The Blackstone Group, the management group, certain accredited employee investors and directors, to pursue the acquisition, exploration and development of oil and gas ventures in West Africa. For each $10 contribution, one Series A Convertible Preferred Unit ("Series A") was issued. Contributions began on March 9, 2004.

        On June 18, 2008, under the Kosmos Energy Holdings Amended and Restated Contribution Agreement, Kosmos secured an additional provisional commitment of up to $500.0 million from Warburg Pincus, The Blackstone Group, the management group, certain accredited employee investors and directors. For each $25 contribution, one Series B Convertible Preferred Unit ("Series B") was issued. Contributions began on November 3, 2008.

        On October 9, 2009, under the Kosmos Energy Holdings Second Amended and Restated Contribution Agreement, Kosmos secured an additional provisional commitment of up to $250.0 million from Warburg Pincus, The Blackstone Group, the management group, certain accredited employee investors and directors. For each $28.25 contribution, one Series C was issued. Contributions began on November 2, 2009. Upon execution and delivery and per Section 1.4 of the Kosmos Energy

F-26

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

13. Convertible Preferred Units (Continued)

Holdings Second Amended and Restated Contribution Agreement, the Company issued a total of 2,500,000 C1 Common Units to the Series C investors. The proceeds from the Series C issuance were allocated on a relative fair value basis between the Series C and the C1 Common Units, which created a discount on the Series C of approximately $11.8 million. The discount on the Series C has been recorded as of December 31, 2010, the date at which a determination was made that it was probable that an exchange of securities for common shares would occur.

        Series A, Series B and Series C contributions and the accumulated preferred return were as follows (in thousands, including unit data):

	 	Warburg Pincus	 	The Blackstone
Group	 	Other Investors	 	Total	 	
Series A:	 	 	 	 	 	 	 	 	 	 	 	 	 	
2004 Issuance of 1,100 units	 	$	5,958	 	$	4,875	 	$	167	 	$	11,000	 	
2005 Retirement of 6 units	 	 	—	 	 	—	 	 	(63	)	 	(63	)	
2005 Issuance of 3,100 units	 	 	16,551	 	 	13,542	 	 	907	 	 	31,000	 	
2006 Retirement of 9 units	 	 	—	 	 	—	 	 	(85	)	 	(85	)	
2006 Issuance of 2,010 units	 	 	10,775	 	 	8,815	 	 	510	 	 	20,100	 	
2007 Issuance of 10,505 units	 	 	56,506	 	 	46,232	 	 	2,310	 	 	105,048	 	
2008 Issuance of 13,300 units	 	 	71,508	 	 	58,508	 	 	2,984	 	 	133,000	 	
Accumulated preferred return	 	 	44,758	 	 	36,621	 	 	1,867	 	 	83,246	 	
 	 	 	 	 	 	 	 	 	 	
Total Issuances—Series A	 	$	206,056	 	$	168,593	 	$	8,597	 	$	383,246	 	
 	 	 	 	 	 	 	 	 	 	
Series B:	 	 	 	 	 	 	 	 	 	 	 	 	 	
2008 Issuance of 7,986 units	 	$	107,718	 	$	88,132	 	$	3,806	 	$	199,656	 	
2009 Issuances of 12,014 units	 	 	161,576	 	 	132,199	 	 	6,569	 	 	300,344	 	
Accumulated preferred return	 	 	36,712	 	 	30,037	 	 	1,414	 	 	68,163	 	
 	 	 	 	 	 	 	 	 	 	
Total Issuances—Series B	 	$	306,006	 	$	250,368	 	$	11,789	 	$	568,163	 	
 	 	 	 	 	 	 	 	 	 	
Series C:	 	 	 	 	 	 	 	 	 	 	 	 	 	
November 2, 2009 Issuance of 885 units	 	$	7,126	 	$	5,830	 	$	288	 	$	13,244	 	
Accretion	 	 	6,325	 	 	5,175	 	 	256	 	 	11,756	 	
Accumulated preferred return	 	 	1,128	 	 	923	 	 	46	 	 	2,097	 	
 	 	 	 	 	 	 	 	 	 	
Total Issuances—Series C	 	$	14,579	 	$	11,928	 	$	590	 	$	27,097	 	
 	 	 	 	 	 	 	 	 	 	
        Under the Fourth Amended and Restated Operating Agreement of Kosmos Energy Holdings (the "Agreement") governing the Company, the holders of the Series A, Series B and Series C (collectively, "Convertible Preferred Units") would receive distributions, if any, equal to the "Accreted Value" of the units, prior to any distributions to the common unit holders. The Accreted Value is defined in the Agreement as the unit purchase price plus the preferred return amount per unit equal to 7% of the Accreted Value per annum (compounded quarterly) for the first seven years after the year of our initial operating agreement and 14% of the Accreted Value per annum (compounded quarterly) thereafter, unless a monetization event (as defined in the Agreement) occurs at which time the preferred return would revert to 7%. The holders of the Convertible Preferred Units will receive the accumulated preferred return upon the consummation of a "Qualified Public Offering" as defined in the Agreement. The accumulated preferred return on the Convertible Preferred Units has been recorded as of December 31, 2010, the date at which a determination was made that it was probable that an exchange

F-27

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

13. Convertible Preferred Units (Continued)

of securities for common shares would occur. The amount was applied to additional paid-in capital first, with the remaining amount applied to the deficit accumulated during development stage.

        Distributions to the unit holders would be made in the following order of priority. First, the entire preferred return amount related to the Convertible Preferred Units; then, the purchase price for each Convertible Preferred Unit would be distributed to the Convertible Preferred Unit holders. Any remaining amounts would be distributed to all unit holders in accordance with their respective percentage interests provided the threshold value of the unit was met. The Series A threshold value is zero; therefore, they would begin participation immediately. The Series B and Series C threshold values are $15 and $18.25, respectively. The common units' threshold values are zero for the management units, $18.25 for the C1 Common Units and range from $0.85 to $90 for the profit units. Such units would begin participation in any distribution after their respective threshold value was met.

        Upon and immediately prior to the consummation of a Qualified Public Offering, each outstanding Common Unit and each outstanding Convertible Preferred Unit would be exchanged (at values determined in the Agreement) into common shares and preferred shares, respectively, of the "IPO Corporation," as defined in the Agreement. Each preferred share of the IPO Corporation would be exchanged for a combination of cash or common shares of the IPO Corporation equal to the accreted value at the option of the unit holders plus common shares of the IPO Corporation based on the provisions of the Agreement. The Convertible Preferred Units are classified as mezzanine equity as the Company cannot solely control the type of consideration issuable on the exchange and the Convertible Preferred Unit holders control the Company's Board of Directors.

14. Other Income

        Other income consists primarily of technical service fees and overhead expenses billed to third parties for the Jubilee Field per the Pre Unit Agreement through July 13, 2009, and subsequently the UUOA. The expenses associated with these third-party billings are recorded within the general and administrative expense line item in the accompanying consolidated financial statements. Other income under this agreement was $6.0 million, $9.6 million and $5.1 million for the years ended December 31, 2008, 2009 and 2010, respectively.

15. Fair Value Measurements

        In accordance with the FASB ASC 820—Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

•
Level 1—quoted prices for identical assets or liabilities in active markets.

•
Level 2—quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted

F-28

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.

        The Company had net deferred tax assets in Ghana totaling approximately $20.6 million at December 31, 2009 primarily relating to capitalized operating expenses incurred during the development phase of the Jubilee Field. Prior to the commencement of production from the Jubilee Field on November 28, 2010, the Company maintained a full valuation allowance against its deferred tax asset. However, at December 31, 2010, the Company determined that it was more likely than not that the deferred tax asset for its Ghana operations would be recognized, resulting in the valuation allowance no longer being necessary. Therefore, we released the $20.6 million deferred tax asset valuation allowance and recognized $56.9 million of deferred tax assets generated during 2010. The factors that the Company considered are discussed below and concluded that many of the considerations that previously led to the need for a valuation allowance related to the Ghana deferred tax assets no longer exist as of December 31, 2010, as the Company had begun production. The net change in the valuation allowance of $3.6 million is due to the release of the Ghana valuation allowance netted against current year activity in Morocco and Cameroon.

        Additionally, in 2010, with the commencement of oil production in Ghana, the Company began to amortize its pre-operating development costs related to the Jubilee Field over a five-year period for tax purposes in accordance with Ghanaian tax law.

        In determining that a valuation allowance was not needed for the Ghanaian deferred tax assets at December 31, 2010 we considered the requirements of ASC 740, including that all evidence, both

F-32

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

16. Income Taxes (Continued)

positive and negative, should be considered to determine whether, based on all the weight of the available evidence, it is more-likely-than-not a deferred tax asset will or will not be realized. If it is more-likely-than-not that the deferred tax asset will be realized, a valuation allowance is not needed. In performing this assessment for the Ghanaian deferred tax assets, the Company determined that the factors that led to the creation of deferred tax assets while operating as a development stage entity changed significantly when the Company moved into the production phase. Accordingly, the Company believes that, considering the facts and circumstances, the negative evidence of the cumulative tax losses incurred during the development stage is overcome by the following positive evidence relating to our ability to more-likely-than-not realize the deferred tax assets in Ghana:

•
The commencement of oil production on November 28, 2010. Equipment and infrastructure was fully in place in the fourth quarter of 2010 immediately prior to production commencing, and the November 2010 successful commencement of production confirmed our expectations that these assets could be utilized to successfully produce from the field with an economical cost structure.

•
The recognition of our first revenues from oil production in January 2011. The Company was a development stage entity as of December 31, 2010, but upon recognition of our first revenues in January 2011, is no longer categorized as such.

•
The existence of significant proved reserves that have been independently verified.

•
The Company produces a commodity (crude oil) with observable market demand capable of purchasing all barrels produced. Prices for oil can be estimated with reasonable certainty through forward pricing curves.

•
The ability to recover our deferred tax assets based on our projections of taxable income for 2011 and future years. Production volumes utilized in our projection are based on our proved reserve estimates, which have been independently verified and our schedule for production which has been approved by the Jubilee Unit partners and, to date, has matched actual production volumes achieved since first oil production commencement on November 28, 2010. Such schedule anticipates that the FPSO producing from the field will reach its maximum production capacity in the third quarter of 2011. Prices have been estimated based on prices utilized to calculate our standardized measure as of December 31, 2010. Additionally, we have estimated our expenses based on current contracts and cost structures in place. Based on our current production plan and a price per barrel of $79.35, which is also used to calculate our standardized measure, we anticipate realization of the net operating loss carryforward by the end of 2012. If we utilize current production plans and March 2, 2011 crude oil prices, we will realize the deferred tax assets.

•
The excess of appreciated asset value over the tax basis of our Ghanaian net assets of an amount sufficient to realize the deferred tax asset. Our estimates of the excess of the appreciated asset value were based upon the independently verified reserve report, third party offers for our Ghana assets, and other market indicators.

•
We tested the sensitivity of our projection of taxable income to changes in production volumes and prices, which indicated that future taxable income was sufficient to recover the deferred tax assets under various scenarios.

F-33

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

16. Income Taxes (Continued)

•
There is an unlimited NOL carryforward period under Ghanaian tax law, which provides flexibility in utilization of the net operating loss.

        ASC 740 provides a more-likely-than-not standard in evaluating whether a valuation allowance is necessary after weighing all of the available evidence. Using the more-likely-than-not standard and weighing all available positive and negative evidence, the Company concluded that the positive evidence outweighs the negative evidence of cumulative tax losses incurred during the development stage. Accordingly, we determined that it is more likely than not that the deferred tax asset for our Ghanaian operations would be realized and, therefore, released the $20.6 million valuation allowance that was recorded as of December 31, 2009 and recognized $56.9 million of deferred tax assets generated during 2010.

        The Company entered into the Boujdour Offshore Petroleum Agreement in May 2006. This agreement provides for a tax holiday, at a 0% tax rate, for a period of 10 years beginning on the date of first production from the Boujdour Offshore Block. The Company currently has recorded deferred tax assets of $6.8 million, recorded at the Moroccan statutory rate of 30%, with an offsetting valuation allowance of $6.8 million. Once the Company enters into the tax holiday period (when production begins) it will re-evaluate its deferred tax position and at such time may reduce the statutory rate applied to the deferred tax assets in Morocco to the extent those deferred tax assets are realized within the tax holiday period.

        The Company has foreign net operating loss carryforwards of approximately $58.9 million which begin to expire in 2011 through 2015 and approximately $298.6 million which do not expire.

        Effective January 1, 2009, the Company adopted the provisions of the FASB ASC 740—Income Taxes which clarifies the accounting for and disclosure of uncertainty in tax positions. Additionally, this standard provides guidance on the recognition, measurement, derecognition, classification and disclosure of tax positions and on the accounting for related interest and penalties. As a result of the implementation of this standard, the Company recognized no material adjustment for unrecognized income tax benefits. In addition, there were no material unrecognized income tax benefits recognized during the current year.

        The Company files a U.S. federal income tax return and a Texas margin tax return. In addition to the United States, the Company files income tax returns in the countries in which the Company operates. The Company is open to U.S. federal income tax examinations for tax years 2007 through 2010 and to Texas margin tax examinations for the tax years 2006 through 2010. In addition the Company is open to income tax examinations for years 2004 through 2010 in its significant foreign jurisdictions (Ghana, Cameroon and Morocco).

        The Company's policy is to recognize potential interest and penalties related to income tax matters in income tax expense, but has had no need to accrue any to date.

        During 2007, the Company settled an examination by the Internal Revenue Service. The settlement resulted in an adjustment that eliminated the domestic net operating loss carryforward. The Company was required to pay $137 thousand of additional tax related to the exam of the 2005 and 2006 federal income tax returns.

F-34

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

17. 401(k) Plan

        As of July 2007, the Company offers a 401(k) Plan to which employees may contribute tax deferred earnings subject to Internal Revenue Service limitations. Employee contributions of up to 6% of compensation, as defined by the plan, is matched by the Company at 100%. The Company's match is vested immediately. Matching contributions made by the Company to the 401(k) Plan were approximately $315 thousand, $550 thousand and $668 thousand for the years ended December 31, 2008, 2009 and 2010, respectively.

18. Profit Units

        Kosmos issues common units designated as profit units with a threshold value of $0.85 to $90 to employees, management and directors. Profit units, the defined term in the related agreements, are equity awards that are measured on the grant date and expensed over a vesting period of four years. Founding management and directors vest 20% as of the date of issuance and an additional 20% on the anniversary date for each of the next four years. Profit units issued to employees vest 50% on the second and fourth anniversary of the issuance date. Of the 100 million authorized common units, 15.7 million are designated as profit units. The following is a summary of the Company's profit unit activity:

	 	Profit Units	 	Weighted-Average
Grant-Date
Fair Value	 	
 
	 	(In thousands)

Outstanding at December 31, 2007	 	 	3,984	 	$	0.13	 	
 	Granted	 	 	9,595	 	 	1.11	 	
 	Relinquished	 	 	(67	)	 	1.52	 	
 	 	 	 	 	 	 	
Outstanding at December 31, 2008	 	 	13,512	 	 	0.82	 	
 	Granted	 	 	10	 	 	2.94	 	
 	Relinquished	 	 	(15	)	 	3.05	 	
 	 	 	 	 	 	 	
Outstanding at December 31, 2009	 	 	13,507	 	 	0.81	 	
 	Granted	 	 	411	 	 	5.27	 	
 	Relinquished	 	 	(8	)	 	2.45	 	
 	 	 	 	 	 	 	
Outstanding December 31, 2010	 	 	13,910	 	 	1.76	 	
 	 	 	 	 	 	 	
F-35

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

18. Profit Units (Continued)

        A summary of the status of the Company's non-vested profit units is as follows:

	 	Profit Units	 	Weighted-Average
Grant-Date
Fair Value	 	
 
	 	(In thousands)

Non-vested at December 31, 2007	 	 	2,080	 	$	0.22	 	
 	Granted	 	 	9,595	 	 	1.11	 	
 	Vested	 	 	(2,659	)	 	0.66	 	
 	Relinquished	 	 	(67	)	 	1.52	 	
 	 	 	 	 	 	 	
Non-vested at December 31, 2008	 	 	8,949	 	 	1.03	 	
 	Granted	 	 	10	 	 	2.94	 	
 	Vested	 	 	(2,000	)	 	0.90	 	
 	Relinquished	 	 	(15	)	 	3.05	 	
 	Other	 	 	13	 	 	0.02	 	
 	 	 	 	 	 	 	
Non-vested at December 31, 2009	 	 	6,957	 	 	1.06	 	
 	Granted	 	 	411	 	 	5.27	 	
 	Vested	 	 	(2,719	)	 	1.03	 	
 	Relinquished	 	 	(8	)	 	2.45	 	
 	Accelerated vesting	 	 	(1,177	)	 	10.66	 	
 	 	 	 	 	 	 	
Non-vested at December 31, 2010	 	 	3,464	 	 	1.60	 	
 	 	 	 	 	 	 	
        Effective December 31, 2010, James C. Musselman retired as the Company's Chairman and Chief Executive Officer. The Company entered into a retirement agreement with Mr. Musselman on December 17, 2010. Pursuant to the retirement agreement, 1.2 million profit units of Kosmos Energy Holdings that were unvested as of his retirement date became fully vested as of such date resulting in unit-based compensation of $11.5 million in the fourth quarter of 2010.

        At December 31, 2010, the remaining unrecognized compensation cost from profit units was $3.1 million, which will be recognized over a weighted-average period of 2.3 years. Total profit unit compensation expense recognized in income was $3.7 million, $3.5 million and $13.8 million for the years ended December 31, 2008, 2009 and 2010, respectively.

        The significant assumptions used to calculate the fair values of the profit units granted over the past three years, as calculated using a binomial tree, were as follows: no dividend yield, expected volatility ranging from approximately 25% to 66%, risk-free interest rate ranging from 1.3% to 5.1%, expected life ranging from 1.2 to 8.1 years and projected turnover rate of 7.0% for employees and none for management.

F-36

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

19. Commitments and Contingencies

        As of September 12, 2003, the Company leased office space located at 8401 North Central Expressway, Dallas, Texas. The lease, as amended, expired on September 30, 2009.

        As of June 29, 2008, office lease agreements were signed between Harvest/NPE LP and Kosmos Energy, LLC with respect to spaces located at 8170 Park Lane, Dallas, Texas, referred to as the North Premises and the South Premises. The leases commenced in March 2009 and expire in 2015 and 2014, respectively. At December 31, 2009 and 2010, liabilities of $1.7 million and $1.4 million, respectively, were recorded for tenant improvement allowances. The Company received $2.0 million for leasehold incentives from Harvest/NPE LP in 2009.

        The Company leases other facilities under various operating leases that expire through 2015. Rent expense under these agreements along with the office lease agreements, was $0.9 million, $1.4 million and $1.4 million for the years ended December 31, 2008, 2009 and 2010, respectively.

        Future minimum rental commitments under these leases at December 31, 2010, are as follows:

	 	Office Leases	 	
 
	 	(In thousands)
	 	
2011	 	$	1,615	 	
2012	 	 	1,636	 	
2013	 	 	1,660	 	
2014	 	 	1,168	 	
2015	 	 	382	 	
Thereafter	 	 	—	 	
        On June 23, 2008, Kosmos Ghana signed an offshore drilling contract with Alpha Offshore Drilling Services Company, a wholly-owned subsidiary of Atwood Oceanics, Inc., for the semi-submersible rig, "Atwood Hunter." Noble Energy EG Ltd. ("Noble") also is a party to the contract. The rated water depth capability of the Atwood Hunter is currently 5,000 feet. The initial rig rate is $538 thousand per day and is subject to annual adjustments for cost increases. Effective, July 27, 2009 and 2010, the rig rate was adjusted to $543 thousand and $546 thousand per day, respectively. The contract, as amended, is for 1,152 days, with Kosmos Ghana and Noble allotted 797 days and 355 days, respectively. Kosmos Ghana and Tullow Ghana Limited entered into a rig and services sharing agreement on October 18, 2009, for use of the Atwood Hunter across WCTP and DT Blocks during part of Kosmos Ghana's allocated time. The future minimum commitments under this contract as of December 31, 2010, are (in thousands): 2011—$138,588; and 2012—$133,131.

20. Litigation

        Kosmos Energy Holdings is not party to any litigation or proceedings with respect to the Company's operations which management believes, based on advice of counsel, will either individually or in the aggregate have a materially adverse impact on the Company's financial condition, results of operations or cash flows.

F-37

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

21. Subsequent Events

Commercial Debt Facilities

        In January 2011, the Company borrowed $28.0 million under the senior facilities. As of the date of the financial statements, borrowings against the commercial debt facilities totaled $1.07 billion and the scheduled principal maturities during the next five years and thereafter are (in thousands): 2011—$273,000; 2012—$250,000; 2013—$200,000; 2014—$175,000; 2015—$100,000 and thereafter—$75,000.

Exploration Expenses

        Drilling of the Mombe-1 exploration well was completed in January 2011. The well encountered hydrocarbons in sub-commercial quantities and accordingly will be plugged and abandoned. Total well related costs incurred from inception through December 31, 2010 of $26.1 million are included in exploration expenses in the accompanying consolidated statement of operations. As of the date of the financial statements, the Company estimates we will incur an additional $1.8 million of related well costs.

Exchange of Convertible Preferred Units

        Contemporaneous with the public offering, the holders of the convertible preferred units are expected to exercise their rights, acquired on formation, to exchange all of the outstanding convertible preferred units of the Company to ordinary shares based on the pre-offering equity value of such interests. As a result, 50,884,956 convertible preferred units outstanding at that date will be exchanged into 279,208,798 ordinary shares. The ordinary shares have one vote per share and a par value of $0.01. The effects of the exchange of the convertible preferred units are shown in the balance sheet column "Pro Forma."

22. Pro forma Information (Unaudited)

Per share information

        Basic and diluted net loss per share have been calculated using the weighted average number of common shares, on a pro forma basis, assuming conversion of the redeemable preferred units into common shares. The weighted average common shares outstanding have been calculated as if the ownership restructure resulting from the corporate reorganization was in place since inception.

        The pro forma as adjusted as of December 31, 2010 gives effect to the exchange of all of the interests in Kosmos Energy Holdings for newly issued common shares of Kosmos Energy Ltd. pursuant to the terms of a corporate reorganization that will be completed simultaneously with, or prior to, the

F-38

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

22. Pro forma Information (Unaudited) (Continued)

closing of this offering. The following is a reconciliation of the denominator of the pro forma basic and diluted net loss per share computations (in thousands, except per share data).

	 	Year Ended
December 31
2010	 	
Weighted average common shares outstanding:	 	 	 	 	
 	As converted from common units	 	 	46,590	 	
 	As converted from convertible preferred units	 	 	279,209	 	
 	 	 	 	
Pro forma weighted average common shares for basic and diluted net loss per common share	 	 	325,799	 	
 	 	 	 	
        The following table sets forth the computation of pro forma basic and diluted net loss per common share (in thousands, except per share data).

	 	Year Ended
December 31
2010	 	
Numerator	 	 	 	 	
Net loss	 	$	(245,672	)	
 	 	 	 	
Denominator	 	 	 	 	
Pro forma weighted average common shares for basic and diluted net loss per common share	 	 	325,799	 	
 	 	 	 	
Pro forma basic and diluted net loss per share	 	
$	
(0.75	
)	

23. Supplementary Oil and Gas Data (Unaudited)

        In January 2010, the FASB issued ASU No. 2010-03—Extractive Activities—Oil and Gas (ASC 932) Oil and Gas Reserve Estimation and Disclosures so as to align the oil and gas reserve estimation and disclosure requirements of Extractive Activities—Oil and Gas (ASC 932) with the requirements in the SEC's final rule, Modernization of the Oil and Gas Reporting Requirements which was issued on December 31, 2008. The Company adopted the update as of December 31, 2009.

        Net proved oil and gas reserve estimates presented were prepared by Netherland, Sewell & Associates, Inc. ("NSAI"), independent petroleum engineers located in Dallas, Texas. The technical persons at NSAI have prepared the reserve estimates presented herein and meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to independent reserve engineers for their reserves review process. The supplementary oil and gas data that follows includes (1) net proved oil and gas reserves, (2) capitalized costs related to oil and gas producing activities, (3) costs incurred for property

F-39

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

acquisition, exploration, and development activities, (4) results of operations for oil and gas producing activities, (5) a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, and (6) changes in the standardized measure of discounted future net cash flows. Oil production commenced on November 28, 2010, and we received revenues from oil production in early 2011; therefore, there are no disclosures related to item (4) above for 2010.

Net Proved Developed and Undeveloped Reserves

        The following table is a summary of net proved developed and undeveloped oil and gas reserves to Kosmos' interest in the Jubilee Field Phase 1 development in Ghana.

	 	Oil	 	Gas	 	Total	 	
 
	 	(Mmbbl)
	 	(Bcf)
	 	(Mmboe)
	 	
Net proved undeveloped reserves at December 31, 2008	 	 	—	 	 	—	 	 	—	 	
 	Discoveries and extensions	 	 	52	 	 	—	 	 	52	 	
 	Production	 	 	—	 	 	—	 	 	—	 	
 	Purchases of minerals-in-place	 	 	—	 	 	—	 	 	—	 	
 	 	 	 	 	 	 	 	
Net proved undeveloped reserves at December 31, 2009	 	 	52	 	 	—	 	 	52	 	
 	Discoveries and extensions	 	 	—	 	 	22	 	 	4	 	
 	Production	 	 	—	 	 	—	 	 	—	 	
 	Purchases of minerals-in-place	 	 	—	 	 	—	 	 	—	 	
 	 	 	 	 	 	 	 	
Net proved developed and undeveloped reserves at December 31, 2010	 	 	52	 	 	22	 	 	56	 	
 	 	 	 	 	 	 	 	
Proved developed reserves	 	 	 	 	 	 	 	 	 	 	
 	January 1, 2009	 	 	—	 	 	—	 	 	—	 	
 	December 31, 2009	 	 	—	 	 	—	 	 	—	 	
 	December 31, 2010	 	 	35	 	 	18	 	 	38	 	
Proved undeveloped reserves	 	 	 	 	 	 	 	 	 	 	
 	January 1, 2009	 	 	—	 	 	—	 	 	—	 	
 	December 31, 2009	 	 	52	 	 	—	 	 	52	 	
 	December 31, 2010	 	 	17	 	 	4	 	 	18	 	
        Net proved reserves were calculated utilizing the twelve month unweighted arithmetic average of the first-day-of-the-month oil price for each month for Brent crude in the period January through December 2010. The average Brent crude price of $79.35 per barrel is adjusted for crude handling, transportation fees, quality, and a regional price differential. Based on the crude quality, these adjustments are estimated to be an additional $0.35 per barrel; therefore, the oil flowstreams receive a crude price of $79.70 per barrel. This oil price is held constant throughout the lives of the properties. There is no gas price used because gas reserves are consumed in operations as fuel.

        Proved oil and gas reserves are defined by the SEC Rule 4.10(a) of Regulation S-X as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recovered under current economic conditions, operating

F-40

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

methods, and government regulations. Inherent uncertainties exist in estimating proved reserve quantities, projecting future production rates and timing of development expenditures.

Capitalized Costs Related to Oil and Gas Activities

        The following table presents aggregate capitalized costs related to oil and gas activities:

	 	Ghana	 	Other West
Africa	 	Total	 	
 
	 	(In thousands)
	 	
As of December 31, 2009	 	 	 	 	 	 	 	 	 	 	
 	Unproved properties	 	$	121,781	 	$	7,206	 	$	128,987	 	
 	Proved properties	 	 	466,104	 	 	—	 	 	466,104	 	
 	 	 	 	 	 	 	 	
 	 	 	587,885	 	 	7,206	 	 	595,091	 	
Accumulated depletion, depreciation and amortization	 	 	
—	 	 	
—	 	 	
—	 	
 	 	 	 	 	 	 	 	
Net capitalized costs	 	$	587,885	 	$	7,206	 	$	595,091	 	
 	 	 	 	 	 	 	 	
As of December 31, 2010	 	 	 	 	 	 	 	 	 	 	
 	Unproved properties	 	$	190,184	 	$	7,965	 	$	198,149	 	
 	Proved properties	 	 	798,150	 	 	—	 	 	798,150	 	
 	 	 	 	 	 	 	 	
 	 	 	988,334	 	 	7,965	 	 	996,299	 	
Accumulated depletion, depreciation and amortization	 	 	(6,430	)	 	—	 	 	(6,430	)	
 	 	 	 	 	 	 	 	
Net capitalized costs	 	$	981,904	 	$	7,965	 	$	989,869	 	
 	 	 	 	 	 	 	 	
F-41

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

F-42

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

from those used; and actual costs may vary. Kosmos' investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on a wide range of different price and cost assumptions.

        The standardized measure is intended to provide a better means to compare the value of Kosmos' proved reserves at a given time with those of other oil producing companies than is provided by comparing raw proved reserve quantities.

	 	Ghana	 	
 
	 	(In millions)
	 	
At December 31, 2009	 	 	 	 	
Future cash inflows	 	$	3,098	 	
Future production costs	 	 	(990	)	
Future development costs	 	 	(630	)	
Future Ghanaian tax expenses(1)	 	 	(351	)	
 	 	 	 	
Future net cash flows	 	 	1,127	 	
10% annual discount for estimated timing of cash flows	 	 	(429	)	
 	 	 	 	
Standardized measure of discounted future net cash flows	 	$	698	 	
 	 	 	 	
At December 31, 2010	 	 	 	 	
Future cash inflows	 	$	4,141	 	
Future production costs	 	 	(1,140	)	
Future development costs	 	 	(342	)	
Future Ghanaian tax expenses(1)	 	 	(618	)	
 	 	 	 	
Future net cash flows	 	 	2,041	 	
10% annual discount for estimated timing of cash flows	 	 	(511	)	
 	 	 	 	
Standardized measure of discounted future net cash flows	 	$	1,530	 	
 	 	 	 	
Changes in the Standardized Measure for Discounted Cash Flows

	 	Ghana	 	
 
	 	(In millions)
	 	
Balance at December 31, 2009	 	$	698	 	
Net changes in prices	 	 	1,055	 	
Net changes in production costs	 	 	(150	)	
Net changes in development costs	 	 	288	 	
Extensions and discoveries	 	 	(12	)	
Net change in Ghanaian tax expenses(1)	 	 	(267	)	
Accretion of discount	 	 	(82	)	
 	 	 	 	
Balance at December 31, 2010	 	$	1,530	 	

(1)
Standardized Measure includes the effects of both future income tax expense related to the Company's proved oil and gas reserves levied at a corporate parent and intermediate

F-43

Table of Contents
Kosmos Energy Holdings
(A Development Stage Entity)

Notes to Consolidated Financial Statements (Continued)

23. Supplementary Oil and Gas Data (Unaudited) (Continued)

subsidiary level on future net revenues and future tax expense levied at an asset level (in the Company's case, future Ghanaian tax expense levied under the WCTP and DT Petroleum Agreements). As the Company has been a tax exempted company incorporated pursuant to the laws of the Cayman Islands to date and will be a tax exempted company incorporated pursuant to the laws of Bermuda following the completion of the corporate reorganization to be completed in connection with this offering, and as the Company's intermediate subsidiaries positioned between it and the subsidiary that is a signatory to the WCTP and DT Petroleum Agreements will continue to be tax exempted companies, the Company has not been and does not expect to be subject to future income tax expense related to its proved oil and gas reserves levied at a corporate parent or intermediate subsidiary level. Accordingly, the Company's Standardized Measure for the years ended December 31, 2009 and 2010, respectively, only reflect the effects of future Ghanaian tax expense levied under the WCTP and DT Petroleum Agreements.

F-44

Table of Contents

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13.    Other Expenses of Issuance and Distribution.

        The following table sets forth an itemization of the various costs and expenses, all of which we will pay, in connection with the issuance and distribution of the securities being registered. All of the amounts shown are estimated except the SEC registration fee, the NYSE listing fee and the FINRA filing fee:
 	 	 	 	 	
SEC registration fee	 	$	58,050	 	
NYSE listing fee	 	 	250,000	 	
FINRA filing fee	 	 	75,500	 	
Accounting fees and expense	 	 	1,500,000	 	
Printing and engraving expenses	 	 	450,000	 	
Legal fees and expenses	 	 	2,800,000	 	
Transfer Agents and Registrar fees	 	 	25,000	 	
Miscellaneous	 	 	341,450	 	
 	 	 	 	
Total	 	$	5,500,000	 	
 	 	 	 	
Item 14.    Indemnification of Directors and Officers.

        Section 98 of the Companies Act 1981 of Bermuda (the "Bermuda Companies Act") provides generally that a Bermuda company may indemnify its directors, officers and auditors against any liability which by virtue of any rule of law would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust, except in cases where such liability arises from fraud or dishonesty of which such director, officer or auditor may be guilty in relation to the company. Section 98 further provides that a Bermuda company may indemnify its directors, officers and auditors against any liability incurred by them in defending any proceedings, whether civil or criminal, in which judgment is awarded in their favour or in which they are acquitted or granted relief by the Supreme Court of Bermuda pursuant to section 281 of the Bermuda Companies Act.

        We have adopted provisions in our bye-laws that provide that we shall indemnify our officers and directors in respect of their actions and omissions, except in respect of their fraud or dishonesty. Our bye-laws provide that the company and the shareholders waive all claims or rights of action that they might have, individually or in right of the company, against any of the company's directors or officers for any act or failure to act in the performance of such director's or officer's duties, except in respect of any fraud or dishonesty of such director or officer. Section 98A of the Bermuda Companies Act permits us to purchase and maintain insurance for the benefit of any officer or director in respect of any loss or liability attaching to him in respect of any negligence, default, breach of duty or breach of trust, whether or not we may otherwise indemnify such officer or director.

        Insofar as indemnification by us for liabilities arising under the Securities Act may be permitted to our directors, officers or persons controlling the company pursuant to provisions of our bye-laws, or otherwise, we have been advised that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable. In the event that a claim for indemnification by such director, officer or controlling person of us in the successful defense of any action, suit or proceeding is asserted by such director, officer or controlling person in connection with the securities being offered, we will, unless in the opinion of our counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by us is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

II-1

        At the present time, there is no pending litigation or proceeding involving a director, officer, employee or other agent of ours in which indemnification would be required or permitted. We are not aware of any threatened litigation or proceeding, which may result in a claim for such indemnification.

        We carry insurance policies insuring our directors and officers against certain liabilities that they may incur in their capacity as directors and officers. In addition, we expect to enter into indemnification agreements with each of our directors prior to completion of the offering.

        Additionally, reference is made to the Underwriting Agreement filed as Exhibit 1.1. hereto, which provides for indemnification by the underwriters of Kosmos Energy Ltd., our directors and officers who sign the registration statement and persons who control Kosmos Energy Ltd., under certain circumstances.

Item 15.    Recent Sales of Unregistered Securities.

        During the past three years, Kosmos Energy Ltd.'s predecessor, Kosmos Energy Holdings, issued unregistered securities to funds affiliated with Warburg Pincus LLC ("Warburg Pincus"), The Blackstone Group L.P. ("Blackstone"), certain members of management, accredited employee investors and directors, as described below. None of these transactions involved any underwriters or any public offerings, and we believe that each of these transactions was exempt from the registration requirements pursuant to Section 3(a)(9) or Section 4(2) of the Securities Act of 1933, as amended. The recipients of the securities in these transactions represented their intention to acquire the securities for investment only and not with a view to or for sale in connection with any distribution thereof. The information presented below does not give effect to our corporate reorganization as described in the prospectus.

        During the fiscal year ended December 31, 2008, Kosmos Energy Holdings issued the following unregistered securities for the consideration listed:
 	 	 	 	 	 	 	
Recipient	 	Securities Issued	 	Consideration
Received by
Kosmos Energy
Holdings	 	
Warburg Pincus	 	7,150,893 Series A Convertible Preferred Units	 	$	71,508,930	 	
 	 	4,308,700 Series B Convertible Preferred Units	 	 	107,717,500	 	
Blackstone	 	5,850,738 Series A Convertible Preferred Units	 	
$	
58,507,380	 	
 	 	3,525,300 Series B Convertible Preferred Units	 	 	88,132,500	 	
Members of management, accredited employee investors and directors, in the aggregate	 	298,367 Series A Convertible Preferred Units	 	
$	
2,983,670	 	
 	 	152,250 Series B Convertible Preferred Units	 	 	3,806,250	 	
II-2

        During the fiscal year ended December 31, 2009, Kosmos Energy Holdings issued the following unregistered securities for the consideration listed:
 	 	 	 	 	 	 	
Recipient	 	Securities Issued	 	Consideration
Received by
Kosmos Energy
Holdings	 	
Warburg Pincus	 	6,463,052 Series B Convertible Preferred Units	 	$	161,576,300	 	
 	 	476,134 Series C Convertible Preferred Units(1)	 	 	13,450,786	 	
Blackstone	 	5,287,948 Series B Convertible Preferred Units	 	
$	
132,198,700	 	
 	 	389,563 Series C Convertible Preferred Units(1)	 	 	11,005,155	 	
Members of management, accredited employee investors and directors, in the aggregate	 	262,750 Series B Convertible Preferred Units	 	
$	
6,568,750	 	
 	 	19,259 Series C Convertible Preferred Units(1)	 	 	544,066	 	

(1)
Kosmos Energy Holdings' financial statements reflect that the proceeds from the Series C funding were allocated on a relative fair value basis between the Series C Convertible Preferred Units and the C1 Common Units.

        During the fiscal year ended December 31, 2010, Kosmos Energy Holdings did not issue any unregistered securities. To date, during the current fiscal year, Kosmos Energy Holdings has not issued any unregistered securities. To date, during the current fiscal year, Kosmos Energy Ltd. has issued one common share in connection with its incorporation under the laws of Bermuda.

II-3

Item 16.    Exhibits and Financial Statement Schedules.
(a)
The following exhibits are filed as part of this registration statement:
 	 	 	 	
Exhibit
Number	 	Description of Document	
 	1.1	 	Form of Underwriting Agreement	

3.1	
 	
Certificate of Incorporation of Kosmos Energy Ltd. (the "Company")****	

3.2	
 	
Memorandum of Association of the Company****	

3.3	
 	
Form of Bye-laws of the Company*****	

3.4	
 	
Fourth Amended and Restated Operating Agreement of Kosmos Energy Holdings (the "Predecessor"), as amended*****	

3.5	
 	
Memorandum of Association of the Predecessor****	

3.6	
 	
Articles of Association of the Predecessor****	

4.1	
 	
Specimen share certificate	

5.1	
 	
Opinion of Conyers Dill & Pearman Limited	

9.1	
 	
Form of Shareholders Agreement.*****	

10.1	
 	
Petroleum Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 22, 2004 among the Ghana National Petroleum Corporation ("GNPC"), Kosmos Energy Ghana HC ("Kosmos Ghana") and the E.O. Group Limited ("E.O. Group").***	

10.2	
 	
Operating Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 27, 2004 between Kosmos Ghana and E.O. Group.***	

10.3	
 	
Petroleum Agreement in respect of the Deepwater Tano Contract Area dated March 10, 2006 among GNPC, Tullow Ghana Limited ("Tullow Ghana"), Sabre Oil and Gas Limited ("Sabre") and Kosmos Ghana.***	

10.4	
 	
Joint Operating Agreement in respect of the Deepwater Tano Contract Area, Offshore Ghana dated August 14, 2006, among Tullow Ghana, Sabre Oil and Gas Limited, and Kosmos Ghana.***	

10.5	
 	
Assignment Agreement in respect of the Deepwater Tano Block dated September 1, 2006, among Anadarko WCTP Company ("Anadarko WCTP") and Kosmos Ghana.***	

10.6	
 	
Unitization and Unit Operating Agreement covering the Jubilee Field Unit located offshore the Republic of Ghana dated July 13, 2009, among GNPC, Tullow, Kosmos Ghana, Anadarko WCTP, Sabre and E.O. Group.***	

10.7	
 	
Atwood Hunter Offshore Drilling Contract dated June 23, 2008 among Kosmos Ghana, Alpha Offshore Drilling Services Company and Noble Energy EG Ltd., as amended.****	

10.8	
 	
Ndian River Production Sharing Contract dated November 20, 2006 between the Republic of Cameroon and Kosmos Energy Cameroon HC ("Kosmos Cameroon").***	

10.9	
 	
Decree 2005/249 dated June 30, 2005 granting Perenco Oil and Gas (Cameroon) Ltd. ("Perenco") and Société Nationale des Hydrocarbures ("SNH") the Kombe-N'sepe Permit.***	

10.10	
 	
Contract of Association relating to the Kombe-N'sepe Permit dated December 11, 1997 between the Republic of Cameroon, CMS Nomeco Cameroon Ltd ("CMS Nomeco Cameroon"), Globex Cameroon, LLC ("Globex Cameroon") and SNH.***	
II-4

 	 	 	 	
Exhibit
Number	 	Description of Document	
 	10.11	 	Convention of Establishment relating to the Kombe-N'sepe Permit dated December 11, 1997 between the Republic of Cameroon, CMS Nomeco Cameroon and Globex Cameroon.***	

10.12	
 	
Deed of Assignment of the Kombe-N'sepe Permit, Contract of Association and Convention of Establishment dated November 16, 2005 between Perenco and Kosmos Cameroon.***	

10.13	
 	
Agreement on the Management of Petroleum Operations (JOA) covering the Kombe-N'sepe Permit dated July 3, 2008 among SNH, Perenco and Kosmos Cameroon.***	

10.14	
 	
Petroleum Agreement regarding the exploration for and exploitation of hydrocarbons in the area of interest named Boujdour Offshore dated May 3, 2006 between Office National des Hydrocarbures et des Mines ("ONHYM") and Kosmos Energy Offshore Morocco HC ("Kosmos Morocco").***	

10.15	
 	
Association Contract regarding the exploration for and exploitation of hydrocarbons in the Boujdour Offshore Block dated May 3, 2006 between ONHYM and Kosmos Morocco.***	

10.16	
 	
Memorandum of Understanding regarding a new petroleum agreement covering certain areas of the Boujdour Offshore Block dated September 27, 2010 between ONHYM and Kosmos Morocco.***	

10.17	
 	
Facility Agreement, dated March 28, 2011 among Kosmos Energy Finance International ("Kosmos Finance International"), Kosmos Energy Operating ("Kosmos Operating"), Kosmos Energy International ("Kosmos International"), Kosmos Energy Development ("Kosmos Development") and Kosmos Ghana and the various financial institutions and others party thereto.	

10.18	
 	
[Reserved.]	

10.19	
 	
[Reserved.]	

10.20	
 	
Intercreditor Agreement, dated March 28, 2011 among BNP Paribas, Kosmos Finance International, Kosmos Operating, Kosmos International, Kosmos Development, Kosmos Ghana and the various financial institutions and others party thereto.	

10.21	
†	
Form of Long Term Incentive Plan*****	

10.22	
†	
Form of Annual Incentive Plan*****	

10.23	
†	
Form of Non-Qualified Stock Option Award Agreement*****	

10.24	
†	
Form of Restricted Stock Award Agreement (Exchange)*****	

10.25	
†	
Form of Restricted Stock Award Agreement (Service Vesting)*****	

10.26	
†	
Form of Restricted Stock Award Agreement (Performance Vesting)*****	

10.27	
 	
Form of Director Indemnification Agreement******	

10.28	
†	
Retirement Agreement dated December 17, 2010 between Kosmos Energy, LLC, Kosmos Energy Holdings, James C. Musselman, Musselman-Kosmos, Ltd. and funds affiliated with Warburg Pincus LLC and The Blackstone Group L.P.***	

10.29	
†	
Consulting Agreement dated November 17, 2010 between Kosmos Energy Holdings and John R. Kemp***	

10.30	
†	
Form of Executive Employment Agreement*****	
II-5

 	 	 	 	
Exhibit
Number	 	Description of Document	
 	10.31	 	Letter agreement, dated May 4, 2010 among Tullow Ghana Limited, Anadarko WCTP Company and Kosmos Ghana****	

10.32	
 	
Settlement Agreement, dated December 18, 2010 among Kosmos Ghana, Ghana National Petroleum Corporation and the Government of the Republic of Ghana******	

10.33	
 	
Participation Agreement dated June 1, 2004 between Kosmos Ghana and E.O. Group Limited.	

21.1	
 	
List of Subsidiaries******	

23.1	
 	
Consent of Ernst & Young LLP	

23.2	
 	
Consent of Netherland, Sewell & Associates, Inc.	

23.3	
 	
Consent of Conyers Dill & Pearman Limited (included in Exhibit 5.1)	

24	
 	
Power of Attorney (included on the signature pages of this registration statement)	

99.1	
 	
Estimate of Reserves and Future Revenue to the Kosmos Energy Interest in the Jubilee Field Phase 1 Development Unit Area located in the West Cape Three Points and Deepwater Tano License Areas Offshore Ghana as of December 31, 2009.	

99.2	
 	
Estimate of Reserves and Future Revenue to the Kosmos Energy Interest in the Jubilee Field Phase 1 Development Unit Area located in the West Cape Three Points and Deepwater Tano License Areas Offshore Ghana as of December 31, 2010.	

99.3	
 	
Consent of David I. Foley, as director nominee**	

99.4	
 	
Consent of Jeffrey A. Harris, as director nominee**	

99.5	
 	
Consent of David Krieger, as director nominee**	

99.6	
 	
Consent of Prakash A. Melwani, as director nominee**	

99.7	
 	
Consent of Bayo O. Ogunlesi, as director nominee**	

99.8	
 	
Consent of Christopher A. Wright, as director nominee**	

**
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on January 14, 2011.

***
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 3, 2011.

****
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 23, 2011.

*****
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 30, 2011.

******
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on April 14, 2011.

†
Management contract or compensatory plan or arrangement.

II-6

(b)
Financial Statement Schedule

Schedule I—Condensed Parent Company Financial Statements

        Under the terms of agreements governing the indebtedness of subsidiaries of Kosmos Energy Holdings ("KEH," the "Parent Company"), such subsidiaries are restricted from making dividend payments, loans or advances to KEH. Schedule I of Article 5-04 of Regulation S-X requires the condensed financial information of the Parent Company to be filed when the restricted net assets of consolidated subsidiaries exceed 25 percent of consolidated net assets as of the end of the most recently completed fiscal year.

        The following condensed parent-only financial statements of KEH have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X and included herein. The Parent Company's 100% investment in its subsidiaries has been recorded using the equity basis of accounting in the accompanying condensed parent-only financial statements. The condensed financial statements should be read in conjunction with the consolidated financial statements of Kosmos Energy Holdings and subsidiaries and notes thereto.

II-7

Kosmos Energy Holdings

(A Development Stage Entity)

Condensed Parent Company Balance Sheets

 
	 	December 31	 	
 
	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Assets	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	51,224	 	$	—	 	
 	Receivables from subsidiaries	 	 	3,878	 	 	—	 	
 	Prepaid expenses and other	 	 	15	 	 	—	 	
 	 	 	 	 	 	
Total current assets	 	 	55,117	 	 	—	 	
Other assets, net of accumulated depreciation and amortization of $773 and $773, respectively	 	 	
2	 	 	
—	 	
Investment in subsidiaries at equity	 	 	540,482	 	 	363,507	 	
 	 	 	 	 	 	
Total assets	 	$	595,601	 	$	363,507	 	
 	 	 	 	 	 	
Liabilities and unit holdings	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	
 	Accounts payable to subsidiaries	 	$	—	 	$	—	 	
 	Accrued liabilities	 	 	213	 	 	—	 	
 	 	 	 	 	 	
Total current liabilities	 	 	213	 	 	—	 	
Convertible preferred units, 100,000 units authorized:	 	 	 	 	 	 	 	
 	Series A—30,000 units issued at December 31, 2009 and 2010	 	 	300,000	 	 	383,246	 	
 	Series B—20,000 units issued at December 31, 2009 and 2010	 	 	500,000	 	 	568,163	 	
 	Series C—885 units issued at December 31, 2009 and 2010	 	 	13,244	 	 	27,097	 	
Unit holdings:	 	 	 	 	 	 	 	
 	Common units, 100,000 units authorized; 18,667 and 19,070 issued at December 31, 2009 and 2010, respectively	 	 	516	 	 	516	 	
 	Additional paid-in capital	 	 	19,108	 	 	—	 	
 	Deficit accumulated during development stage	 	 	(237,480	)	 	(615,515	)	
 	 	 	 	 	 	
Total unit holdings	 	 	(217,856	)	 	(614,999	)	
 	 	 	 	 	 	
Total liabilities, convertible preferred units and unit holdings	 	$	595,601	 	$	363,507	 	
 	 	 	 	 	 	
II-8

Kosmos Energy Holdings

(A Development Stage Entity)

Condensed Parent Company Statements of Operations

 
	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	
 	Oil and gas revenue	 	$	—	 	$	—	 	$	—	 	
 	Interest income	 	 	188	 	 	15	 	 	44	 	
 	 	 	 	 	 	 	 	
Total revenues and other income	 	 	188	 	 	15	 	 	44	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	
 	General and administrative	 	 	4,743	 	 	11,580	 	 	21,187	 	
 	General and administrative—related party	 	 	12,453	 	 	10,663	 	 	16,830	 	
 	Depreciation and amortization	 	 	155	 	 	39	 	 	—	 	
 	Equity in losses of subsidiaries	 	 	31,642	 	 	57,494	 	 	207,697	 	
 	Other expenses, net	 	 	—	 	 	(14	)	 	2	 	
 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	48,993	 	 	79,762	 	 	245,716	 	
 	 	 	 	 	 	 	 	
Loss before income taxes	 	 	
(48,805	
)	 	
(79,747	
)	 	
(245,672	
)	
Income tax expense	 	 	—	 	 	—	 	 	—	 	
 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(245,672	)	
 	 	 	 	 	 	 	 	
II-9

Kosmos Energy Holdings

(A Development Stage Entity)

Condensed Parent Company Statements of Cash Flows

 
	 	Years Ended December 31	 	
 
	 	2008	 	2009	 	2010	 	
 
	 	(In thousands)
	 	
Operating activities	 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(48,805	)	$	(79,747	)	$	(245,672	)	
Adjustments to reconcile net loss to net cash used in operating activities:	 	 	 	 	 	 	 	 	 	 	
 	Equity in losses of subsidiaries	 	 	31,642	 	 	57,494	 	 	207,697	 	
 	Depreciation and amortization	 	 	155	 	 	39	 	 	—	 	
 	Unit-based compensation	 	 	3,671	 	 	3,468	 	 	13,791	 	
 	Changes in assets and liabilities:	 	 	 	 	 	 	 	 	 	 	
 	 	(Increase) decrease in prepaid expenses and other	 	 	(47	)	 	32	 	 	15	 	
 	 	(Increase) decrease due to/from related party	 	 	1,008	 	 	(10,171	)	 	3,878	 	
 	 	Decrease in accounts payable	 	 	(75	)	 	—	 	 	—	 	
 	 	Increase (decrease) in accrued liabilities	 	 	—	 	 	213	 	 	(213	)	
 	 	 	 	 	 	 	 	
Net cash used in operating activities	 	 	(12,451	)	 	(28,672	)	 	(20,504	)	
Investing activities	 	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	 	 	(320,205	)	 	(245,496	)	 	(30,722	)	
Other property	 	 	—	 	 	(2	)	 	2	 	
 	 	 	 	 	 	 	 	
Net cash used in investing activities	 	 	(320,205	)	 	(245,498	)	 	(30,720	)	
Financing activities	 	 	 	 	 	 	 	 	 	 	
Net proceeds from issuance of units	 	 	332,656	 	 	325,344	 	 	—	 	
 	 	 	 	 	 	 	 	
Net cash provided by financing activities	 	 	332,656	 	 	325,344	 	 	—	 	
 	 	 	 	 	 	 	 	
Net increase (decrease) in cash and cash equivalents	 	 	
—	 	 	
51,174	 	 	
(51,224	
)	
Cash and cash equivalents at beginning of period	 	 	50	 	 	50	 	 	51,224	 	
 	 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	 	$	50	 	$	51,224	 	$	—	 	
 	 	 	 	 	 	 	 	
II-10

Kosmos Energy Holdings

(A Development Stage Entity)

Valuation and Qualifying Accounts

For the Years Ended December 31, 2008, 2009 and 2010

 
	 	 
	 	Additions	 	 

Description
	 	Balance
January 1	 	Charged to
Costs and
Expenses	 	Charged
to Other
Accounts	 	Deductions
From
Reserves	 	Balance
December 31	 	
 
	 	(In thousands)
	 	
2008	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for doubtful receivables	 	
$	
—	 	
$	
—	 	
$	
—	 	
$	
—	 	
$	
—	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for deferred tax asset	 	
$	
9,404	 	
$	
9,727	 	
$	
—	 	
$	
—	 	
$	
19,131	 	
 	 	 	 	 	 	 	 	 	 	 	 	
2009	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for doubtful receivables	 	
$	
—	 	
$	
—	 	
$	
—	 	
$	
—	 	
$	
—	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for deferred tax asset	 	
$	
19,131	 	
$	
14,618	 	
$	
—	 	
$	
—	 	
$	
33,749	 	
 	 	 	 	 	 	 	 	 	 	 	 	
2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for doubtful receivables	 	
$	
—	 	
$	
39,782	 	
$	
—	 	
$	
—	 	
$	
39,782	 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for deferred tax asset	 	
$	
33,749	 	
$	
(3,609	
)	
$	
—	 	
$	
—	 	
$	
30,140	 	
 	 	 	 	 	 	 	 	 	 	 	 	
II-11

Item 17.    Undertakings.

        (a)   The undersigned registrant hereby undertakes:

        (1)   To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

            i.  To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;

           ii.  To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20 percent change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in the effective registration statement.

          iii.  To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

        (2)   That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

        (3)   To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

        (4)   That in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

            i.  Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

           ii.  Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

          iii.  The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

          iv.  Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

        (b)   The undersigned hereby undertakes to provide to the underwriter at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriter to permit prompt delivery to each purchaser.

        (c)   Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and

II-12

Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer, or controlling person of the registrant in the successful defense of any action, suit, or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

        (d)   The undersigned registrant hereby undertakes that:

        (1)   For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

        (2)   For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-13

SIGNATURES

        Pursuant to the requirements of the Securities Act of 1933, the Registrant certifies that it has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Dallas, Texas on April 25, 2011.
 	 	 	 	 	
 	 	Kosmos Energy Ltd.	
 	 	By:	 	/s/ BRIAN F. MAXTED

Brian F. Maxted
Director and Chief Executive Officer	
        Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities held on the dates indicated.
 	 	 	 	 	
SIGNATURE	 	TITLE	 	DATE	

 	

 	
/s/ BRIAN F. MAXTED

Brian F. Maxted	 	Director and Chief Executive Officer (Principal Executive Officer)	 	April 25, 2011	

/s/ W. GREG DUNLEVY

W Greg. Dunlevy	
 	
Chief Financial Officer and Executive Vice President (Principal Financial Officer)	
 	
April 25, 2011	

/s/ SYLVIA MANOR

Sylvia Manor	
 	
Vice President and Controller
(Principal Accounting Officer)	
 	
April 25, 2011	

    *

John R. Kemp	
 	
Chairman of the Board of Directors	
 	
April 25, 2011	

    *

David I. Foley	
 	
Director	
 	
April 25, 2011	

    *

Jeffrey A. Harris	
 	
Director	
 	
April 25, 2011	

    *

David B. Krieger	
 	
Director	
 	
April 25, 2011	

    *

Prakash A. Melwani	
 	
Director	
 	
April 25, 2011	

    *

Adebayo O. Ogunlesi	
 	
Director	
 	
April 25, 2011	

    *

Chris Tong	
 	
Director	
 	
April 25, 2011	

    *

Christopher A. Wright	
 	
Director	
 	
April 25, 2011	

*By:	 	/s/ BRIAN F. MAXTED

Brian F. Maxted
Attorney-in-Fact	 	 	
II-14

INDEX OF EXHIBITS

Exhibit
Number	 	Description of Document	
 	1.1	 	Form of Underwriting Agreement	

3.1	
 	
Certificate of Incorporation of the Company****	

3.2	
 	
Memorandum of Association of the Company****	

3.3	
 	
Form of Bye-laws of the Company*****	

3.4	
 	
Fourth Amended and Restated Operating Agreement of the Predecessor, as amended*****	

3.5	
 	
Memorandum of Association of the Predecessor****	

3.6	
 	
Articles of Association of the Predecessor****	

4.1	
 	
Specimen share certificate	

5.1	
 	
Opinion of Conyers Dill & Pearman Limited	

9.1	
 	
Form of Shareholders Agreement.*****	

10.1	
 	
Petroleum Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 22, 2004 among the GNPC, Kosmos Ghana and the E.O. Group.***	

10.2	
 	
Operating Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 27, 2004 between Kosmos Ghana and E.O. Group.***	

10.3	
 	
Petroleum Agreement in respect of the Deepwater Tano Contract Area dated March 10, 2006 among GNPC, Tullow Ghana, Sabre and Kosmos Ghana.***	

10.4	
 	
Joint Operating Agreement in respect of the Deepwater Tano Contract Area, Offshore Ghana dated August 14, 2006, among Tullow Ghana, Sabre Oil and Gas Limited, and Kosmos Ghana.***	

10.5	
 	
Assignment Agreement in respect of the Deepwater Tano Block dated September 1, 2006, among Anadarko WCTP and Kosmos Ghana.***	

10.6	
 	
Unitization and Unit Operating Agreement covering the Jubilee Field Unit located offshore the Republic of Ghana dated July 13, 2009, among GNPC, Tullow, Kosmos Ghana, Anadarko WCTP, Sabre and E.O. Group.***	

10.7	
 	
Atwood Hunter Offshore Drilling Contract dated June 23, 2008 among Kosmos Ghana, Alpha Offshore Drilling Services Company and Noble Energy EG Ltd., as amended.****	

10.8	
 	
Ndian River Production Sharing Contract dated November 20, 2006 between the Republic of Cameroon and Kosmos Cameroon.***	

10.9	
 	
Decree 2005/249 dated June 30, 2005 granting Perenco and SNH the Kombe-N'sepe Permit.***	

10.10	
 	
Contract of Association relating to the Kombe-N'sepe Permit dated December 11, 1997 between the Republic of Cameroon, CMS Nomeco Cameroon, Globex Cameroon and SNH.***	

10.11	
 	
Convention of Establishment relating to the Kombe-N'sepe Permit dated December 11, 1997 between the Republic of Cameroon, CMS Nomeco Cameroon and Globex Cameroon.***	

10.12	
 	
Deed of Assignment of the Kombe-N'sepe Permit, Contract of Association and Convention of Establishment dated November 16, 2005 between Perenco and Kosmos Cameroon.***	

10.13	
 	
Agreement on the Management of Petroleum Operations (JOA) covering the Kombe-N'sepe Permit dated July 3, 2008 among SNH, Perenco and Kosmos Cameroon.***	

 	 	 	 	
Exhibit
Number	 	Description of Document	
 	10.14	 	Petroleum Agreement regarding the exploration for and exploitation of hydrocarbons in the area of interest named Boujdour Offshore dated May 3, 2006 between ONHYM and Kosmos Morocco.***	

10.15	
 	
Association Contract regarding the exploration for and exploitation of hydrocarbons in the Boujdour Offshore Block dated May 3, 2006 between ONHYM and Kosmos Morocco.***	

10.16	
 	
Memorandum of Understanding regarding a new petroleum agreement covering certain areas of the Boujdour Offshore Block dated September 27, 2010 between ONHYM and Kosmos Morocco.***	

10.17	
 	
Facility Agreement, dated March 28, 2011 among Kosmos Finance International, Kosmos Operating, Kosmos International, Kosmos Development and Kosmos Ghana and the various financial institutions and others party thereto.	

10.18	
 	
[Reserved.]	

10.19	
 	
[Reserved.]	

10.20	
 	
Intercreditor Agreement, dated March 28, 2011 among BNP Paribas, Kosmos Finance International, Kosmos Operating, Kosmos International, Kosmos Development, Kosmos Ghana and the various financial institutions and others party thereto.	

10.21	
†	
Form of Long Term Incentive Plan*****	

10.22	
†	
Form of Annual Incentive Plan*****	

10.23	
†	
Form of Non-Qualified Stock Option Award Agreement*****	

10.24	
†	
Form of Restricted Stock Award Agreement (Exchange)*****	

10.25	
†	
Form of Restricted Stock Award Agreement (Service Vesting)*****	

10.26	
†	
Form of Restricted Stock Award Agreement (Performance Vesting)*****	

10.27	
 	
Form of Director Indemnification Agreement******	

10.28	
†	
Retirement Agreement dated December 17, 2010 between Kosmos Energy, LLC, Kosmos Energy Holdings, James C. Musselman, Musselman-Kosmos, Ltd. and funds affiliated with Warburg Pincus LLC and The Blackstone Group L.P.***	

10.29	
†	
Consulting Agreement dated November 17, 2010 between Kosmos Energy Holdings and John R. Kemp***	

10.30	
†	
Form of Executive Employment Agreement*****	

10.31	
 	
Letter agreement, dated May 4, 2010 among Tullow Ghana Limited, Anadarko WCTP Company and Kosmos Ghana****	

10.32	
 	
Settlement Agreement, dated December 18, 2010 among Kosmos Ghana, Ghana National Petroleum Corporation and the Government of the Republic of Ghana******	

10.33	
 	
Participation Agreement date June 1, 2004 between Kosmos Ghana and E.O. Group Limited.	

21.1	
 	
List of Subsidiaries******	

23.1	
 	
Consent of Ernst & Young LLP	

23.2	
 	
Consent of Netherland, Sewell & Associates, Inc.	

23.3	
 	
Consent of Conyers Dill & Pearman Limited (included in Exhibit 5.1)	

24	
 	
Power of Attorney (included on the signature pages of this registration statement)	

 	 	 	 	
Exhibit
Number	 	Description of Document	
 	99.1	 	Estimate of Reserves and Future Revenue to the Kosmos Energy Interest in the Jubilee Field Phase 1 Development Unit Area located in the West Cape Three Points and Deepwater Tano License Areas Offshore Ghana as of December 31, 2009.	

99.2	
 	
Estimate of Reserves and Future Revenue to the Kosmos Energy Interest in the Jubilee Field Phase 1 Development Unit Area located in the West Cape Three Points and Deepwater Tano License Areas Offshore Ghana as of December 31, 2010.	

99.3	
 	
Consent of David I. Foley, as director nominee**	

99.4	
 	
Consent of Jeffrey A. Harris, as director nominee**	

99.5	
 	
Consent of David Krieger, as director nominee**	

99.6	
 	
Consent of Prakash A. Melwani, as director nominee**	

99.7	
 	
Consent of Bayo O. Ogunlesi, as director nominee**	

99.8	
 	
Consent of Christopher A. Wright, as director nominee**	

**
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on January 14, 2011.

***
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 3, 2011.

****
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 23, 2011.

*****
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on March 30, 2011.

******
Filed as part of this registration statement on Form S-1 (Registration No. 333-171700) on April 14, 2011.

†
Management contract or compensatory plan or arrangement.

Exhibit 1.1
 
[·] Common Shares
 
KOSMOS ENERGY LTD.
 
UNDERWRITING AGREEMENT
 
[·], 2011
 
CITIGROUP GLOBAL MARKETS INC.
BARCLAYS CAPITAL INC.
CREDIT SUISSE SECURITIES (USA) LLC,
As Representatives of the several Underwriters,
c/o Citigroup Global Markets Inc.
388 Greenwich Street
New York, NY 10013
 
Dear Sirs:
 
1.  Introductory. Kosmos Energy Ltd., a Bermuda exempted company, agrees with the several Underwriters named in Schedule A hereto (“ Underwriters ”), for whom Citigroup Global Markets Inc., Barclays Capital Inc. and Credit Suisse Securities (USA) LLC are acting as Representatives (collectively, the “ Representatives ”) to issue and sell to the several Underwriters [ · ] common shares, par value $0.01 per share, of the Company (as defined herein) (“ Securities ”) (such Securities being hereinafter referred to as the “ Firm Securities ”) and also agrees to sell to the Underwriters, at the option of the Underwriters, an aggregate of not more than [ · ] additional outstanding common shares (“ Optional Securities ”) of the Company’s Securities, as set forth below. The Firm Securities and the Optional Securities are herein collectively called the “ Offered Securities ”.  As part of the offering contemplated by this Agreement, Citigroup Global Markets Inc. (the “ Designated Underwriter” ) has agreed to reserve out of the Firm Securities purchased by it under this Agreement, up to [ · ] shares, for sale to the Company’s directors, officers, employees and other parties associated with the Company (collectively, “ Participants” ), as set forth in the Final Prospectus (as defined herein) under the heading “Underwriting” (the “ Directed Share Program” ). The Firm Securities to be sold by the Designated Underwriter pursuant to the Directed Share Program (the “ Directed Shares” ) will be sold by the Designated Underwriter pursuant to this Agreement at the public offering price. Any Directed Shares not subscribed for by the end of the business day on which this Agreement is executed will be offered to the public by the Underwriters as set forth in the Final Prospectus.
 
On or prior to the Closing Date (as defined herein), pursuant to the terms of a plan of reorganization (the “Plan of Reorganization ”), as approved by the Board of Directors of Kosmos Energy Ltd., a Bermuda exempted company (“Kosmos Energy Ltd.”) on [ · ], 2011, the Company will acquire all of the outstanding interests of Kosmos Energy Holdings, a Cayman Islands exempted company limited by guarantee (“ Kosmos Energy Holdings ”), in exchange for common shares of the Company, as described in the General Disclosure Package and the Final Prospectus (as defined herein) under the heading “Corporate Reorganization” (the “ Corporate Reorganization ”).  As used in this Agreement, prior to the consummation of the Corporate Reorganization, references to the “ Company ” shall be deemed to be references to Kosmos Energy Holdings, and after the consummation of the Corporate Reorganization, references to the “Company” shall be deemed to be references to Kosmos Energy Ltd. unless the context otherwise requires.
 
2.  Representations and Warranties of the Company.  The Company represents and warrants to, and agrees with, the several Underwriters that:
 
(i)  Filing and Effectiveness of Registration Statement; Certain Defined Terms.  The Company has filed with the Commission a registration statement on Form S-1 (No. 333- 171700) covering

 
the registration of the Offered Securities under the Act, including a related preliminary prospectus or prospectuses.  At any particular time, this initial registration statement, in the form then on file with the Commission, including all information contained in the registration statement (if any) pursuant to Rule 462(b) and then deemed to be a part of the initial registration statement, and all 430A Information and all 430C Information, that in any case has not then been superseded or modified, shall be referred to as the “ Initial Registration Statement ”.  The Company may also have filed, or may file with the Commission, a Rule 462(b) registration statement covering the registration of Offered Securities.   At any particular time, this Rule 462(b) registration statement, in the form then on file with the Commission, including the contents of the Initial Registration Statement incorporated by reference therein and including all 430A Information and all 430C Information, that in any case has not then been superseded or modified, shall be referred to as the “ Additional Registration Statement ”.
 
As of the time of execution and delivery of this Agreement, the Initial Registration Statement has been declared effective under the Act and is not proposed to be amended. Any Additional Registration Statement has or will become effective upon filing with the Commission pursuant to Rule 462(b) and is not proposed to be amended.  The Offered Securities all have been or will be duly registered under the Act pursuant to the Initial Registration Statement and, if applicable, the Additional Registration Statement.
 
For purposes of this Agreement:
 
“430A Information”, with respect to any registration statement, means information included in a prospectus and retroactively deemed to be a part of such registration statement pursuant to Rule 430A(b).
 
“430C Information”, with respect to any registration statement, means information included in a prospectus then deemed to be a part of such registration statement pursuant to Rule 430C.
 
“Act” means the Securities Act of 1933, as amended.
 
“Applicable Time” means [·]:00 pm (Eastern time) on the date of this Agreement.
 
“Closing Date” has the meaning defined in Section 3 hereof.
 
“Commission” means the Securities and Exchange Commission.
 
“Effective Time” with respect to the Initial Registration Statement or, if filed prior to the execution and delivery of this Agreement, the Additional Registration Statement, means the date and time as of which such Registration Statement was declared effective by the Commission or has become effective upon filing pursuant to Rule 462(b). If an Additional Registration Statement has not been filed prior to the execution and delivery of this Agreement but the Company has advised the Representatives that it proposes to file one, “ Effective Time ” with respect to such Additional Registration Statement means the date and time as of which such Registration Statement is filed and becomes effective pursuant to Rule 462(b).
 
“Exchange Act” means the Securities Exchange Act of 1934.
 
“Final Prospectus” means the Statutory Prospectus that discloses the public offering price, other 430A Information and other final terms of the Offered Securities and otherwise satisfies Section 10(a) of the Act.
 
“General Use Issuer Free Writing Prospectus” means any Issuer Free Writing Prospectus that is intended for general distribution to prospective investors, as evidenced by its being so specified in Schedule B to this Agreement.
 
“Issuer Free Writing Prospectus” means any “issuer free writing prospectus,” as defined in Rule 433, relating to the Offered Securities in the form filed or required to be filed with the Commission or, if not required to be filed, in the form retained in the Company’s records pursuant to Rule 433(g).
 
2

 
“Limited Use Issuer Free Writing Prospectus” means any Issuer Free Writing Prospectus that is not a General Use Issuer Free Writing Prospectus.
 
The Initial Registration Statement and the Additional Registration Statement are referred to collectively as the “ Registration Statements ” and individually as a “ Registration Statement ”.  A “ Registration Statement ” with reference to a particular time means the Initial Registration Statement and any Additional Registration Statement as of such time.  A “ Registration Statement ” without reference to a time means such Registration Statement as of its Effective Time.  For purposes of the foregoing definitions, 430A Information with respect to a Registration Statement shall be considered to be included in such Registration Statement as of the time specified in Rule 430A.
 
“Rules and Regulations” means the rules and regulations of the Commission.
 
“Securities Laws” means, collectively, the Sarbanes-Oxley Act of 2002 (“ Sarbanes-Oxley ”), the Act, the Exchange Act, the Rules and Regulations, the auditing principles, rules, standards and practices applicable to auditors of “issuers” (as defined in Sarbanes-Oxley) promulgated or approved by the Public Company Accounting Oversight Board and, as applicable, the rules of the New York Stock Exchange (“ Exchange Rules ”).
 
“Statutory Prospectus” with reference to a particular time means the prospectus included in a Registration Statement immediately prior to that time, including any 430A Information or 430C Information with respect to such Registration Statement.  For purposes of the foregoing definition, 430A Information shall be considered to be included in the Statutory Prospectus as of the actual time that form of prospectus is filed with the Commission pursuant to Rule 424(b) or Rule 462(c) and not retroactively.
 
Unless otherwise specified, a reference to a “rule” is to the indicated rule under the Act.
 
(ii)  Compliance with Securities Act Requirements.  (i) (A) At their respective Effective Times, (B) on the date of this Agreement and (C) on each Closing Date, each of the Initial Registration Statement and the Additional Registration Statement (if any) conformed and will conform in all material respects to the requirements of the Act, (ii) on its date, at the time of filing of the Final Prospectus pursuant to Rule 424(b) or (if no such filing is required) at the Effective Time of the Additional Registration Statement in which the Final Prospectus is included, and on each Closing Date, the Final Prospectus will conform in all material respects to the requirements of the Act and the Rules and Regulations and will not include any untrue statement of a material fact or omit to state any material fact required to be stated therein or necessary to make the statements therein, in light of the circumstances under which they were made, not misleading, and (iii) on the date of this Agreement, at their respective Effective Times or issue dates and on each Closing Date, each Registration Statement, the Final Prospectus, any Statutory Prospectus, any prospectus wrapper and any Issuer Free Writing Prospectus complied or comply, and such documents and any further amendments or supplements thereto will comply, with any applicable laws or regulations of foreign jurisdictions in which the Final Prospectus, any Statutory Prospectus, any prospectus wrapper or any Issuer Free Writing Prospectus, as amended or supplemented, if applicable, are distributed in connection with the Directed Share Program.  The preceding sentence does not apply to statements in or omissions from any such document based upon written information furnished to the Company by any Underwriter through the Representatives specifically for use therein, it being understood and agreed that the only such information is that described as such in Section 8(c) hereof.
 
(iii)  Ineligible Issuer Status.  (i) At the time of the initial filing of the Initial Registration Statement and (ii) at the date of this Agreement, the Company was not and is not an “ineligible issuer,” as defined in Rule 405, including (x) the Company or any subsidiary of the Company in the preceding three years not having been convicted of a felony or misdemeanor or having been made the subject of a judicial or administrative decree or order as described in Rule 405 and (y) the Company in the preceding three years not having been the subject of a bankruptcy petition or insolvency or similar proceeding, not having had a registration statement be the subject of a
 
3

 
proceeding under Section 8 of the Act and not being the subject of a proceeding under Section 8A of the Act in connection with the offering of the Offered Securities, all as described in Rule 405.
 
(iv)  General Disclosure Package.  As of the Applicable Time, neither (i) the General Use Issuer Free Writing Prospectus(es) issued at or prior to the Applicable Time, the preliminary prospectus, dated [ · ], 2011 (which is the most recent Statutory Prospectus distributed to investors generally) and the other information, if any, stated in Schedule B to this Agreement to be included in the General Disclosure Package, all considered together (collectively, the “ General Disclosure Package ”), nor (ii) any individual Limited Use Issuer Free Writing Prospectus when considered together with the General Disclosure Package, included any untrue statement of a material fact or omitted to state any material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading.  The preceding sentence does not apply to statements in or omissions from any Statutory Prospectus or any Issuer Free Writing Prospectus in reliance upon and in conformity with written information furnished to the Company by any Underwriter through the Representatives specifically for use therein, it being understood and agreed that the only such information furnished by any Underwriter consists of the information described as such in Section 8(c) hereof.
 
(v)  Issuer Free Writing Prospectuses.  Each Issuer Free Writing Prospectus, as of its issue date and at all subsequent times through the completion of the public offer and sale of the Offered Securities or until any earlier date that the Company notified or notifies the Representatives as described in the next sentence, did not, does not and will not include any information that conflicted, conflicts or will conflict with the information then contained in the Registration Statement.  If at any time following issuance of an Issuer Free Writing Prospectus, at a time when a prospectus relating to the offered securities is (but for the exemption in Rule 172 would be) required to be delivered under the Act by any Underwriter or dealer, there occurred or occurs an event or development as a result of which such Issuer Free Writing Prospectus conflicted or would conflict with the information then contained in the Registration Statement or as a result of which such Issuer Free Writing Prospectus, if republished immediately following such event or development, would include an untrue statement of a material fact or omitted or would omit to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading, (i) the Company has promptly notified or will promptly notify the Representatives and (ii) the Company has promptly amended or will promptly amend or supplement such Issuer Free Writing Prospectus to eliminate or correct such conflict, untrue statement or omission.  The preceding two sentences do not apply to statements in or omissions from any Issuer Free Writing Prospectus in reliance upon and in conformity with written information furnished to the Company by any Underwriter through the Representatives specifically for use therein, it being understood and agreed that the only such information furnished by any Underwriter consists of the information described as such in Section 8(c) hereof.
 
(vi) Good Standing of the Company.  The Company has been duly incorporated and is existing and in good standing under the laws of Bermuda, with power and authority (corporate and other) to own its properties and conduct its business as described in the General Disclosure Package; and the Company is duly qualified to do business as a foreign corporation in good standing in all other jurisdictions in which its ownership or lease of property or the conduct of its business requires such qualification, except where the failure to be duly qualified or in good standing as a foreign corporation would not, individually or in the aggregate, result in a material adverse effect on the condition (financial or otherwise), results of operations, business, properties or prospects of the Company and its subsidiaries taken as a whole (“Material Adverse Effect”).
 
(vii) Subsidiaries.  Each subsidiary of the Company has been duly incorporated, formed or organized and is existing and in good standing under the laws of the jurisdiction of its incorporation, formation or organization, as the case may be, with power and authority (corporate and other) to own its properties and conduct its business as described in the General Disclosure Package; and each subsidiary of the Company is duly qualified to do business as a foreign corporation in good standing
 
4

 
in all other jurisdictions in which its ownership or lease of property or the conduct of its business requires such qualification, except as would not, individually or in the aggregate, result in a Material Adverse Effect; all of the issued and outstanding capital shares of each subsidiary of the Company has been duly authorized and validly issued and is fully paid and nonassessable; and the capital shares of each subsidiary owned by the Company, directly or through subsidiaries, is owned free from liens, encumbrances and defects, other than pledges of such shares in connection with the Company’s commercial debt facility.
 
(viii) Offered Securities.  The Offered Securities and all other outstanding shares in the capital of the Company have been duly authorized; the authorized share capital of the Company is as set forth in the General Disclosure Package; all issued and outstanding shares of the Company are, and, when the Offered Securities have been delivered and paid for in accordance with this Agreement on each Closing Date, such Offered Securities will have been, validly issued, fully paid and nonassessable, will conform to the information in the General Disclosure Package and to the description of such Offered Securities contained in the Final Prospectus; the shareholders of the Company have no preemptive rights with respect to the Securities; and none of the issued and outstanding shares of the Company have been issued in violation of any preemptive or similar rights of any security holder.
 
(ix) No Finder’s Fee.  Except as disclosed in the General Disclosure Package, there are no contracts, agreements or understandings between the Company and any person that would give rise to a valid claim against the Company or any Underwriter for a brokerage commission, finder’s fee or other like payment in connection with this offering.
 
(x) Registration Rights.  Except as disclosed in the General Disclosure Package and except as have been permanently waived prior to or on the date of this Agreement, there are no contracts, agreements or understandings between the Company and any person granting such person the right to require the Company to file a registration statement under the Act with respect to any securities of the Company owned or to be owned by such person or to require the Company to include such securities in the securities registered pursuant to a Registration Statement or in any securities being registered pursuant to any other registration statement filed by the Company under the Act. (collectively, “ registration rights ”), and any person to whom the Company has granted registration rights has agreed not to exercise such rights until after the expiration of the Lock-Up Period referred to in Section 5(l) hereof.
 
(xi) Listing.  The Offered Securities have been approved for listing on The New York Stock Exchange, subject to notice of issuance.
 
(xii) Absence of Further Requirements.  No consent, approval, authorization or order of, or filing or registration with, any person (including any governmental agency or body or any court) is required to be obtained or made by the Company for the consummation of the transactions contemplated by this Agreement in connection with the sale of the Offered Securities, except (a) such as have been obtained or made and such as may be required under state securities laws, (b) the filing of the Final Prospectus with the Bermuda Registrar of Companies as soon as reasonably practicable after publication of the Final Prospectus, or (c) as may be required by the rules of the Financial Industry Regulatory Authority, Inc. (“FINRA”).  No authorization, consent, approval, license, qualification or order of, or filing or registration with any person (including any governmental agency or body or any court) in any foreign jurisdiction is required for the consummation of the transactions contemplated by this Agreement in connection with the offering, issuance and sale of the Directed Shares under the laws and regulations of such jurisdiction except such as have been obtained or made.
 
(xiii) Title to Property.  Except as disclosed in the General Disclosure Package, the Company and its subsidiaries have (i) legal, valid and defensible title to the interests in the oil and natural gas properties described in each Registration Statement, the General Disclosure Package and the Final Prospectus and (ii) good and marketable title to all real properties and all other properties and assets
 
5

 
owned by them, in each case free from liens, charges, encumbrances and defects that would materially affect the value thereof or materially interfere with the use made or to be made thereof by them; and, except as disclosed in the General Disclosure Package, the Company and its subsidiaries hold any leased real or personal property under valid and enforceable leases with no terms or provisions that would materially interfere with the use made or currently proposed to be made thereof by them in each case, other than pledges of shares under, or otherwise pursuant to, the Company’s commercial debt facility.
 
(xiv) Absence of Defaults and Conflicts Resulting from Transaction.  The execution, delivery and performance of this Agreement, and the issuance and sale of the Offered Securities will not, and the execution, delivery and performance of the Reorganization Agreement and the consummation of the transactions contemplated therein will not, result in a breach or violation of any of the terms and provisions of, or constitute a default or a Debt Repayment Triggering Event (as defined below) under, or result in the imposition of any lien, charge or encumbrance upon any property or assets of the Company or any of its subsidiaries pursuant to, (i) the charter or by-laws of the Company or any of its subsidiaries, (ii) any statute, rule, regulation or order of any governmental agency or body or any court, domestic or foreign, having jurisdiction over the Company or any of its subsidiaries or any of their properties, or (iii) any agreement or instrument to which the Company or any of its subsidiaries is a party or by which the Company or any of its subsidiaries is bound or to which any of the properties of the Company or any of its subsidiaries is subject; , except, in the case of clauses (ii) and (iii), where any such breach, violation or default would not, individually or in the aggregate, result in a Material Adverse Effect. A “ Debt Repayment Triggering Event ” means any event or condition that gives, or with the giving of notice or lapse of time would give, the holder of any note, debenture, or other evidence of indebtedness (or any person acting on such holder’s behalf) the right to require the repurchase, redemption or repayment of all or a portion of such indebtedness by the Company or any of its subsidiaries.
 
(xv) Absence of Existing Defaults and Conflicts.  Neither the Company nor any of its subsidiaries is in violation of its respective memorandum of association, charter or bye-laws or in default (or with the giving of notice or lapse of time would be in default) under any existing obligation, agreement, covenant or condition contained in any indenture, loan agreement, mortgage, lease or other agreement or instrument to which any of them is a party or by which any of them is bound or to which any of the properties of any of them is subject, except such defaults that would not, individually or in the aggregate, result in a Material Adverse Effect.
 
(xvi) Authorization of this Agreement and the Plan of Reorganization.  This Agreement has been duly authorized, executed and delivered by the Company.  The Plan of Reorganization has been duly authorized by the Company.
 
(xvii) Possession of Licenses and Permits.  Except as disclosed in the General Disclosure Package, the Company and its subsidiaries possess, and are in compliance with the terms of, all adequate certificates, authorizations, franchises, licenses and permits (“ Licenses ”) necessary or material to the conduct of the business now conducted or proposed in the General Disclosure Package to be conducted by them and except as disclosed in the General Disclosure Package, have not received any notice of proceedings relating to the revocation or modification of any Licenses that, if determined adversely to the Company or any of its subsidiaries, would individually or in the aggregate have a Material Adverse Effect.
 
(xviii) Absence of Labor Dispute.  No labor dispute with the employees of the Company or any of its subsidiaries exists or, to the knowledge of the Company, is imminent that could have a Material Adverse Effect.
 
(xix) Possession of Intellectual Property.  The Company and its subsidiaries own, possess or can acquire on reasonable terms, adequate trademarks, trade names and other rights to inventions, know-how, patents, copyrights, confidential information and other intellectual property (collectively, “ intellectual property rights ”) necessary to conduct the business now operated by them, or
 
6

 
presently employed by them, and have not received any notice of infringement of or conflict with asserted rights of others with respect to any intellectual property rights that, if determined adversely to the Company or any of its subsidiaries, would individually or in the aggregate have a Material Adverse Effect.
 
(xx) Environmental Laws.  Except as disclosed in the General Disclosure Package, (a)(i) neither the Company nor any of its subsidiaries is in violation of, or has any liability under, any federal, state, local or non-U.S. statute, law, rule, regulation, ordinance, code, other requirement or rule of law (including common law), or decision or order of any domestic or foreign governmental agency, governmental body or court, relating to pollution, to the use, handling, transportation, treatment, storage, discharge, disposal or release of hazardous substances, to the protection or restoration of the environment or natural resources (including biota), to health and safety as such relates to exposure to hazardous substances, and to natural resource damages (collectively, “ Environmental Laws ”), (ii) neither the Company nor any of its subsidiaries owns, occupies, operates or uses any real property contaminated with Hazardous Substances, (iii) neither the Company nor any of its subsidiaries is conducting or funding any investigation, remediation, remedial action or monitoring of actual or suspected Hazardous Substances in the environment, (iv) neither the Company nor any of its subsidiaries is liable or allegedly liable for any release or threatened release of Hazardous Substances, including at any off-site treatment, storage or disposal site or any formerly owned or occupied real property, (v) neither the Company nor any of its subsidiaries is subject to any claim by any governmental agency or governmental body or person relating to Environmental Laws or Hazardous Substances, and (vi) the Company and its subsidiaries have received and are in compliance with all, and have no liability under any, permits, licenses, authorizations, identification numbers or other approvals required under applicable Environmental Laws to conduct their respective businesses, except in each case covered by clauses (i) — (vi) such as would not individually or in the aggregate have a Material Adverse Effect; (b) to the knowledge of the Company, there are no facts or circumstances that would reasonably be expected to result in a violation of, liability under, or claim pursuant to any Environmental Law that would have a Material Adverse Effect; (c) to the knowledge of the Company, there are no requirements proposed for adoption or implementation under any Environmental Law that would reasonably be expected to have a Material Adverse Effect; (d) the Company has evaluated the effects, including associated costs and liabilities, of Environmental Laws on the business, properties and financial condition of it and its subsidiaries, and, on the basis of such evaluation, the Company has reasonably concluded that such Environmental Laws will not, singly or in the aggregate, have a Material Adverse Effect; and (e) neither the Company nor any of its subsidiaries is subject to any pending proceeding under Environmental Laws, and no such proceeding is known by the Company to be contemplated, to which a governmental authority is a party and which is reasonably likely to result in monetary sanctions of $100,000 or more.  For purposes of this subsection, “ Hazardous Substances ” means (A) petroleum and petroleum products, by-products or breakdown products, radioactive materials, asbestos-containing materials, polychlorinated biphenyls and mold, and (B) any other chemical, material or substance defined or regulated as toxic or hazardous or as a pollutant, contaminant or waste under Environmental Laws.
 
(xxi)  Accurate Disclosure.  The statements in the General Disclosure Package  and the Final Prospectus under the headings “Corporate Reorganization”, “Certain Tax Considerations”, “Description of Share Capital”, “Business—Environmental Matters”, “Business—Other Regulation of the Oil and Gas Industry” and “Certain Relationships and Related Party Transactions”, insofar as such statements summarize legal matters, agreements, documents or proceedings discussed therein, are accurate in all material respects and fair summaries of such legal matters, agreements, documents or proceedings and present the information required to be shown.
 
(xxii) Absence of Manipulation.  The Company has not taken, directly or indirectly, any action that is designed to or that has constituted or that would reasonably be expected to cause or result in the stabilization or manipulation of the price of any security of the Company to facilitate the sale or resale of the Offered Securities.
 
7

 
(xxiii)  Statistical and Market-Related Data.  Any third-party statistical and market-related data included in a Registration Statement, a Statutory Prospectus or the General Disclosure Package are based on or derived from sources that the Company believes to be reliable and accurate.
 
(xxiv)  Internal Controls and Compliance with the Sarbanes-Oxley Act.  Except as set forth in the General Disclosure Package, the Company, its subsidiaries and the Company’s Board of Directors (the “ Board ”) are in compliance with all applicable provisions of Sarbanes-Oxley and Exchange Rules.  The Company maintains a system of internal controls, including, but not limited to, disclosure controls and procedures, internal controls over accounting matters and financial reporting, an internal audit function and legal and regulatory compliance controls (collectively, “ Internal Controls ”) that comply with the Securities Laws and are sufficient to provide reasonable assurances that (i) transactions are executed in accordance with management’s general or specific authorizations, (ii) transactions are recorded as necessary to permit preparation of financial statements in conformity with U.S. General Accepted Accounting Principles and to maintain accountability for assets, (iii) access to assets is permitted only in accordance with management’s general or specific authorization, and (iv) the recorded accountability for assets is compared with the existing assets at reasonable intervals and appropriate action is taken with respect to any differences.  The Internal Controls are, or upon consummation of the offering of the Offered Securities will be, overseen by the Audit Committee (the “ Audit Committee ”) of the Board in accordance with Exchange Rules.  The Company has not publicly disclosed or reported to the Audit Committee or the Board, and within the next 135 days the Company does not reasonably expect to publicly disclose or report to the Audit Committee or the Board, a significant deficiency, material weakness, change in Internal Controls or fraud involving management or other employees who have a significant role in Internal Controls (each, an “ Internal Control Event ”), any violation of, or failure to comply with, the Securities Laws, or any matter which, if determined adversely, would have a Material Adverse Effect.
 
(xxv)  Absence of Accounting Issues.  A member of the Audit Committee has confirmed to the Chief Financial Officer that, except as set forth in the General Disclosure Package, the Audit Committee is not reviewing or investigating, and neither the Company’s independent auditors nor its internal auditors have recommended that the Audit Committee review or investigate, (i) adding to, deleting, changing the application of, or changing the Company’s disclosure with respect to, any of the Company’s material accounting policies; (ii) any matter which could result in a restatement of the Company’s financial statements for any annual or interim period during the current or prior three fiscal years; or (iii) any Internal Control Event.
 
(xxvi) Litigation.  Except as disclosed in the General Disclosure Package, there are no pending actions, suits or proceedings (including any inquiries or investigations by any court or governmental agency or body, domestic or foreign) against the Company, any of its subsidiaries or any of their respective properties that, if determined adversely to the Company or any of its subsidiaries, would individually or in the aggregate have a Material Adverse Effect, or would materially and adversely affect the ability of the Company to perform its obligations under this Agreement, or which are otherwise material in the context of the sale of the Offered Securities; and no such actions, suits or proceedings (including any inquiries or investigations by any court or governmental agency or body, domestic or foreign) are threatened or, to the Company’s knowledge, contemplated.
 
(xxvii) Financial Statements.  The financial statements included in each Registration Statement and the General Disclosure Package present fairly in all material respects the financial position of the Company and its consolidated subsidiaries as of the dates shown and their results of operations and cash flows for the periods shown, and such financial statements have been prepared in conformity with the generally accepted accounting principles in the United States applied on a consistent basis; the schedules included in each Registration Statement present fairly in all material respects the information required to be stated therein; and the assumptions used in preparing the pro forma financial statements included in each Registration Statement and the General Disclosure Package provide a reasonable basis for presenting the significant effects directly attributable to the transactions or events described therein, the related pro forma adjustments give appropriate effect
 
8

 
to those assumptions, and the pro forma columns therein reflect the proper application of those adjustments to the corresponding historical financial statement amounts.
 
(xxviii) No Material Adverse Change in Business.  Except as disclosed in the General Disclosure Package, since the end of the period covered by the latest audited financial statements included in the General Disclosure Package (i) there has been no change, nor any development or event involving a prospective change, in the condition (financial or otherwise), results of operations, business, properties or prospects of the Company and its subsidiaries, taken as a whole, that is material and adverse, (ii) except as disclosed in or contemplated by the General Disclosure Package, there has been no dividend or distribution of any kind declared, paid or made by the Company on any class of its capital shares and (iii) except as disclosed in or contemplated by the General Disclosure Package, there has been no material adverse change in the capital shares, short-term indebtedness, long-term indebtedness, net current assets or net assets of the Company and its subsidiaries.
 
(xxix)  Investment Company Act.  The Company is not and, after giving effect to the offering and sale of the Offered Securities and the application of the proceeds thereof as described in the General Disclosure Package, will not be an “investment company” as defined in the Investment Company Act of 1940, as amended (the “ Investment Company Act ”).
 
(xxx)  Ratings.  If applicable to the Company, no “nationally recognized statistical rating organization” as such term is defined for purposes of Rule 436(g)(2) (i) has imposed (or has informed the Company that it is considering imposing) any condition (financial or otherwise) on the Company’s retaining any rating assigned to the Company or any securities of the Company or (ii) has indicated to the Company that it is considering any of the actions described in Section 7(c)(ii) hereof.
 
(xxxi)  PFIC Status.  Based on management estimates and projections of future operations and revenue, Kosmos Energy Ltd. does not believe that it will be a “passive foreign investment company” (“ PFIC ”) as defined in Section 1297 of the United States Internal Revenue Code of 1986, as amended (the “ Code ”), for its current taxable year and does not expect to become a PFIC in the foreseeable future.
 
(xxxii)  OFAC.  Neither the Company nor any of its subsidiaries nor, to the knowledge of the Company, any director, officer, agent, employee or affiliate of the Company or any of its subsidiaries is currently subject to any sanctions administered by the Office of Foreign Assets Control of the U.S. Treasury Department (“ OFAC ”); and the Company, to its knowledge after due inquiry, will not directly or indirectly use the proceeds of the offering, or lend, contribute or otherwise make available such proceeds to any subsidiary, joint venture partner or other person or entity, for the purpose of financing the activities of any person currently subject to any U.S. sanctions administered by OFAC.
 
(xxxiii)  Anti-corruption Laws; Money Laundering Laws; Sanctions.  Except as disclosed in the General Disclosure Package, each of the Company, its subsidiaries, and to the Company’s knowledge, its affiliates and any of their respective officers, directors, supervisors, managers, agents, employees, and any other persons acting on its behalf, is not aware of, has not taken, and will not take any action, directly or indirectly, including its participation in the offering, that violates the following laws, has instituted and maintains policies and procedures whose effects are designed to ensure continued compliance with each of the following laws, and has maintained, and will continue to maintain, books and records as required by, and that ensure continued compliance with, each of the following laws: (a) anti-corruption laws, including but not limited to, any applicable law, rule, or regulation of any locality, including but not limited to any law, rule, or regulation promulgated to implement the OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions, signed December 17, 1997, including the U.S. Foreign Corrupt Practices Act of 1977, as amended, and the rules and regulations thereunder (the “FCPA”), including, without limitation, making use of the mails or any means or instrumentality of interstate commerce corruptly
 
9

 
in furtherance of an offer, payment, promise to pay or authorization of the payment of any money, or other property, gift, promise to give, or authorization of the giving of anything of value to any “foreign official” (as such term in defined in the FCPA) or any foreign political party or official thereof or any candidate for foreign political office, in contravention of the FCPA, or any other law, rule or regulation of similar purpose and scope applicable to the operations of the Company, its subsidiaries or its affiliates, (b) anti-money laundering laws, including but not limited to, applicable federal, state, international, foreign or other laws, regulations or government guidance regarding anti-money laundering, including, without limitation, Title 18 U.S. Code section 1956 and 1957, the Patriot Act, the Bank Secrecy Act, and international anti-money laundering principles or procedures by an intergovernmental group or organization, such as the Financial Action Task Force on Money Laundering, of which the United States is a member and with which designation the United States representative to the group or organization continues to concur, all as amended, and any Executive order, directive, or regulation pursuant to the authority of any of the foregoing, or any orders or licenses issued thereunder or (c) laws and regulations imposing U.S. economic sanctions measures, including, but not limited to, the International Emergency Economic Powers Act, the Trading with the Enemy Act, the United Nations Participation Act, and the Syria Accountability and Lebanese Sovereignty Act, all as amended, and any Executive Order, directive, or regulation pursuant to the authority of any of the foregoing, including the regulations of the United States Treasury Department set forth under 31 CFR, Subtitle B, Chapter V, as amended, or any orders or licenses issued thereunder.
 
(xxxiv)  Taxes.  The Company and its subsidiaries have filed all federal, state, local and non-U.S. tax returns that are required to be filed or have requested extensions thereof (except in any case in which the failure so to file would not have a Material Adverse Effect); and, except as set forth in the General Disclosure Package, the Company and its subsidiaries have paid all taxes (including any assessments, fines or penalties) required to be paid by them, except for any such taxes, assessments, fines or penalties currently being contested in good faith or as would not, individually or in the aggregate, have a Material Adverse Effect.
 
(xxxv)  Insurance.  The Company and its subsidiaries are insured by insurers with appropriately rated claims paying abilities against such losses and risks and in such amounts as are customary for the industry in which they participate; all policies of insurance and fidelity or surety bonds insuring the Company or any of its subsidiaries or their respective businesses, assets, employees, officers and directors are in full force and effect; the Company and its subsidiaries are in compliance with the terms of such policies and instruments in all material respects; and there are no claims by the Company or any of its subsidiaries under any such policy or instrument as to which any insurance company is denying liability or defending under a reservation of rights clause; neither the Company nor any such subsidiary has been refused any insurance coverage sought or applied for; neither the Company nor any such subsidiary has any reason to believe that it will not be able to renew its existing insurance coverage as and when such coverage expires or to obtain similar coverage from similar insurers as may be necessary to continue its business at a cost that would not have a Material Adverse Effect, except as set forth in or contemplated in the General Disclosure Package; and the Company has or will obtain directors’ and officer’s insurance in such amounts as is customary for an initial public offering.
 
(xxxvi)  Independent Petroleum Engineers.  Netherland, Sewell & Associates, Inc. (“NSAI”), who has delivered the letter referenced in Section 7(h) hereof (the “ NSAI Letter ”), was, as of the date(s) of the reports referenced in such letter, and is, as of the date hereof, an independent engineering firm with respect to the Company.
 
(xxxvii)  Information Underlying NSAI Reports.  The factual information underlying the estimates of the Company’s oil and natural gas reserves and resources, which was supplied by the Company to NSAI for the purposes of preparing the reserve and resource reports and estimates of the Company and preparing the NSAI Letter, including, without limitation, costs of operation and development and agreements relating to current and future operations and sales of production, was true and correct in all material respects on the dates such estimates were made and such information
 
10

 
was supplied and was prepared in accordance with customary industry practices; other than intervening market commodity price fluctuations, the Company is not aware of any facts or circumstances that would result in a material adverse change in the estimates of the Company’s oil and natural gas resources, or the present value of future net cash flows therefrom, as reflected in the reports referenced in the NSAI Letter; the Company has no reason to believe that such estimates do not fairly reflect the oil and natural gas resources of the Company as of the dates indicated in each Registration Statement, the General Disclosure Package and the Final Prospectus.
 
(xxxviii)  Corporate Reorganization.  As of the Closing Date, the Company will have filed all notices, reports, documents or other information required to be filed by them pursuant to, and will have obtained any and all authorizations, approvals, orders, consents, licenses, certificates, permits, registrations or qualifications required to be obtained under, and will have otherwise complied with all requirements of, all applicable laws in connection with the consummation of the Corporate Reorganization, except in each case where such failure would not, individually or in the aggregate, result in a Material Adverse Effect; the Corporate Reorganization will be legal, effective and valid and in accordance with the laws of Bermuda.
 
(xxxix)  Auditor Independence.  Ernst & Young LLP, who have certified certain financial statements of the Company and its subsidiaries, are independent public accountants as required by the Act and the rules and regulations of the Commission thereunder.
 
(xxxx)  Payments in Foreign Currency.  Except as disclosed in the General Disclosure Package, under current laws and regulations of Bermuda and any political subdivision thereof, all dividends and other distributions declared and payable on the Offered Securities may be paid by the Company to the holder thereof in United States dollars or Bermuda dollars that may be converted into foreign currency and freely transferred out of Bermuda and all such payments made to holders thereof or therein who are non-residents of Bermuda will not be subject to income, withholding or other taxes under laws and regulations of Bermuda or any political subdivision or taxing authority thereof or therein and will otherwise be free and clear of any other tax, duty, withholding or deduction in Bermuda or any political subdivision or taxing authority thereof or therein and without the necessity of obtaining any governmental authorization in Bermuda or any political subdivision or taxing authority thereof or therein.
 
(xxxxi)  Absence of Unlawful Influence.  The Company has not offered or sold, or caused the Underwriters to offer or sell, any Offered Securities to any person pursuant to the Directed Share Program with the specific intent to unlawfully influence (i) a customer or supplier of the Company to alter the customer’s or supplier’s level or type of business with the Company or (ii) a trade journalist or publication to write or publish favorable information about the Company or its products.
 
3.  Purchase, Sale and Delivery of Offered Securities.  On the basis of the representations, warranties and agreements and subject to the terms and conditions set forth herein, the Company agrees to sell to the several Underwriters, and each of the Underwriters agrees, severally and not jointly, to purchase from the Company, at a purchase price of $[ · ] per share, the respective number of shares of Firm Securities set forth opposite the names of the Underwriters in Schedule A hereto.
 
The Company will deliver the Firm Securities to or as instructed by the Representatives for the accounts of the several Underwriters in a form reasonably acceptable to the Representatives against payment of the purchase price in Federal (same day) funds by official bank check or checks or wire transfer to an account at a bank acceptable to the Representatives drawn to the order of “Kosmos Energy Ltd.”, at the office of Davis Polk & Wardwell LLP, 450 Lexington Avenue, New York, New York 10017, at 9:00 A.M., New York time, on [ · ], 2011, or at such other time not later than seven full business days thereafter as the Representatives and the Company determine, such time being herein referred to as the “ First Closing Date ”.  For purposes of Rule 15c6-1 under the Exchange Act, the First Closing Date (if later than the otherwise applicable settlement date) shall be the settlement date for payment of funds and delivery of securities for all the Offered Securities sold pursuant to the offering.  The Firm Securities so to be delivered or evidence of
 
11

 
their issuance will be made available for checking at the above office of Davis Polk & Wardwell LLP at least 24 hours prior to the First Closing Date.
 
In addition, upon written notice from the Representatives given to the Company from time to time not more than 30 days subsequent to the date of the Final Prospectus, the Underwriters may purchase all or less than all of the Optional Securities at the purchase price per Security to be paid for the Firm Securities, less an amount per share equal to any dividends or distributions declared by the Company and payable on the Firm Securities but not payable on the Optional Securities.  The Company agrees to sell to the Underwriters the number of shares of Optional Securities specified in such notice and the Underwriters agree, severally and not jointly, to purchase such Optional Securities.  Such Optional Securities shall be purchased for the account of each Underwriter in the same proportion as the number of shares of Firm Securities set forth opposite such Underwriter’s name bears to the total number of shares of Firm Securities (subject to adjustment by the Representatives to eliminate fractions) and may be purchased by the Underwriters only for the purpose of covering over-allotments made in connection with the sale of the Firm Securities.  No Optional Securities shall be sold or delivered unless the Firm Securities previously have been, or simultaneously are, sold and delivered.  The right to purchase the Optional Securities or any portion thereof may be exercised from time to time and to the extent not previously exercised may be surrendered and terminated at any time upon notice by the Representatives to the Company.
 
Each time for the delivery of and payment for the Optional Securities, being herein referred to as an “Optional Closing Date ”, which may be the First Closing Date (the First Closing Date and each Optional Closing Date, if any, being sometimes referred to as a “ Closing Date ”), shall be determined by the Representatives but shall be not later than five full business days after written notice of election to purchase Optional Securities is given.  The Company will deliver the Optional Securities being purchased on each Optional Closing Date to or as instructed by the Representatives for the accounts of the several Underwriters in a form reasonably acceptable to the Representatives, against payment of the purchase price therefor in Federal (same day) funds by official bank check or checks or wire transfer to an account at a bank acceptable to the Representatives drawn to the order of “Kosmos Energy Ltd.”, at the above office of Davis Polk & Wardwell LLP.  The Optional Securities being purchased on each Optional Closing Date or evidence of their issuance will be made available for checking at the above office of Davis Polk & Wardwell LLP at a reasonable time in advance of such Optional Closing Date.
 
4.  Offering by Underwriters.  It is understood that the several Underwriters propose to offer the Offered Securities for sale to the public as set forth in the Final Prospectus.
 
5.  Certain Agreements of the Company. The Company agrees with the several Underwriters that:
 
(a)  Additional Filings.  Unless filed pursuant to Rule 462(c) as part of the Additional Registration Statement in accordance with the next sentence, the Company will file the Final Prospectus, in a form approved by the Representatives, with the Commission pursuant to and in accordance with subparagraph (1) (or, if applicable and if consented to by the Representatives, subparagraph (4)) of Rule 424(b) not later than the earlier of (A) the second business day following the execution and delivery of this Agreement or (B) the fifteenth business day after the Effective Time of the Initial Registration Statement.  The Company will advise the Representatives promptly of any such filing pursuant to Rule 424(b) and provide satisfactory evidence to the Representatives of such timely filing.  If an Additional Registration Statement is necessary to register a portion of the Offered Securities under the Act but the Effective Time thereof has not occurred as of the execution and delivery of this Agreement, the Company will file the Additional Registration Statement or, if filed, will file a post-effective amendment thereto with the Commission pursuant to and in accordance with Rule 462(b) on or prior to 10:00 P.M., New York time, on the date of this Agreement or, if earlier, on or prior to the time the Final Prospectus is finalized and distributed to any Underwriter, or will make such filing at such later date as shall have been consented to by the Representatives.
 
(b)  Filing of Amendments: Response to Commission Requests.  The Company will promptly advise the Representatives of any proposal to amend or supplement at any time the Initial
 
12

 
Registration Statement, any Additional Registration Statement or any Statutory Prospectus and will not effect such amendment or supplementation without the Representatives’ consent; and the Company will also advise the Representatives promptly of (i) the effectiveness of any Additional Registration Statement (if its Effective Time is subsequent to the execution and delivery of this Agreement), (ii) any amendment or supplementation of a Registration Statement or any Statutory Prospectus, (iii) any request by the Commission or its staff for any amendment to any Registration Statement, for any supplement to any Statutory Prospectus or for any additional information, (iv) the institution by the Commission of any stop order proceedings in respect of a Registration Statement or the threatening of any proceeding for that purpose, and (v) the receipt by the Company of any notification with respect to the suspension of the qualification of the Offered Securities in any jurisdiction or the institution or threatening of any proceedings for such purpose.  The Company will use its reasonable best efforts to prevent the issuance of any such stop order or the suspension of any such qualification and, if issued, to obtain as soon as possible the withdrawal thereof.
 
(c)  Continued Compliance with Securities Laws.  If, at any time when a prospectus relating to the Offered Securities is (or but for the exemption in Rule 172 would be) required to be delivered under the Act by any Underwriter or dealer, any event occurs as a result of which the Final Prospectus as then amended or supplemented would include an untrue statement of a material fact or omit to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading, or if it is necessary at any time to amend the Registration Statement or supplement the Final Prospectus to comply with the Act, the Company will promptly notify the Representatives of such event and will promptly prepare and file with the Commission and furnish, at its own expense, to the Underwriters and the dealers and any other dealers upon request of the Representatives, an amendment or supplement which will correct such statement or omission or an amendment which will effect such compliance.  Neither the Representatives’ consent to, nor the Underwriters’ delivery of, any such amendment or supplement shall constitute a waiver of any of the conditions set forth in Section 7 hereof.
 
(d)  Rule 158.  As soon as practicable, but not later than the Availability Date (as defined below), the Company will make generally available to its security holders an earnings statement covering a period of at least 12 months beginning after the Effective Time of the Initial Registration Statement (or, if later, the Effective Time of the Additional Registration Statement) which will satisfy the provisions of Section 11(a) of the Act and Rule 158 under the Act. For the purpose of the preceding sentence, “ Availability Date ” means the 45th day after the end of the fourth fiscal quarter following the fiscal quarter that includes such Effective Time, except that, if such fourth fiscal quarter is the last quarter of the Company’s fiscal year, “ Availability Date ” means the 90th day after the end of such fourth fiscal quarter.
 
(e)  Furnishing of Prospectuses.  The Company will furnish to the Representatives copies of each Registration Statement (four of which will include all exhibits), each related Statutory Prospectus, and, so long as a prospectus relating to the Offered Securities is (or but for the exemption in Rule 172 would be) required to be delivered under the Act, the Final Prospectus and all amendments and supplements to such documents, in each case in such quantities as the Representatives request. The Final Prospectus shall be so furnished on or prior to 3:00 P.M., New York time, on the business day following the execution and delivery of this Agreement.  All other such documents shall be so furnished as soon as available. The Company will pay the expenses of printing and distributing to the Underwriters all such documents.
 
(f)  Blue Sky Qualifications.  The Company will cooperate with the Representatives for the qualification of the Offered Securities for sale under the laws of such jurisdictions as the Representatives designate and to continue such qualifications in effect so long as required for the distribution; provided, however, that the Company shall not be obligated to file any general consent to service of process or to qualify as a foreign corporation or as a dealer in securities in any jurisdiction in which it is not so qualified or to subject itself to taxation in respect of doing business in any jurisdiction in which it is not otherwise so subject.
 
13

 
(g)  Reporting Requirements.  During the period of four years hereafter, the Company will furnish to the Representatives and, upon request, to each of the other Underwriters, as soon as practicable after the end of each fiscal year, a copy of its annual report to shareholders for such year; and the Company will furnish to the Representatives (i) as soon as available, a copy of each report and any definitive proxy statement of the Company filed with the Commission under the Exchange Act or mailed to shareholders, and (ii) from time to time, such other information concerning the Company as the Representatives may reasonably request (as long as such information is not publicly available at an insignificant cost).  However, so long as the Company is subject to the reporting requirements of either Section 13 or Section 15(d) of the Exchange Act and is timely filing reports with the Commission on its Electronic Data Gathering, Analysis and Retrieval system (“ EDGAR ”), it is not required to furnish such reports or statements to the Underwriters.
 
(h)  Payment of Expenses.  The Company agrees with the several Underwriters that the Company will pay all expenses incident to the performance of its obligations under this Agreement, including but not limited to any filing fees and other expenses (including fees and disbursements of counsel to the Underwriters) incurred in connection with qualification of the Offered Securities for sale under the laws of such jurisdictions as the Representatives designate and the preparation and printing of memoranda relating thereto, costs and expenses related to the review by FINRA of the Offered Securities (including filing fees and the fees and expenses of counsel for the Underwriters relating to such review), costs and expenses relating to investor presentations or any “road show” in connection with the offering and sale of the Offered Securities including, without limitation, any travel expenses of the Company’s officers and employees and any other expenses of the Company including 50% of the costs of the chartering of airplanes, the fees and expenses incident to listing the Offered Securities on the New York Stock Exchange, the Ghanaian Stock Exchange and other national and foreign exchanges, the fees and expenses in connection with the registration of the Offered Securities under the Exchange Act, and the expenses incurred in distributing preliminary prospectuses and the Final Prospectus (including any amendments and supplements thereto) to the Underwriters and for the expenses incurred for preparing, printing and distributing any Issuer Free Writing Prospectuses to investors or prospective investors.  Except as otherwise provided by this Agreement, the Underwriters shall pay their own costs and expenses in connection with the transactions contemplated hereby, including, without limitation, fees and expenses of their counsel.
 
(i) Use of Proceeds.  The Company will use the net proceeds received by it in connection with this offering in the manner described in the “Use of Proceeds” section of the General Disclosure Package and, except as disclosed in the General Disclosure Package, the Company does not intend to use any of the proceeds from the sale of the Offered Securities hereunder to repay any outstanding debt owed to any affiliate of any Underwriter.
 
(j) Absence of Manipulation.  The Company will not take, directly or indirectly, any action designed to or that would constitute or that might reasonably be expected to cause or result in, stabilization or manipulation of the price of any securities of the Company to facilitate the sale or resale of the Offered Securities.
 
(k)  Taxes.  The Company will indemnify and hold harmless the Underwriters against any documentary, stamp or similar issue tax arising under laws other than those of the United States, including any interest and penalties, on the creation, issue and sale of the Offered Securities and on the execution and delivery of this Agreement. All payments to be made by the Company hereunder shall be made without withholding or deduction for or on account of any present or future taxes, duties or governmental charges whatsoever unless the Company is compelled by law to deduct or withhold such taxes, duties or charges. In that event, the Company shall pay such additional amounts as may be necessary in order that the net amounts received after such withholding or deduction shall equal the amounts that would have been received if no withholding or deduction had been made.
 
(l)  Restriction on Sale of Securities by Company.  For the period specified below (the “Lock-Up Period ”), the Company will not, directly or indirectly, take any of the following actions with respect to its Securities or any securities convertible into or exchangeable or exercisable for any of
 
14

 
its Securities (“Lock-Up Securities”): (i) offer, sell, issue, contract to sell, pledge or otherwise dispose of Lock-Up Securities, (ii) offer, sell, issue, contract to sell, contract to purchase, or grant any option, right or warrant to purchase Lock-Up Securities, (iii) enter into any swap, hedge or any other agreement that transfers, in whole or in part, the economic consequences of ownership of Lock-Up Securities, (iv) establish or increase a put equivalent position or liquidate or decrease a call equivalent position in Lock-Up Securities within the meaning of Section 16 of the Exchange Act or (v) file with the Commission a registration statement under the Act relating to Lock-Up Securities, or publicly disclose the intention to take any such action, without the prior written consent of the Representatives.  The initial Lock-Up Period will commence on the date hereof and continue for 180 days after the date hereof or such earlier date that the Representatives consent to in writing; provided, however, that if (1) during the last 17 days of the initial Lock-Up Period, the Company releases earnings results or material news or a material event relating to the Company occurs or (2) prior to the expiration of the initial Lock-Up Period, the Company announces that it will release earnings results during the 16-day period beginning on the last day of the initial Lock-Up Period, then in each case the Lock-Up Period will be extended until the expiration of the 18-day period beginning on the date of release of the earnings results or the occurrence of the material news or material event, as applicable, unless the Representatives waive, in writing, such extension.  The Company will provide the Representatives with notice of any announcement described in clause (2) of the preceding sentence that gives rise to an extension of the Lock-Up Period.  These restrictions in this Section 5(l) shall not apply to (v) the sale of Securities to the Underwriters; (w) the issuance of Securities pursuant to the terms of the Plan of Reorganization as described in the General Disclosure Package; (x) the issuance of units of Kosmos Energy Holdings prior to the Closing Date as described in the General Disclosure Package; (y) grants of restricted shares, restricted share units or share options in accordance with the terms of an incentive plan existing on the Closing Date and described in the General Disclosure Package, and the exercise of such grants thereof; and (z) the repurchase by the Company of one common share of the Company which was originally issued to Pembroke Company Limited in connection with the incorporation of the Company under the laws of Bermuda.
 
(m) Transfer Restrictions.  In connection with the Directed Share Program, the Company will ensure that the Directed Shares will be restricted to the extent required by FINRA or the FINRA rules from sale, transfer, assignment, pledge or hypothecation for a period of three months following the date of the effectiveness of the Registration Statement. The Designated Underwriter will notify the Company as to which Participants will need to be so restricted. The Company will direct the transfer agent to place stop transfer restrictions upon such securities for such period of time.
 
(n) Payment of Expenses Related to Directed Share Program.  The Company will pay all fees and disbursements of counsel (including non-U.S. counsel) incurred by the Underwriters in connection with the Directed Share Program and stamp duties, similar taxes or duties or other taxes, if any, incurred by the underwriters in connection with the Directed Share Program.
 
(o) Compliance with Foreign Laws.  The Company will comply with all applicable securities and other applicable laws, rules and regulations in each foreign jurisdiction in which the Directed Shares are offered in connection with the Directed Share Program.
 
6.  Free Writing Prospectuses. The Company represents and agrees that, unless it obtains the prior consent of the Representatives, and each Underwriter represents and agrees that, unless it obtains the prior consent of the Company and the Representatives, it has not made and will not make any offer relating to the Offered Securities that would constitute an Issuer Free Writing Prospectus, or that would otherwise constitute a “free writing prospectus,” as defined in Rule 405, required to be filed with the Commission.  Any such free writing prospectus consented to by the Company and the Representatives is hereinafter referred to as a “ Permitted Free Writing Prospectus .”  The Company represents that it has treated and agrees that it will treat each Permitted Free Writing Prospectus as an “issuer free writing prospectus,” as defined in Rule 433, and has complied and will comply with the requirements of Rules 164 and 433 applicable to any Permitted Free Writing Prospectus, including timely Commission filing where required,
 
15

 
legending and record keeping.  The Company represents that it has satisfied and agrees that it will satisfy the conditions in Rule 433 to avoid a requirement to file with the Commission any electronic road show.
 
7.  Conditions of the Obligations of the Underwriters. The obligations of the several Underwriters to purchase and pay for the Firm Securities on the First Closing Date and the Optional Securities to be purchased on each Optional Closing Date will be subject to the accuracy of the representations and warranties of the Company herein (as though made on such Closing Date), to the accuracy of the statements of Company officers made pursuant to the provisions hereof, to the performance by the Company of its obligations hereunder and to the following additional conditions precedent:
 
(a)  Accountants’ Comfort Letter.  The Representatives shall have received letters, dated, respectively, the date hereof and each Closing Date, of  Ernst & Young LLP confirming that they are a registered public accounting firm and independent public accountants within the meaning of the Securities Laws and in form and substance acceptable to the Representatives.
 
(b)  Effectiveness of Registration Statement.  If the Effective Time of the Additional Registration Statement (if any) is not prior to the execution and delivery of this Agreement, such Effective Time shall have occurred not later than 10:00 P.M., New York time, on the date of this Agreement or, if earlier, the time the Final Prospectus is finalized and distributed to any Underwriter, or shall have occurred at such later time as shall have been consented to by the Representatives.  The Final Prospectus shall have been filed with the Commission in accordance with the Rules and Regulations and Section 5(a) hereof. Prior to such Closing Date, no stop order suspending the effectiveness of a Registration Statement shall have been issued and no proceedings for that purpose shall have been instituted or, to the knowledge of the Company or the Representatives, shall be contemplated by the Commission.
 
(c)  No Material Adverse Change.  Subsequent to the execution and delivery of this Agreement, there shall not have occurred (i) any change, or any development or event involving a prospective change, in the condition (financial or otherwise), results of operations, business, properties or prospects of the Company and its subsidiaries taken as a whole which, in the sole judgment of the Representatives, is material and adverse and makes it impractical or inadvisable to market the Offered Securities; (ii) any change in either U.S. or international financial, political or economic conditions or currency exchange rates or exchange controls the effect of which is such as to make it, in the sole judgment of the Representatives, impractical to market or to enforce contracts for the sale of the Offered Securities, whether in the primary market or in respect of dealings in the secondary market; (iii) any suspension or material limitation of trading in securities generally on the New York Stock Exchange, or any setting of minimum or maximum prices for trading on such exchange; (iv) or any suspension of trading of any securities of the Company on any exchange or in the over-the-counter market; (v) any banking moratorium declared by any U.S. federal or New York authorities; (vi) any major disruption of settlements of securities, payment or clearance services in the United States or any other country where such securities are listed or (vii) any attack on, outbreak or escalation of hostilities or act of terrorism involving the United States, any declaration of war by Congress or any other national or international calamity or emergency if, in the sole judgment of the Representatives, the effect of any such attack, outbreak, escalation, act, declaration, calamity or emergency is such as to make it impractical or inadvisable to market the Offered Securities or to enforce contracts for the sale of the Offered Securities.
 
(d)  Opinion of Counsels for the Company.  The Representatives shall have received (i) an opinion and 10b-5 letter, each dated such Closing Date, of Davis Polk & Wardwell LLP, U.S. counsel for the Company in the form of Schedule E hereto, and (ii) an opinion, dated such Closing date, of Conyers Dill & Pearman Limited, Bermuda counsel to the Company in the form of Schedule F hereto.
 
(e) Opinion of Counsel for Underwriters.  The Representatives shall have received from Shearman & Sterling LLP, counsel for the Underwriters, such opinion or opinions, dated such Closing Date, with respect to such matters as the Representatives may require, and the Company
 
16

 
shall have furnished to such counsel such documents as they request for the purpose of enabling them to pass upon such matters.
 
(f)  Officer’s Certificate.  The Representatives shall have received a certificate, dated such Closing Date, of an executive officer of the Company and a principal financial or accounting officer of the Company in which such officers shall state that: the representations and warranties of the Company in this Agreement are true and correct; the Company has complied with all agreements and satisfied all conditions on its part to be performed or satisfied hereunder at or prior to such Closing Date; no stop order suspending the effectiveness of any Registration Statement has been issued and no proceedings for that purpose have been instituted or, to the best of their knowledge and after reasonable investigation, are contemplated by the Commission; the Additional Registration Statement (if any) satisfying the requirements of subparagraphs (1) and (3) of Rule 462(b) was timely filed pursuant to Rule 462(b), including payment of the applicable filing fee in accordance with Rule 111(a) or (b) of Regulation S-T of the Commission; and, subsequent to the date of the most recent financial statements in the General Disclosure Package, there has been no material adverse change, nor any development or event involving a prospective material adverse change, in the condition (financial or otherwise), results of operations, business, properties or prospects of the Company and its subsidiaries taken as a whole except as set forth in the General Disclosure Package or as described in such certificate.
 
(g)  Lock-Up Agreements.  On or prior to the date hereof, the Representatives shall have received lockup letters from each of the persons listed in Schedule D hereto.
 
(h)  NSAI Letter.  The Representatives shall have received letters, dated, respectively, the date hereof and each Closing Date, of NSAI, in the form of Schedule C hereto.
 
(i)  Corporate Reorganization.  As of the First Closing Date, all transactions described in the General Disclosure Package and the Final Prospectus under the heading “Corporate Reorganization” shall have been completed substantially in the manner described therein.
 
The Company will furnish the Representatives with such conformed copies of such opinions, certificates, letters and documents as the Representatives reasonably request.  The Representatives may in their sole discretion waive on behalf of the Underwriters compliance with any conditions to the obligations of the Underwriters hereunder, whether in respect of an Optional Closing Date or otherwise.
 
8.  Indemnification and Contribution.  (a)  Indemnification of Underwriters by Company.  The Company will indemnify and hold harmless each Underwriter, its partners, members, directors, officers, employees, agents, affiliates and each person, if any, who controls such Underwriter within the meaning of Section 15 of the Act or Section 20 of the Exchange Act (each an “ Indemnified Party ”), against any and all losses, claims, damages or liabilities, joint or several, to which such Indemnified Party may become subject, under the Act, the Exchange Act, other Federal or state statutory law or regulation or otherwise, insofar as such losses, claims, damages or liabilities (or actions in respect thereof) arise out of or are based upon any untrue statement or alleged untrue statement of any material fact contained in any part of any Registration Statement at any time, any Statutory Prospectus as of any time, the Final Prospectus or any Issuer Free Writing Prospectus, or arise out of or are based upon the omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein not misleading, and will reimburse each Indemnified Party for any legal or other expenses reasonably incurred by such Indemnified Party in connection with investigating or defending against any loss, claim, damage, liability, action, litigation, investigation or proceeding whatsoever (whether or not such Indemnified Party is a party thereto), whether threatened or commenced, and in connection with the enforcement of this provision with respect to any of the above as such expenses are incurred; provided, however, that the Company will not be liable in any such case to the extent that any such loss, claim, damage or liability arises out of or is based upon an untrue statement or alleged untrue statement in or omission or alleged omission from any of such documents in reliance upon and in conformity with written information furnished to the Company by any Underwriter through the Representatives specifically for use therein, it being understood and agreed that the only such information furnished by any Underwriter consists of the information described as such in subsection (c) below.
 
17

 
The Company agrees to indemnify and hold harmless the Designated Underwriter and its affiliates and each person, if any, who controls the Designated Underwriter within the meaning of either Section 15 of the Act or Section 20 of the Exchange Act (the “ Designated Entities” ), from and against any and all losses, claims, damages and liabilities (including, without limitation, any legal or other expenses reasonably incurred in connection with defending or investigating any such action or claim) (i) arising out of or based upon any untrue statement or alleged untrue statement of a material fact contained in any material prepared by or with the consent of the Company for distribution to Participants in connection with the Directed Share Program or arising out of or based upon any omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein not misleading; (ii) arising out of or based upon the failure of any Participant to pay for and accept delivery of Directed Shares that the Participant agreed to purchase; or (iii) arising out of, related to, or in connection with the Directed Share Program, other than losses, claims, damages or liabilities (or expenses relating thereto) that are finally judicially determined to have resulted from the willful misconduct or gross negligence of the Designated Entities.
 
(b)  Indemnification of Company.  Each Underwriter will severally and not jointly indemnify and hold harmless the Company, each of its directors and each of its officers who signs a Registration Statement and each person, if any, who controls the Company within the meaning of Section 15 of the Act or Section 20 of the Exchange Act (each, an “ Underwriter Indemnified Party ”) against any losses, claims, damages or liabilities to which such Underwriter Indemnified Party may become subject, under the Act, the Exchange Act, or other Federal or state statutory law or regulation or otherwise, insofar as such losses, claims, damages or liabilities (or actions in respect thereof) arise out of or are based upon any untrue statement or alleged untrue statement of any material fact contained in any Registration Statement at any time, any Statutory Prospectus at any time, the Final Prospectus or any Issuer Free Writing Prospectus or arise out of or are based upon the omission or the alleged omission of a material fact required to be stated therein or necessary to make the statements therein not misleading, in each case to the extent, but only to the extent, that such untrue statement or alleged untrue statement or omission or alleged omission was made in reliance upon and in conformity with written information furnished to the Company by such Underwriter through the Representatives specifically for use therein, and will reimburse any legal or other expenses reasonably incurred by such Underwriter Indemnified Party in connection with investigating or defending against any such loss, claim, damage, liability, action, litigation, investigation or proceeding whatsoever (whether or not such Underwriter Indemnified Party is a party thereto), whether threatened or commenced, based upon any such untrue statement or omission, or any such alleged untrue statement or omission as such expenses are incurred, it being understood and agreed that the only such information furnished by any Underwriter consists of the following information in the Final Prospectus furnished on behalf of each Underwriter: the concession and reallowance figures appearing in the fourth paragraph under the caption “Underwriting”, the information contained in the sixth paragraph under the caption “Underwriting” with respect to sales to discretionary accounts, and the information contained in the fifteenth paragraph under the caption “Underwriting”.
 
(c)  Actions against Parties; Notification.  Promptly after receipt by an indemnified party under this Section of notice of the commencement of any action, such indemnified party will, if a claim in respect thereof is to be made against an indemnifying party under subsection (a) or (b) above, notify the indemnifying party of the commencement thereof; but the failure to notify the indemnifying party shall not relieve it from any liability that it may have under subsection (a) or (b) above except to the extent that it has been materially prejudiced (through the forfeiture of substantive rights or defenses) by such failure; and provided further that the failure to notify the indemnifying party shall not relieve it from any liability that it may have to an indemnified party otherwise than under subsection (a) or (b) above.  In case any such action is brought against any indemnified party and it notifies an indemnifying party of the commencement thereof, the indemnifying party will be entitled to participate therein and, to the extent that it may wish, jointly with any other indemnifying party similarly notified, to assume the defense thereof, with counsel satisfactory to such indemnified party (who shall not, except with the consent of the indemnified party, be counsel to the indemnifying party), and after notice from the indemnifying party to such indemnified party of its election so to assume the defense thereof, the indemnifying party will not be liable to such indemnified party under this Section for any legal or other expenses subsequently incurred by such indemnified party in connection with the defense thereof other than reasonable costs of investigation. Notwithstanding anything contained herein to the contrary, if indemnity may be sought pursuant to the last paragraph in Section 8 (a) hereof in respect
 
18

 
of such action or proceeding, then in addition to such separate firm for the indemnified parties, the indemnifying party shall be liable for the reasonable fees and expenses of not more than one separate firm (in addition to any local counsel) for the Designated Underwriter for the defense of any losses, claims, damages and liabilities arising out of the Directed Share Program, and all persons, if any, who control the Designated Underwriter within the meaning of either Section 15 of the Act of Section 20 of the Exchange Act. No indemnifying party shall, without the prior written consent of the indemnified party, effect any settlement of any pending or threatened action in respect of which any indemnified party is or could have been a party and indemnity could have been sought hereunder by such indemnified party unless such settlement (i) includes an unconditional release of such indemnified party from all liability on any claims that are the subject matter of such action and (ii) does not include a statement as to, or an admission of, fault, culpability or a failure to act by or on behalf of an indemnified party.
 
(d)  Contribution.  If the indemnification provided for in this Section is unavailable or insufficient to hold harmless an indemnified party under subsection (a) or (b) above, then each indemnifying party shall contribute to the amount paid or payable by such indemnified party as a result of the losses, claims, damages or liabilities referred to in subsection (a) or (b) above (i) in such proportion as is appropriate to reflect the relative benefits received by the Company on the one hand and the Underwriters on the other from the offering of the Securities or (ii) if the allocation provided by clause (i) above is not permitted by applicable law, in such proportion as is appropriate to reflect not only the relative benefits referred to in clause (i) above but also the relative fault of the Company on the one hand and the Underwriters on the other in connection with the statements or omissions which resulted in such losses, claims, damages or liabilities as well as any other relevant equitable considerations. The relative benefits received by the Company on the one hand and the Underwriters on the other shall be deemed to be in the same proportion as the total net proceeds from the offering (before deducting expenses) received by the Company bear to the total underwriting discounts and commissions received by the Underwriters. The relative fault shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact relates to information supplied by the Company or the Underwriters and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such untrue statement or omission. The amount paid by an indemnified party as a result of the losses, claims, damages or liabilities referred to in the first sentence of this subsection (d) shall be deemed to include any legal or other expenses reasonably incurred by such indemnified party in connection with investigating or defending any action or claim which is the subject of this subsection (d). Notwithstanding the provisions of this subsection (d), no Underwriter shall be required to contribute any amount in excess of the amount by which the total price at which the Securities underwritten by it and distributed to the public were offered to the public exceeds the amount of any damages which such Underwriter has otherwise been required to pay by reason of such untrue or alleged untrue statement or omission or alleged omission.  No person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Act) shall be entitled to contribution from any person who was not guilty of such fraudulent misrepresentation. The Underwriters’ obligations in this subsection (d) to contribute are several in proportion to their respective underwriting obligations and not joint.  The Company and the Underwriters agree that it would not be just and equitable if contribution pursuant to this Section 8(d) were determined by pro rata allocation (even if the Underwriters were treated as one entity for such purpose) or by any other method of allocation which does not take account of the equitable considerations referred to in this Section 8(d).
 
9.  Default of Underwriters.  If any Underwriter or Underwriters default in their obligations to purchase Offered Securities hereunder on either the First or any Optional Closing Date and the aggregate number of shares of Offered Securities that such defaulting Underwriter or Underwriters agreed but failed to purchase does not exceed 10% of the total number of shares of Offered Securities that the Underwriters are obligated to purchase on such Closing Date, the Representatives may make arrangements satisfactory to the Company for the purchase of such Offered Securities by other persons, including any of the Underwriters, but if no such arrangements are made by such Closing Date, the non-defaulting Underwriters shall be obligated severally, in proportion to their respective commitments hereunder, to purchase the Offered Securities that such defaulting Underwriters agreed but failed to purchase on such Closing Date. If any Underwriter or Underwriters so default and the aggregate number of shares of Offered Securities with respect to which such default or defaults occur exceeds 10% of the total number of shares of Offered Securities that the Underwriters are obligated to purchase on such Closing Date and arrangements satisfactory to the
 
19

 
Representatives and the Company for the purchase of such Offered Securities by other persons are not made within 36 hours after such default, this Agreement will terminate without liability on the part of any non-defaulting Underwriter or the Company, except as provided in Section 10 (provided that if such default occurs with respect to Optional Securities after the First Closing Date, this Agreement will not terminate as to the Firm Securities or any Optional Securities purchased prior to such termination). As used in this Agreement, the term “Underwriter” includes any person substituted for an Underwriter under this Section. Nothing herein will relieve a defaulting Underwriter from liability for its default.
 
10.  Survival of Certain Representations and Obligations.  The respective indemnities, agreements, representations, warranties and other statements of the Company or its officers and of the several Underwriters set forth in or made pursuant to this Agreement will remain in full force and effect, regardless of any investigation, or statement as to the results thereof, made by or on behalf of any Underwriter, the Company or any of their respective representatives, officers or directors or any controlling person, and will survive delivery of and payment for the Offered Securities. If the purchase of the Offered Securities by the Underwriters is not consummated for any reason other than solely because of the termination of this Agreement pursuant to Section 9 hereof, the Company will reimburse the Underwriters for all out-of-pocket expenses (including fees and disbursements of counsel) reasonably incurred by them in connection with the offering of the Offered Securities, and the respective obligations of the Company and the Underwriters pursuant to Section 8 hereof shall remain in effect.  In addition, if any Offered Securities have been purchased hereunder, the representations and warranties in Section 2 and all obligations under Section 5 shall also remain in effect.
 
11.  Notices. All communications hereunder will be in writing and, if sent to the Underwriters, will be mailed, delivered or telefaxed and confirmed to the Representatives at Citigroup Global Markets Inc., 388 Greenwich Street, New York, NY 10013, (fax:  (212) 816-7912), Attention: General Counsel; and Barclays Capital Inc. at 745 Seventh Avenue, New York, NY 10019, (fax:  (646) 834-8133), Attention:  Syndicate Registration, with a copy, in the case of any notice pursuant to Section 9 hereof, to the Director of Litigation, Office of the General Counsel, Barclays Capital Inc., 745 Seventh Avenue, New York, NY 10019; and Credit Suisse Securities (USA) LLC, Eleven Madison Avenue, New York, N.Y. 10010-3629, Attention:  LCD-IBD; with a copy to Shearman & Sterling LLP, 599 Lexington Avenue, New York, NY 10022, Attention: David J. Beveridge, Esq., or, if sent to the Company, will be mailed or delivered and confirmed to it at Kosmos Energy Ltd., c/o Kosmos Energy, LLC, 8176 Park Lane, Suite 500, Dallas, TX 75231, Attention: General Counsel, with a copy to Davis Polk & Wardwell LLP, 450 Lexington Avenue, New York, NY 10017, Attention: Richard D. Truesdell, Jr., Esq; provided, however, that any notice to an Underwriter pursuant to Section 8 will be mailed, delivered or telegraphed and confirmed to such Underwriter.
 
12.  Successors. This Agreement will inure to the benefit of and be binding upon the parties hereto and their respective successors and the officers and directors and controlling persons referred to in Section 7, and no other person will have any right or obligation hereunder.
 
13.  Representation.  The Representatives will act for the several Underwriters in connection with the transactions contemplated by this Agreement, and any action under this Agreement taken by the Representatives jointly will be binding upon all the Underwriters.
 
14.  Counterparts.  This Agreement may be executed in any number of counterparts, each of which shall be deemed to be an original, but all such counterparts shall together constitute one and the same Agreement.
 
15.  Absence of Fiduciary Relationship.  The Company acknowledges and agrees that:
 
(a)  No Other Relationship.  The Representatives have been retained solely to act as underwriters in connection with the sale of the Offered Securities and that no fiduciary, advisory or agency relationship between the Company and the Representatives has been created in respect of any of the transactions contemplated by this Agreement or the Final Prospectus, irrespective of whether the Representatives have advised or are advising the Company on other matters;
 
20

 
(b) Arms’ Length Negotiations.  The price of the Offered Securities set forth in this Agreement was established by the Company following discussions and arms-length negotiations with the Representatives and the Company is capable of evaluating and understanding and understands and accepts the terms, risks and conditions of the transactions contemplated by this Agreement;
 
(c) Absence of Obligation to Disclose.  The Company has been advised that the Representatives and their affiliates are engaged in a broad range of transactions which may involve interests that differ from those of the Company and that the Representatives have no obligation to disclose such interests and transactions to the Company by virtue of any fiduciary, advisory or agency relationship; and
 
(d)  Waiver.  The Company waives, to the fullest extent permitted by law, any claims it may have against the Representatives for breach of fiduciary duty or alleged breach of fiduciary duty and agrees that the Representatives shall have no liability (whether direct or indirect) to the Company in respect of such a fiduciary duty claim or to any person asserting a fiduciary duty claim on behalf of or in right of the Company, including shareholders, employees or creditors of the Company.
 
16.  Patriot Act Notice.  In accordance with the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)), the Underwriters are required to obtain, verify and record information that identifies their respective clients, including the Company, which information may include the name and address of their respective clients, as well as other information that will allow the Underwriters to properly identify their respective clients.
 
17.  Applicable Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of New York.
 
The Company hereby submits to the non-exclusive jurisdiction of the Federal and state courts in the Borough of Manhattan in The City of New York in any suit or proceeding arising out of or relating to this Agreement or the transactions contemplated hereby.  The Company irrevocably and unconditionally waives any objection to the laying of venue of any suit or proceeding arising out of or relating to this Agreement or the transactions contemplated hereby in Federal and state courts in the Borough of Manhattan in the City of New York and irrevocably and unconditionally waives and agrees not to plead or claim in any such court that any such suit or proceeding in any such court has been brought in an inconvenient forum.
 
The obligation of the Company pursuant to this Agreement in respect of any sum due to any Underwriter shall, notwithstanding any judgment in a currency other than United States dollars, not be discharged until the first business day, following receipt by such Underwriter of any sum adjudged to be so due in such other currency, on which (and only to the extent that) such Underwriter may in accordance with normal banking procedures purchase United States dollars with such other currency; if the United States dollars so purchased are less than the sum originally due to such Underwriter hereunder, the Company agrees, as a separate obligation and notwithstanding any such judgment, to indemnify such Underwriter against such loss.  If the United States dollars so purchased are greater than the sum originally due to such Underwriter hereunder, such Underwriter agrees to pay to the Company an amount equal to the excess of the dollars so purchased over the sum originally due to such Underwriter hereunder.
 
21

 
If the foregoing is in accordance with the Representatives’ understanding of our agreement, kindly sign and return to the Company one of the counterparts hereof, whereupon it will become a binding agreement, between the Company and the several Underwriters in accordance with its terms.
 
 	 	Very truly yours,	 	
 	 	 	 	
 	 	KOSMOS ENERGY LTD.	 	

 	 	By:	 	 	
 	 	 	Name:	 	
 	 	 	Title:	 	
 	 	 	 	 	
The foregoing Underwriting Agreement is hereby confirmed and accepted as of the date first above written.	 	 	
 	 	 	
 	CITIGROUP GLOBAL MARKETS INC.	 	 	
 	 	 	
 	By:	 	 	 	
 	 	Name:	 	 	
 	 	Title:	 	 	

 	BARCLAYS CAPITAL INC.	 	 	
 	 	 	
 	By:	 	 	 	
 	 	Name:	 	 	
 	 	Title:	 	 	

 	CREDIT SUISSE SECURITIES (USA) LLC	 	 	
 	 	 	
 	By:	 	 	 	
 	 	Name:	 	 	
 	 	Title:	 	 	

 	Acting on behalf of themselves and as Representatives of the Several Underwriters.	 	 	

22

 
SCHEDULE A
 
Underwriter	 	Number of
Firm Securities
to be Purchased	
Citigroup Global Markets Inc.	 	[·]	
Barclays Capital Inc.	 	[·]	
Credit Suisse Securities (USA) LLC	 	[·]	
BNP Paribas Securities Corp.	 	[·]	
SG Americas Securities, LLC.	 	[·]	
Credit Agricole Securities (USA) Inc.	 	[·]	
Howard Weil Incorporated.	 	[·]	
HSBC Securities (USA) Inc.	 	[·]	
Jefferies & Company, Inc.	 	[·]	
Natixis Bleichroeder LLC.	 	[·]	
RBC Capital Markets, LLC.	 	[·]	
Total	 	[·]	
 
23

 
SCHEDULE B
 
1.             General Use Free Writing Prospectuses (included in the General Disclosure Package)
 
“General Use Issuer Free Writing Prospectus” includes each of the following documents:
 
1.  The Pricing Term Sheet attached as Annex I to this Schedule B.
 
2.             Other Information Included in the General Disclosure Package
 
The following information is also included in the General Disclosure Package:
 
None.
 
24

 
ANNEX I
 
TO SCHEDULE B
 
FORM OF PRICING TERM SHEET
 
25

 
SCHEDULE C
 
FORM OF LETTER OF
NETHERLAND, SEWELL & ASSOCIATES, INC.
 
26

 
SCHEDULE D
 
LIST OF PERSONS SUBJECT TO LOCK-UP AGREEMENTS
PURSUANT TO SECTION 7(g)
 
27

 
SCHEDULE E
 
FORM OF OPINION OF
DAVIS POLK & WARDWELL LLP
 
28

 
SCHEDULE F
 
FORM OF OPINION OF
CONYERS DILL & PEARMAN LIMITED
 
29

Exhibit 4.1
 
 	THIS CERTIFIES THAT is the registered holder of CUSIP DATED COUNTERSIGNED AND REGISTERED: COMPUTERSHARE TRUST COMPANY, N.A. TRANSFER AGENT AND REGISTRAR, COMMON SHARES PAR VALUE $0.01 COMMON SHARES THIS CERTIFICATE IS TRANSFERABLE IN CANTON, MA AND NEW YORK, NY SEE REVERSE FOR CERTAIN DEFINITIONS Certificate Number Shares . KOSMOS ENERGY LTD. INCORPORATED UNDER THE LAWS OF BERMUDA Chief Executive Officer Corporate Secretary By AUTHORISED SIGNATURE fully paid and non-assessable common shares of the par value of US $0.01 each in the share capital of Kosmos Energy Ltd. (hereinafter called the “Company”), subject to the Memorandum of Association and Bye-Laws of the Company and transferable in accordance therewith. This certificate is not valid until countersigned by the Transfer Agent and registered by the Registrar. Witness, the facsimile seal of the Company and the facsimile signatures of its duly authorised officers. 016570| 003590|127C|RESTRICTED||4|057-423 G5315B 10 7 <<Month Day, Year>> * * 000000* * * * * * * * * 000000* * * * * * * * * 000000* * * * * * * * * 000000* * * * * * * * * 000000* * ** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Alexander David Sample **** Mr. Sample **** Mr. Sample **000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares*** *000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares**** 000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****0 00000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****00 0000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000 000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****0000 00**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****00000 0**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000 **Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000* *Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000** Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**Shares****000000**S ***ZERO HUNDRED THOUSAND ZERO HUNDRED AND ZERO*** MR. SAMPLE & MRS. SAMPLE & MR. SAMPLE & MRS. SAMPLE NNNNN ZQ 000000	

 
 	For value received, ____________________________hereby sell, assign and transfer unto _______________________________________________________________________________________________________________________________ _______________________________________________________________________________________________________________________________ _______________________________________________________________________________________________________________________________ _______________________________________________________________________________________________________________________ Shares _______________________________________________________________________________________________________________________ Attorney Dated: __________________________________________20__________________ Signature: ____________________________________________________________ Signature: ____________________________________________________________ Notice: The signature to this assignment must correspond with the name as written upon the face of the certificate, in every particular, without alteration or enlargement, or any change whatever. PLEASE INSERT SOCIAL SECURITY OR OTHER IDENTIFYING NUMBER OF ASSIGNEE (PLEASE PRINT OR TYPEWRITE NAME AND ADDRESS, INCLUDING POSTAL ZIP CODE, OF ASSIGNEE) represented by the within Certificate, and do hereby irrevocably constitute and appoint to transfer the said Shares on the books of the within-named Company with full power of substitution in the premises. . KOSMOS ENERGY LTD. (THE “COMPANY”) THE COMPANY WILL FURNISH WITHOUT CHARGE TO EACH REGISTERED HOLDER WHO SO REQUESTS, A SUMMARY OF THE POWERS, DESIGNATIONS, PREFERENCES AND RELATIVE, PARTICIPATING, OPTIONAL OR OTHER SPECIAL RIGHTS OF EACH CLASS OF SHARES OF THE COMPANY AND THE QUALIFICATIONS, LIMITATIONS OR RESTRICTIONS OF SUCH PREFERENCES AND RIGHTS, AND THE VARIATIONS IN RIGHTS, PREFERENCES AND LIMITATIONS DETERMINED FOR EACH SERIES, WHICH ARE FIXED BY THE MEMORANDUM OF ASSOCIATION AND BYE-LAWS OF THE COMPANY, AS AMENDED, AND THE RESOLUTIONS OF THE BOARD OF DIRECTORS OF THE COMPANY, AND THE AUTHORITY OF THE BOARD OF DIRECTORS TO DETERMINE VARIATIONS FOR FUTURE SERIES. SUCH REQUEST MAY BE MADE TO THE OFFICE OF THE SECRETARY OF THE COMPANY OR TO THE TRANSFER AGENT. THE BOARD OF DIRECTORS MAY REQUIRE THE REGISTERED HOLDER OF A LOST OR DESTROYED SHARE CERTIFICATE, OR HIS LEGAL REPRESENTATIVES, TO GIVE THE COMPANY A BOND TO INDEMNIFY IT AND ITS TRANSFER AGENTS AND REGISTRARS AGAINST ANY CLAIM THAT MAY BE MADE AGAINST THEM ON ACCOUNT OF THE ALLEGED LOSS OR DESTRUCTION OF ANY SUCH CERTIFICATE. Signature(s) Guaranteed: Medallion Guarantee Stamp THE SIGNATURE(S) SHOULD BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (Banks, Stockbrokers, Savings and Loan Associations and Credit Unions) WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM, PURSUANT TO S.E.C. RULE 17Ad-15. The following abbreviations, when used in the inscription on the face of this certificate, shall be construed as though they were written out in full according to applicable laws or regulations: TEN COM - as tenants in common UNIF GIFT MIN ACT - Custodian (Cust) (Minor) TEN ENT - as tenants by the entireties under Uniform Gifts to Minors Act (State) JT TEN - as joint tenants with right of survivorship UNIF TRF MIN ACT - Custodian (until age ) (Cust) under Uniform Transfers to Minors Act (Minor) (State) Additional abbreviations may also be used though not in the above list.	

Exhibit 5.1
 
18 April 2011
 
Kosmos Energy Ltd.
Clarendon House
2 Church Street
Hamilton, HM 11
Bermuda	 	Direct Line: 441-2994993
E-Mail: jason.piney@conyersdill.com
Our Reference: JPX/339475/365833	
 
Dear Sirs,
 
Re: Kosmos Energy Ltd. (the “Company”)
 
We have acted as special Bermuda legal counsel to the Company in connection with a registration statement on form S-1, as amended (Registration No. 333-171700) filed with the U.S. Securities and Exchange Commission (the “Commission”) on 13 January 2011 (the “Registration Statement”, which term does not include any other document or agreement whether or not specifically referred to therein or attached as an exhibit or schedule thereto) relating to the registration under the U.S. Securities Act of 1933, as amended, (the “Securities Act”) of an aggregate of 30,000,000 common shares, par value US$0.01 each being offered by the Company together with an additional 4,500,000 common shares, par value US$0.01 each subject to an over-allotment option granted to the underwriters by the Company (together, the “Common Shares”).
 
For the purposes of giving this opinion, we have examined a copy of the Registration Statement. We have also reviewed the memorandum of association and the bye-laws of the Company, each certified by the Secretary of the Company on 18 April 2011, written resolutions of its directors dated 13 January 2011, written resolutions of its sole shareholder dated 14 April 2011 (together, the “Resolutions”) and such other documents and made such enquiries as to questions of law as we have deemed necessary in order to render the opinion set forth below.
 
We have assumed (a) the genuineness and authenticity of all signatures and the conformity to the originals of all copies (whether or not certified) examined by us and the authenticity and completeness of the originals from which such copies were taken, (b) that where a document has been examined by us in draft form, it will be or has been executed and/or filed in the form of that draft, and where a number of drafts of a document have been

 
examined by us all changes thereto have been marked or otherwise drawn to our attention,  (c) the accuracy and completeness of all factual representations made in the Registration Statement and other documents reviewed by us, (d) that the Resolutions were passed at one or more duly convened, constituted and quorate meetings, or by unanimous written resolutions, remain in full force and effect and have not been rescinded or amended, (e) that there is no provision of the law of any jurisdiction, other than Bermuda, which would have any implication in relation to the opinions expressed herein, (f) that upon issue of any shares the Company will receive consideration for the full issue price thereof which shall be equal to at least the par value thereof, (g) that a duly constituted pricing committee of the Company’s board of directors will have approved the terms of the offering of the Common Shares pursuant to the Registration Statement as contemplated by the Resolutions.
 
We have made no investigation of and express no opinion in relation to the laws of any jurisdiction other than Bermuda.  This opinion is to be governed by and construed in accordance with the laws of Bermuda and is limited to and is given on the basis of the current law and practice in Bermuda. This opinion is issued solely for the purposes of the filing of the Registration Statement and the offering of the Common Shares by the Company and is not to be relied upon in respect of any other matter.
 
On the basis of and subject to the foregoing, we are of the opinion that:
 
1.              The Company is duly incorporated and existing under the laws of Bermuda in good standing (meaning solely that it has not failed to make any filing with any Bermuda government authority or to pay any Bermuda government fees or tax which would make it liable to be struck off the Register of Companies and thereby cease to exist under the laws of Bermuda).
 
2.              When issued and paid for as contemplated by the Registration Statement, the Common Shares will be validly issued, fully paid and non-assessable (which term means when used herein that no further sums are required to be paid by the holders thereof in connection with the issue of such shares).
 
We hereby consent to the filing of this opinion as an exhibit to the Registration Statement and to the references to our firm under the caption “Legal Matters” in the prospectus forming a part of the Registration Statement.  In giving this consent, we do not hereby admit that we are experts within the meaning of Section 11 of the Securities Act or that we are within the category of persons whose consent is required under Section 7 of the Securities Act or the Rules and Regulations of the Commission promulgated thereunder.
 
Yours faithfully,
 
/s/ Conyers Dill & Pearman
 
Conyers Dill & Pearman Limited
 
2

Exhibit 10.17
 
EXECUTION VERSION
 
DATED 28 March 2011
 
KOSMOS ENERGY FINANCE INTERNATIONAL
as Original Borrower
 
- and -
 
KOSMOS ENERGY OPERATING, KOSMOS ENERGY INTERNATIONAL, KOSMOS ENERGY
DEVELOPMENT and KOSMOS ENERGY GHANA HC
as Guarantors
 
- and -
 
ABSA CAPITAL (A DIVISION OF ABSA BANK LIMITED), BNP PARIBAS, CRÉDIT
AGRICOLE CORPORATE AND INVESTMENT BANK, HSBC BANK PLC, SOCIÉTÉ
GÉNÉRALE, LONDON BRANCH AND STANDARD CHARTERED BANK
as Mandated Lead Arrangers and Underwriters
 
- and -
 
THE FINANCIAL INSTITUTIONS LISTED IN SCHEDULE 2
as Original Lenders

 
FACILITY AGREEMENT

 
Slaughter and May
One Bunhill Row
London
EC1Y 8YY
(SRG/JRR)
 
507147220

 
Contents
 
 	 	 	Page	
PART 1 INTERPRETATION	 	8	
 	 	 	 	
1.	Definitions and Interpretation	 	8	
 	 	 	 	
PART 2 CONDITIONS PRECEDENT	 	45	
 	 	 	 	
2.	Conditions Precedent	 	45	
 	 	 	 	
3.	The Facility	 	47	
 	 	 	 	
4.	Finance Parties’ Rights and Obligations	 	51	
 	 	 	 	
5.	Purpose	 	51	
 	 	 	 	
6.	Utilisation	 	52	
 	 	 	 	
7.	Letters of Credit — Utilisation	 	53	
 	 	 	 	
8.	Letters of Credit — General Provisions	 	58	
 	 	 	 	
PART 4 PAYMENTS, CANCELLATION, INTEREST AND FEES	 	65	
 	 	 	 	
9.	Repayment	 	65	
 	 	 	 	
10.	Prepayment and Cancellation	 	65	
 	 	 	 	
11.	Interest	 	71	
 	 	 	 	
12.	Interest Periods	 	73	
 	 	 	 	
13.	Changes to the Calculation of Interest	 	74	
 	 	 	 	
14.	Fees	 	75	
 	 	 	 	
PART 5 TAXES, INCREASED COSTS AND INDEMNITIES	 	77	
 	 	 	 	
15.	Tax Gross Up and Indemnities	 	77	
 	 	 	 	
16.	Increased Costs	 	79	
 	 	 	 	
17.	Other Indemnities	 	81	
 	 	 	 	
18.	Mitigation by the Lenders	 	82	
 	 	 	 	
PART 6 FORECASTS AND CALCULATIONS AND BORROWING BASE AMOUNT	 	83	
 
2

 
19.	Forecasts and Calculations	 	83	
 	 	 	 	
PART 7 BANKS ACCOUNTS, CASH MANAGEMENT AND RESERVE EQUITY	 	87	
 	 	 	 	
20.	Bank Accounts and Cash Management	 	87	
 	 	 	 	
21.	Operation of the Offshore Proceeds Accounts	 	90	
 	 	 	 	
22.	Debt Service Reserve Account	 	92	
 	 	 	 	
23.	Authorised Investments	 	93	
 	 	 	 	
PART 8 FINANCIAL AND PROJECT INFORMATION	 	95	
 	 	 	 	
24.	Information Undertakings	 	95	
 	 	 	 	
PART 9 GUARANTEE	 	103	
 	 	 	 	
25.	Guarantee and Indemnity	 	103	
 	 	 	 	
PART 10 REPRESENTATIONS, COVENANTS, EVENTS OF DEFAULT	 	106	
 	 	 	 	
26.	Representations	 	106	
 	 	 	 	
27.	Financial Covenants	 	110	
 	 	 	 	
28.	General Undertakings	 	110	
 	 	 	 	
29.	Events of Default	 	118	
 	 	 	 	
PART 11 CHANGES TO LENDERS AND OBLIGORS AND ROLES	 	124	
 	 	 	 	
30.	Changes to the Lenders	 	124	
 	 	 	 	
31.	Changes to the Obligors	 	128	
 	 	 	 	
32.	Role of the Agents and the Arranger	 	130	
 	 	 	 	
33.	Consultants	 	136	
 	 	 	 	
PART 12 ADMINISTRATION, COSTS AND EXPENSES	 	138	
 	 	 	 	
34.	Payment Mechanics	 	138	
 	 	 	 	
35.	Set-Off	 	140	
 	 	 	 	
36.	Costs and Expenses	 	141	
 	 	 	 	
37.	Notices	 	142	
 
3

 
38.	Calculations and Certificates	 	144	
 	 	 	 	
39.	Partial Invalidity	 	145	
 	 	 	 	
40.	Remedies and Waivers	 	145	
 	 	 	 	
41.	Amendments and Waivers	 	145	
 	 	 	 	
42.	Counterparts	 	147	
 	 	 	 	
PART 13 GOVERNING LAW AND ENFORCEMENT	 	148	
 	 	 	 	
43.	Governing Law	 	148	
 	 	 	 	
44.	Jurisdiction	 	148	
 	 	 	 	
45.	Service of Process	 	148	
 	 	 	 	
Schedule 1 The Initial Obligors	 	150	
 	 	 	
Schedule 2 The Original Lenders	 	151	
 	 	 	
Schedule 3 Conditions Precedent	 	152	
 	 	 	
Schedule 4 Utilisation Requests	 	156	
 	 	 	
Schedule 5 Amortisation Schedule	 	159	
 	 	 	
Schedule 6 Mandatory Cost Formulae	 	160	
 	 	 	
Schedule 7 Form of Transfer Certificate	 	163	
 	 	 	
Schedule 8 Form of Lender Accession Notice	 	165	
 	 	 	
Schedule 9 Form of Accession Letter	 	167	
 	 	 	
Schedule 10 Form of Resignation Letter	 	168	
 	 	 	
Schedule 11 Form of Compliance Certificate	 	169	
 	 	 	
Schedule 12 Form of Letter of Credit	 	171	
 	 	 	
Schedule 13 Form of Confidentiality Undertaking	 	175	
 	 	 	
Schedule 14 Form of Deed of Subordination	 	180	
 	 	 	
Schedule 15 Form of Sources and Uses Statement	 	196	
 	 	 	
Schedule 16 (Copy of ORGL LC)	 	198	
 
4

 
THIS AGREEMENTis dated 28 March 2011 and made between:
 
(1)                   KOSMOS ENERGY FINANCE INTERNATIONALa company incorporated under the laws of the Cayman Islands with registered number 253656 and having its registered office at P.O. Box 32322, 4 th Floor, Century Yard, Cricket Square, Elgin Avenue, George Town, Grand Cayman KY1-1209, Cayman Islands (the “ Original Borrower ”);
 
(2)                   KOSMOS ENERGY OPERATINGa company incorporated under the laws of the Cayman Islands with registered number 231417 and having its registered office at P.O. Box 32322, 4 th Floor, Century Yard, Cricket Square, Elgin Avenue, George Town, Grand Cayman KY1-1209, Cayman Islands (“ KEO ”);
 
(3)                   KOSMOS ENERGY INTERNATIONALa company incorporated under the laws of the Cayman Islands with registered number 218274 and having its registered office at P.O. Box 32322, 4 th Floor, Century Yard, Cricket Square, Elgin Avenue, George Town, Grand Cayman KY1-1209, Cayman Islands (“ KEI ”);
 
(4)                   KOSMOS ENERGY DEVELOPMENTa company incorporated under the laws of the Cayman Islands with registered number 225879 and having its registered office at P.O. Box 32322, 4 th Floor, Century Yard, Cricket Square, Elgin Avenue, George Town, Grand Cayman KY1-1209, Cayman Islands (“ KED ”);
 
(5)                   KOSMOS ENERGY GHANA HCa company incorporated under the laws of the Cayman Islands with registered number 135710 and having its registered office at P.O. Box 32322, 4 th Floor, Century Yard, Cricket Square, Elgin Avenue, George Town, Grand Cayman KY1-1209, Cayman Islands (“ KEG ”);
 
(6)                   ABSA CAPITAL (A DIVISION OF ABSA BANK LIMITED), BNP PARIBAS, CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANK, HSBC BANK PLC, SOCIÉTÉ GÉNÉRALE LONDON BRANCH AND STANDARD CHARTERED BANK as mandated lead arrangers of the Facility (each a “ Mandated Lead Arranger ” and together, the “ Mandated Lead Arrangers ”);
 
(7)                   ABSA CAPITAL (A DIVISION OF ABSA BANK LIMITED), BNP PARIBAS, CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANK, HSBC BANK PLC, SOCIÉTÉ GÉNÉRALE LONDON BRANCH AND STANDARD CHARTERED BANK as underwriters of the Facility (each an “ Underwriter ” and together, the “ Underwriters ”);
 
(8)                   THE FINANCIAL INSTITUTIONSlisted in Schedule 2 as lenders (the “Original Lenders”);
 
(9)                   SOCIÉTÉ GÉNÉRALE, LONDON BRANCH as the lead technical bank, CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANK  as co-technical bank and  HSBC BANK PLC  as co-technical bank (together referred to as the “ Technical Bank ”);
 
(10)            SOCIÉTÉ GÉNÉRALE, LONDON BRANCHas the lead modelling bank and CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANK  as co-modelling bank (together referred to as the “ Modelling Bank ”);
 
5

 
(11)            HSBC BANK PLCas the documentation bank (the “Documentation Bank”);
 
(12)            STANDARD CHARTERED BANKas onshore account bank on the terms and conditions set out in the KEG Onshore Project Accounts Agreement (the “ Onshore Account Bank ”);
 
(13)            HSBC BANK PLCas offshore account bank on the terms and conditions set out in the KEG Offshore Project Accounts Agreement and the Borrower Offshore Project Accounts Agreement (the “ Offshore Account Bank ”);
 
(14)            BNP PARIBASas agent of the Finance Parties under this Agreement (the “Facility Agent”);
 
(15)            BNP PARIBASin its capacity as Security Agent for the Secured Parties on the terms and conditions set out in the Intercreditor Agreement (the “ Security Agent ” which expression includes its successors in title and assigns or any person appointed as an additional trustee for the purpose of and in accordance with the Intercreditor Agreement); and
 
(16)            BNP PARIBASas the intercreditor agent (the “Intercreditor Agent”).
 
6

 
INTRODUCTION
 
(1)                    The Original Lenders have agreed to provide a secured, revolving and amortising loan and letter of credit facility for loans of up to USD 2 billion.
 
(2)                    The parties have agreed to enter into this Agreement for the purpose of setting out the provisions on which such facility will be provided.
 
7

 
PART 1
 
INTERPRETATION
 
1.                        DEFINITIONS AND INTERPRETATION
 
1.1                 Definitions
 
Each of the defined terms and interpretative provisions set out below and in the above list of parties to this Agreement shall apply to this Agreement and each Finance Document, unless an express contrary intention appears in that Finance Document.
 
“1992 ISDA Master Agreement” means the Master Agreement (Multicurrency Cross Border) as published by the International Swaps and Derivatives Association, Inc.
 
“2002 ISDA Master Agreement” means the 2002 Master Agreement as published by the International Swaps and Derivatives Association, Inc.
 
“Accession Letter” means a document substantially in the form set out in Schedule 8 (Form of Lender Accession Notice ) of this Agreement.
 
“Account Bank” means, as the context so requires, either the Onshore Account Bank, the Offshore Account Bank, or both of them.
 
“Accounting Reference Date” means 31 December of each year.
 
“Additional Borrower” means a company which accedes to the terms of this Agreement as an additional borrower in accordance with clause 31 ( Changes to the Obligors ) of this Agreement.
 
“Additional Commitment” has the meaning given to it in clause 3.3 (Additional Commitment).
 
“Additional Commitment Date” has the meaning given to that term in clause 3.3 (Additional Commitment) of this Agreement.
 
“Additional Cost Rate” has the meaning given to that term in Schedule 6 (Mandatory Cost Formulae) of this Agreement.
 
“Additional Debt” means, in relation to any debt, any money, debt or liability due, owing or incurred under or in connection with:
 
(A)               any refinancing, deferral, novation or extension of that debt;
 
(B)                 any further advance which may be made under any document, agreement or instrument supplemental to any relevant Finance Document together with any related interest, fees and costs;
 
(C)                 any claim for damages or restitution in the event of rescission of that debt or otherwise in connection with any relevant Finance Document;
 
8

 
(D)                any claim against Kosmos flowing from any recovery by Kosmos or any liquidator, receiver, administrator, administrative receiver, compulsory manager or other similar officer of a payment or discharge in respect of that debt on the grounds of preference or otherwise; and
 
(E)                  any amount (such as post-insolvency interest) which would be included in any of the above but for any discharge, non-provability, unenforceability or non-allowability of the same in any insolvency or other proceedings.
 
“Additional Guarantor” means a company which accedes to the terms of this Agreement as an additional guarantor in accordance with clause 31 ( Changes to the Obligors ) of this Agreement.
 
“Additional Lender” has the meaning given to it in clause 3.3 (Additional Commitment).
 
“Additional Obligor” means an Additional Borrower or an Additional Guarantor.
 
“Additional Oil Entitlement” shall have the meaning given to that term in the relevant Petroleum Agreement.
 
“Affected Administrative Party” has the meaning given to that term in clause 32.12(Replacement of Administrative Parties) of this Agreement.
 
“Affiliate” means, in relation to any person, a subsidiary of that person or a holding company of that person or any other subsidiary of that holding company.
 
“Agent” means each of the Facility Agent, the Security Agent, the Intercreditor Agent, the Technical Bank and the Modelling Bank and “ Agents ” shall be construed accordingly.
 
“Agreed Form” means in a form agreed between the Borrower (and/or KEG) and the Facility Agent.
 
“Agreed Insurances” means the insurances to be implemented and maintained by the Obligors in accordance with the Schedule of Insurances, to be formulated in consultation with the Insurance Consultant, but excluding any insurances to the extent that the cover to be maintained is not available on reasonable commercial terms or no longer reflects insurance which would be implemented and maintained in accordance with good oil industry practice or ceases to be generally available in the market and provided that a maximum aggregate of up to 30 per cent. of reinsurance may be effected through a self-insurance programmes of the Obligors (such self-insurance being captive insurance and excluding non-insurance).
 
“Amortisation Schedule” means the amortisation schedule set out in Schedule 5 (Amortisation Schedule) of this Agreement, as amended, supplemented or replaced from time to time.
 
“Approved Accounting Principles” means US generally accepted accounting principles to the extent applicable to the relevant financial statements.
 
9

 
“Approved Auditor” means any one of Deloitte LLP, Ernst & Young, PriceWaterhouse Coopers LLP or such other internationally recognised auditor as the Majority Lenders may approve from time to time (acting reasonably).
 
“Approved Development” means any Petroleum Asset in which an Obligor has an interest and which the Majority Lenders have agreed (acting reasonably) shall be a Borrowing Base Asset.
 
“Assignments” means the KEG Offshore Security Assignment, the KEG Onshore Security Assignment and the Assignment of Reinsurance Rights, together with any other Security Document entered into after the Signing Date which may give rise to a liability to pay stamp duty, documentary taxes or any other similar tax, charge or impost.
 
“Assignment of Reinsurance Rights” means the deed of insurance and reinsurance assignment to be entered into in accordance with the terms of this Agreement, between the insurers ,  the Security Agent and KEG.
 
“Authorisation” means an authorisation, consent, approval, resolution, licence, exemption, filing, notarisation or registration.
 
“Authorised Investment” means, at any time (subject to such being available), any of the following:
 
(A)               a US Dollar denominated institutional money market fund with at least USD 1 billion of funds and an average rate of maturity not exceeding one year;
 
(B)                 a US Dollar denominated freely negotiable and marketable bond, treasury bill or debt security of a remaining maturity not exceeding one year issued by the United States of America or any agency or instrumentality thereof, or by any other sovereign government with a long-term credit rating of at least A2 by Moody’s or A by Standard & Poor’s at such time;
 
(C)                 a US Dollar denominated time deposit (of an original maturity not exceeding six months) made in London or New York or any other place agreed between the Borrower and the Facility Agent with a bank authorised to carry on business there whose long-term debt securities are, at such time, rated at least A2 by Moody’s or A by Standard & Poor’s;
 
(D)                a US Dollar denominated instrument with a maturity of less than one year which has a short-term rating at such time of at least P1 by Moody’s or A1 by Standard & Poor’s or instruments with a maturity of less than one year issued by, or guaranteed by, entities whose short-term securities are rated at such time at least P1 by Moody’s or A1 by Standard & Poor’s; or
 
(E)                  any other investment agreed between the Facility Agent and the Borrower.
 
“Authorised Signatory” means, in relation to a company or other legal person:
 
(A)               one or more directors who are duly authorised whether singly or jointly, to act to bind that company or other legal person; or
 
10

 
 
(B)                 a person or persons duly authorised by that company or other legal person to act to bind that company or other legal person.
 
“Authority” means any governmental, provincial or local government, department, authority, court, tribunal or other judicial or regulatory body, instrumentality or agency in any of the countries where the Borrower operates its business.
 
“Availability Period” means the availability period in respect of the Facility as specified in clause 6.1 ( Availability Period ) of this Agreement.
 
“Available Commitment” means, at any time, a Lender’s Commitment minus:
 
(A)               the amount of its participation in any outstanding Loans; and
 
(B)                 in relation to any proposed Utilisation, the amount of its participation in any Loans that are due to be made on or before the proposed Utilisation Date,
 
other than that Lender’s participation in any Loans that are due to be repaid or prepaid on or before expiry of the Availability Period or all or a part of any Letters of Credit that have been cash collateralised by the Borrower depositing funds into the LC Cash Collateral Account.
 
“Base Currency” has the meaning given to it in clause 34.7 (Currency of account).
 
“Basel II” has the meaning given to it in clause 16.3 (Exceptions).
 
“Basel III” means the agreements on capital requirements, a leverage ratio and liquidity standards contained in “Basel III: A global regulatory framework for more resilient banks and banking systems”, “Basel III: International framework for liquidity risk measurement, standards and monitoring” and “Guidance for national authorities operating the countercyclical capital buffer” published by the Basel Committee on Banking Supervision on 16 December 2010.
 
“BBA Cure Period” has the meaning given to it in paragraph (A)(i) of clause 10.3 (Aggregate outstandings exceed the Borrowing Base Amount ) of this Agreement.
 
“Borrower” means the Original Borrower or any Additional Borrower unless it has ceased to be a Borrower in accordance with clause 31 ( Changes to the Obligors ).
 
“Borrower Insurance Proceeds Account” means an account designated “Borrower — Insurance Proceeds Account” established by the Original Borrower with the Offshore Account Bank in London pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement which is secured in favour of the Secured Parties.
 
“Borrower Offshore Proceeds Account” means an account designated “Borrower — Offshore” established by the Original Borrower with the Account Bank in London pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement which is secured in favour of the Secured Parties.
 
11

 
“Borrower Offshore Project Accounts Agreement” means the offshore project accounts agreement, dated on or about the date of this Agreement, between the Original Borrower, the Offshore Account Bank, the Facility Agent and the Security Agent.
 
“Borrower Offshore Security Assignment” means the English law security assignment and debenture, dated on or about the date of this Agreement, between the Original Borrower and the Security Agent.
 
“Borrowing Base Amount” means the amount determined on a Forecast Date in accordance with clause 19.6 ( Calculation of Borrowing Base Amount ) of this Agreement.
 
“Borrowing Base Assets” means KEG’s interest in, and all rights in respect of, Jubilee Field Phase 1, Phase 1a and Phase 1b and any other Ghana Block Asset when a plan of development applicable to that asset has been approved in accordance with the relevant Petroleum Agreement, including the Entitlement to all Unit Substances, and the assets in any Permitted Acquisition or Approved Development (which can be either Developed Assets or Developing Assets). In determining the reserves attributable to the Jubilee Field Phase 1, Phase 1a and Phase 1b and any Developed Assets, such determination shall take account of the proved and probable (2P) reserves, and in respect of Developing Assets, shall take account of proved (1P) reserves only.
 
“Break Costs” means the amount (if any) by which:
 
(A)               the interest which a Lender should have received for the period from the date of receipt of all or any part of its participation in a Loan or Unpaid Sum to the last day of the current Interest Period in respect of that Loan or Unpaid Sum, had the principal amount or Unpaid Sum received been paid on the last day of that Interest Period;
 
exceeds:
 
(B)                 the amount which that Lender would be able to obtain by placing an amount equal to the total sum received by it on deposit with a leading bank in the London interbank market for a period starting on the date of receipt or recovery and ending on the last day of the current Interest Period.
 
The calculation of interest for the purposes of paragraph (A) shall exclude an amount equal to the Margin for the period referred to in that paragraph where Kosmos prepays a Loan in any of the following circumstances:
 
(1)                   under clause 10.1 (General) of this Agreement or if clause 10.10 (Right of repayment and cancellation in relation to a single Lender ) of this Agreement applies; or
 
(2)                   a Market Disruption Event has occurred in relation to that Loan and no substitute basis for determining the rate of interest has been agreed.
 
“Brent Forward Curve” means a Brent Crude Oil five-year forward curve as quoted Ft, T by Intercontinental Exchange.
 
12

 
“Business Day” means a day (other than a Saturday or Sunday) when banks are open for business in London, Paris and New York.
 
“Cameroon Block Assets” means all activities, assets and developments in the Kombe-Nsepe Permit area and the Ndian River Block (including exploration), as such areas are described in the relevant Project Agreements set out below.
 
“Cameroon Blocks” means all of the blocks in the Kombe-Nsepe Permit area and the Ndian River Block, as such areas are described in the relevant Project Agreements set out below.
 
“Cash Waterfall” means the order of priority for application of amounts withdrawn from the Offshore Proceeds Accounts and the Onshore Working Capital Accounts as set out in clause 21.2 ( Withdrawals — No Default Outstanding ) of this Agreement.
 
“Change of Control” has the meaning given to that term in clause 10.6 (Change of Control) of this Agreement.
 
“Charge over Shares in KED” means the charge over shares in KED dated on or about the date of this Agreement between KEI and the Security Agent.
 
“Charge over Shares in KEG” means the charge over shares in KEG dated on or about the date of this Agreement between KED and the Security Agent.
 
“Charge over Shares in KEI” means the charge over shares in KEI dated on or about the date of this Agreement between KEO and the Security Agent.
 
“Charge over Shares in KEO” means the limited recourse charge over shares in KEO dated on or about the date of this Agreement between KEH as chargor, KEO and the Security Agent.
 
“Charge over Shares in the Original Borrower” means the limited recourse charge over shares in the Original Borrower dated on or about the date of this Agreement between KEI as chargor, the Original Borrower and the Security Agent.
 
“Charges over Shares” means the Charge over Shares in KED, the Charge over Shares in KEG, the Charge over Shares in KEI, the Charge over Shares in KEO and the Charge over Shares in the Original Borrower.
 
“Commitment” means:
 
(A)               in relation to an Original Lender, the amount set opposite its name under the heading “Commitment” in Schedule 2 ( The Original Lenders ) of this Agreement and the amount of any other Commitment transferred to it;
 
(B)                 in relation to an Additional Lender, its Additional Commitment; and
 
(C)                 in relation to any other Lender, the amount of any Commitment transferred to it,
 
to the extent not cancelled, reduced or transferred by it.
 
13

 
“Completion” means, in respect of a Developing Asset, the date on which the applicable Completion Test has been satisfied (as determined by the Technical Bank acting reasonably).
 
“Completion Test” means, in respect of a Developing Asset, the tests as agreed between the Original Borrower and the Technical Bank (acting reasonably) and approved by the Majority Lenders (acting reasonably) which must be completed to show that such asset should reasonably be considered to be a commercially producing asset (being substantially equivalent to the date of commencement of commercial production under applicable Project Agreements) in order for a Developing Asset to be included in the Borrowing Base Assets as a Developed Asset.
 
“Compliance Certificate” means a certificate, substantially in the form set out in Schedule 11 (Form of Compliance Certificate ) of this Agreement.
 
“Conditions Precedent” means the conditions precedent to initial utilisation of the Facility as set out in Part I of Schedule 3 ( Conditions Precedent ) of this Agreement.
 
“Confidentiality Undertaking” means a confidentiality undertaking substantially in the form of Schedule 13 ( Form of Confidentiality Undertaking ) of this Agreement or in any other form agreed between Kosmos and the Mandated Lead Arrangers.
 
“Consultants” means the Technical Consultant, Environmental Consultant, the Reserves Consultant and the Insurance Consultant.
 
“Contract Area” shall have the meaning given to that term in the WCTP PA or the DWT PA, as appropriate, or in any new petroleum agreements in Ghana applying to any part of such areas.
 
“Contractor” means the contractor under the WCTP PA and the DWT PA respectively from time to time.
 
“Crude Oil” shall have the meaning given to that term in the UUOA.
 
“Debt Service Reserve Account” or “DSRA” means an account designated “Kosmos -DSRA” established by the Original Borrower in respect of the Facility with the Account Bank in London pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement which is secured in favour of the Secured Parties.
 
“Deed of Acknowledgment and Release” means the Deed of Acknowledgment and Release between KEH, KEI, KED, KEFI, KEG and KEO.
 
“Deed of Subordination” means each deed of subordination in respect of Financial Indebtedness of either (i) the Obligors owed to each other, or (ii) Obligors owed to KEH, in each case substantially in the form of Schedule 14 ( Form of Deed of Subordination ).
 
“Default” means an Event of Default or event which, with the giving of notice, lapse of time, or fulfilment of any condition, would constitute an Event of Default.
 
14

 
“Definitions Agreement” means the definitions agreement dated 13 July 2009 (as amended on 29 October, 2009, 24 December, 2009 and 23 August, 2010) between, inter alios, Kosmos Energy Finance (as original borrower), certain other Obligors and the Finance Parties named therein setting out the definitions and the rules of construction and interpretation used in the Finance Documents relating to the financing for the Jubilee Field Phase 1.
 
“Derivative Agreement” means an ISDA Master Agreement or similar agreement pursuant to which Derivative Transactions are entered into by the Borrower with a counterparty.
 
“Derivative Transaction” means any transaction entered into under a Derivative Agreement, including (but not limited to) any transaction which is a forward rate agreement, option, future, swap, cap, floor and any combination of the foregoing.
 
“Developed Assets” means each of Jubilee Field Phase 1, Phase 1a and Phase 1b, and any Developing Assets which have achieved Completion and, as applicable, Approved Developments and Permitted Acquisitions which have been approved as Developed Assets in accordance with clause 19.8.
 
“Developing Assets” means the Ghana Block Assets and, as applicable, Approved Developments and Permitted Acquisitions which are to be counted as Developing Assets.
 
“Development Work Program and Budget” shall have the meaning given to that term in the UUOA.
 
“Discharge Date” means the first date on which all liabilities (whether actual or contingent) owed to the Finance Parties (other than the Hedging Counterparties) have finally been discharged and such Finance Parties are under no further obligation to provide financial accommodation under the Finance Documents.
 
“Discharged Rights and Obligations” has the meaning given to it in clause 30.5 (Procedure for transfer).
 
“Dispute” has the meaning given to it in clause 44.1 (Submission).
 
“Disruption Event” means either or both of:
 
(A)               a material disruption to those payment or communications systems or to those financial markets which are, in each case, required to operate in order for payments to be made in connection with the Facility (or otherwise in order for the transactions contemplated by the Finance Documents to be carried out) which disruption is not caused by, and is beyond the control of, any of the Parties; or
 
(B)                 the occurrence of any other event which results in a disruption (including, without limitation, disruption of a technical or systems-related nature) to the treasury or payments operations of a Party preventing or severely inhibiting that or any other Party:
 
15

 
(i)                       from performing its payment obligations under the Finance Documents; or
 
(ii)                    from communicating with other Parties in accordance with the terms of the Finance Documents,
 
and which (in either such case) is not caused by, and is beyond the control of, the Party whose operations are disrupted.
 
“Distributions Reserve Account” means each account designated “Kosmos - DRA” which is established and maintained by an Obligor pursuant to clause 20.6 ( Distributions Reserve Account ) of this Agreement, with any bank and in any jurisdiction (and to the extent such account is held by HSBC Bank plc, it is not held in its capacity as Account Bank).
 
“Dividend Release Test” means the conditions to be satisfied under clause 28.23 (Distributions) of this Agreement for the payment of a Shareholder Distribution.
 
“DWT Block” means the Deep Water Tano area offshore Ghana, being the area described in Annex 1 of the DWT PA, but excluding any portions of such area in respect of which the Contractor’s rights thereunder are from time to time relinquished or surrendered pursuant to the DWT PA.
 
“DWT JOA” means the joint operating agreement dated 15 August 2006 between Tullow Ghana Limited, Sabre Oil and Gas Limited and KEG in respect of the DWT Block (and all amendments and supplements thereto).
 
“DWT PA” means the petroleum agreement dated 10 March 2006 between the Government, represented by the Minister, the GNPC, Tullow Ghana Limited, Sabre Oil and Gas Limited and KEG in respect of the DWT Block (and all amendments and supplements thereto).
 
“Economic Assumptions” means the economic assumptions agreed or determined in accordance with clause 19.1 ( Forecast Procedures ) of this Agreement.
 
“Enforcement Action” shall have the meaning given to that term in the Intercreditor Agreement.
 
“Entitlement” means Kosmos’s entitlement to and lifting by tankers of its share of crude oil delivered from a Field.
 
“Environmental Consultant” means Shaw Consultants International, Inc., (or any other reputable environmental consultant agreed to by the Technical and Modelling Bank (acting reasonably)) appointed in accordance with a scope of work and budget for fees and expenses agreed with the Borrower, the Facility Agent and the Technical and Modelling Bank.
 
“EO” means the EO Group Limited, a Cayman Islands company with registered company number 219175 whose registered office is at PMB CT 123, Cantonments,
 
16

 
112A Adole Crescent Way, Airport, Accra, Ghana (formerly known as the KG Group Limited).
 
“EO Participation Agreement” means the participation agreement dated 1 June 2004 between KEG and EO (including, for the avoidance of doubt, any amendment, restatement or supplemental agreements or arrangements in relation thereto).
 
“Equator Principles” means those principles so titled and set out in a paper entitled “The ‘Equator Principles’: A financial industry benchmark for determining, assessing and managing social & environmental risk in project financing” dated July 2006 and developed and adopted by the International Finance Corporation and various other financial institutions, as amended from time to time.
 
“Event of Default” means any event or circumstance specified as such in clause 29 (Events of Default) of this Agreement.
 
“Existing Finance Documents” means the Finance Documents as defined in the Definitions Agreement.
 
“Existing Lender” has the meaning given to it in clause 30.1 (Assignments and transfers and changes in Facility Office by the Lenders ).
 
“Facility” means the facility made available under this Agreement as described in clause 3 (The Facility) of this Agreement.
 
“Facility Office” means the office or offices notified by a Lender to the Facility Agent in writing on or before the date it becomes a Lender (or, following that date, by not less than five Business Days’ written notice where notice is required under clause 32.14 ( Facility Agent relationship with the Lenders ) of this Agreement) as the office or offices through which it will perform its obligations under this Agreement.
 
“Fee Letter” means any letter or letters dated on or about the date of this Agreement between any Finance Party and Kosmos setting out any of the fees referred to in clause 14 ( Fees ) of this Agreement and any other fees payable by Kosmos to a Finance Party pursuant to a Finance Document or payable under this Facility.
 
“Field” means the Jubilee Field, the Ghana Block Assets, the Cameroon Block Assets, the Morocco Block Assets and any other onshore or offshore block or oil and gas field or reserves in which an Obligor has from time to time, directly or indirectly, acquired an interest pursuant to a Permitted Acquisition.
 
“Field Depletion Date” means the projected date on which it is determined (in accordance with the Forecast Assumptions) that Net Cash Flow is negative on each remaining Forecast Date following that projected date.
 
“Field Life Cover Ratio” or “FLCR” means the ratio of (i) the net present value of Net Cash Flow (calculated on the basis of the Forecast Assumptions) from the relevant Forecast Date until the Field Depletion Date plus the net present value of Relevant Capital Expenditure to (ii) the aggregate of all Loans outstanding under the Facility on that Forecast Date.
 
17

 
“Final Information Memorandum” means the information memorandum agreed between the Original Borrower and the Mandated Lead Arrangers and used by the Mandated Lead Arrangers during primary syndication of the Facility.
 
“Final Maturity Date” means the earlier of 7 years from the date of Financial Close and the Reserve Tail Date.
 
“Final Repayment Date” means the final repayment date for the Facility determined in accordance with clause 9 ( Repayment ) and/or the Amortisation Schedule, and references to the Final Repayment Date shall be construed as a reference to any Revised Final Repayment Date which may be determined in accordance with clause 9.2 ( Amendment to Amortisation Schedule ) of this Agreement.
 
“Final Reports” means the reports prepared by the Insurance Consultant, the Reserves Consultant, the Technical Consultant and the Environmental Consultant in relation to the Borrowing Base Assets.
 
“Finance Document” means this Agreement, the Intercreditor Agreement, each Hedging Agreement, each Intercompany Loan Agreement, each Security Document, each Deed of Acknowledgment and Release, each Deed of Subordination and each Fee Letter with an Agent and any other document designated as such by the Original Borrower and the Facility Agent.
 
“Finance Party” means each of the Mandated Lead Arrangers, the Lenders, the Hedging Counterparties, the LC Issuing Banks, the LC Lenders, the Account Bank, the Facility Agent, the Security Agent, the Intercreditor Agent, the Modelling Bank and the Technical Bank, and “ Finance Parties ” shall be construed accordingly.
 
“Financial Close” means the date on which the Facility Agent notifies the Original Borrower and the Lenders that it has received all of the Conditions Precedent in form and substance satisfactory to it (acting reasonably) and/or waived receipt of those Conditions Precedent in accordance with clause 2.1 ( Conditions Precedent to first Utilisation ).
 
“Financial Covenants” means the financial covenants listed under clause 27 (Financial Covenants) of this Agreement.
 
“Financial Indebtedness” means any indebtedness for or in respect of:
 
(A)               moneys borrowed;
 
(B)                 any amount raised by acceptance under any acceptance credit facility or dematerialised equivalent;
 
(C)                 any amount raised pursuant to any note purchase facility or the issue of bonds, notes, debentures, loan stock or any similar instrument;
 
(D)                the amount of any liability in respect of any lease or hire purchase contract which would be treated in the accounts of the relevant entity as a finance or capital lease;
 
18

 
(E)                  receivables sold or discounted (other than any receivables to the extent they are sold on a non-recourse basis);
 
(F)                  any derivative transaction entered into in connection with protection against or benefit from fluctuation in any rate or price (and, when calculating the value of any derivative transaction, only the market to market value shall be taken into account);
 
(G)                 any amount raised under any other transaction (including any forward sale or purchase agreement) of a type not referred to in any other paragraph of this definition but which is classified as a borrowing in the accounts of the relevant entity;
 
(H)                any counter-indemnity obligation in respect of a guarantee, indemnity, bond, standby or documentary letter of credit or any other instrument issued by a bank or financial institution in respect of an underlying liability of an entity which is not a member of the Group and which underlying liability would fall within one of the other paragraphs of this definition if it were a liability of a member of the Group; and
 
(I)                     the amount of any liability in respect of any guarantee or indemnity for any of the items referred to in paragraphs (A) to (H) above (but only to the extent that the Financial Indebtedness supported thereby is or is at any time in the future capable of being outstanding).
 
“Financing Costs” means all amounts of interest, fees, commitment fees, or other costs and scheduled principal instalments payable by the Obligors under the Finance Documents.
 
“First Currency” has the meaning given to it in clause 17.1 (Currency indemnity).
 
“Forecast” means each Forecast prepared in accordance with clause 19 (Forecasts and Calculations) of this Agreement.
 
“Forecast Assumptions” means the assumptions used in the production of a Forecast.
 
“Forecast Date” means:
 
(A)               the date of Financial Close;
 
(B)                 the date on which an asset becomes a Borrowing Base Asset;
 
(C)                 15 June and 15 December in each year commencing on and from a date to be agreed between the Technical and Modelling Bank and Kosmos which will fall between 15 June 2011 and 15 August 2011;
 
(D)                any other date which falls no more than 90 days after the date on which the Reserves Consultant has, at the request of the Original Borrower, produced a new or updated reserves report;
 
19

 
(E)                  the date of disposal of a Borrowing Base Asset (other than a Permitted Disposal which falls under any of paragraphs (B) and (E) to (K) of the definition of “Permitted Disposal” set out below); and
 
(F)                  on request by the Majority Lenders on any date after the Signing Date and before the date falling 12 months after the Signing Date upon which the Majority Lenders (acting reasonably) determine that an event (or series of events) or circumstance or any effect or consequence thereof has occurred (other than any fluctuation or change in crude oil prices) that could reasonably be expected to have a Material Adverse Effect, provided that, before making such determination, the Majority Lenders must first consult with Kosmos in good faith for not less than 5 Business Days.
 
“Forecast Period” means, in the case of the first Forecast Period, the period commencing on the date of Financial Close and ending at close of business on the first Forecast Date and, in the case of any subsequent Forecast Period, the period commencing on the expiry of the immediately preceding Forecast Period and ending at close of business on the next Forecast Date.
 
“Forecasting Procedures” means the procedures set out under clause 19 (Forecasts and Calculations) of this Agreement for preparing a Forecast.
 
“FPSO” means a floating production, storage and offloading vessel.
 
“FPSO Agreement” means an agreement entered into by Tullow Ghana Limited (and its successors under the UUOA) in relation to the Jubilee Field Phase 1 for the construction, installation, lease, operations and maintenance of an FPSO dated 7 May 2010 (as amended from time to time).
 
“FPSO Construction Financing” means any financing arrangements in relation to the construction of the FPSO to which an Obligor or member of the Group is a party.
 
“Ghanaian Cedi” means the lawful currency of Ghana.
 
“Ghana” means the Republic of Ghana, West Africa.
 
“Ghana Block Assets” means, other than Jubilee Field Phase 1, Phase 1a and Phase 1b, all other activities, assets and developments in the Contract Areas (including exploration).
 
“Ghana Blocks” means the WCTP Block and the DWT Block.
 
“Ghana Working Capital Cedi Account” means a Ghanaian Cedi account designated “Kosmos — Onshore Working Capital Account” established by Kosmos with the Onshore Account Bank in Ghana pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement which is secured in favour of the Secured Parties.
 
“Ghana Working Capital USD Account” means a USD account designated “Kosmos — Onshore Working Capital Account” established by Kosmos with the Onshore Account
 
20

 
 
Bank in Ghana pursuant to clause 20 (Bank Accounts and Cash Management) of this Agreement which is secured in favour of the Secured Parties.
 
“GNPC” means the Ghana National Petroleum Corporation, a public corporation established by Provisional National Defence Council Law 64 of 1983.
 
“Government” means the government of Ghana or, as appropriate, the government of any other country in which a Borrowing Base Asset is situated.
 
“Gross Revenues” means, for the relevant period of determination and without double counting, the USD equivalent of each of the following amounts to the extent received (or projected to be received or which are credits to an interest or account of an Obligor) by or on behalf of an Obligor (including the USD equivalent of any payment in kind) during that period from or in respect of the Borrowing Base Assets (other than any amount received or held on behalf of an Interested Third Party which is not related to a Borrowing Base Asset whether in cash or in kind):
 
(A)               amounts received or to be received from the sale of crude oil, condensate, natural gas liquids and all output and product from the Borrowing Base Assets or otherwise received or to be received pursuant to any Project Agreement;
 
(B)                 amounts representing interest on the Project Accounts and interest or distributions or income of any kind in respect of Authorised Investments;
 
(C)                 all refunds of tax of any kind;
 
(D)                all Insurance Proceeds;
 
(E)                  all damages or other payments for termination or non-performance or failure to perform or variation under any contract;
 
(F)                  all net amounts received under any Derivative Agreement;
 
(G)                 all amounts received in respect of any Permitted Disposal; and
 
(H)                all other amounts which fall to be credited to the profit and loss account of an Obligor for the financial year in which the relevant period falls.
 
“Group” means KEO and the Original Borrower and each of their subsidiaries.
 
“Guarantor” means the Original Guarantor or an Additional Guarantor.
 
“Hedging Agreement” means an ISDA Master Agreement or similar agreement pursuant to which Hedging Transactions are entered into by the Borrower with a Hedging Counterparty and where the liability of the Obligors thereunder are secured by the Security Documents.
 
“Hedging Counterparty” means:
 
21

 
(a)                   any person which is named on the signing pages of the Intercreditor Agreement as a Hedging Counterparty and;
 
(b)                  any person which becomes a Party as a Hedging Counterparty pursuant to Clause 13.5 (Creditor/Agent Accession Undertaking ) of the Intercreditor Agreement.
 
“Hedging Transaction” means any transaction entered into under a Hedging Agreement, including (but not limited to) any transaction which is a forward rate agreement, option, future, swap, cap, floor and any combination of the foregoing.
 
“IFC Commitment” has the meaning given to it in paragraph (A) of clause 3.4 (IFC as Additional Lender) of this Agreement.
 
“IFC Facility” has the meaning given to it in paragraph (A) of clause 3.4 (IFC as Additional Lender) of this Agreement.
 
“IFC Rebalancing” has the meaning given to it in paragraph (C) of clause 3.4 (IFC as Additional Lender) of this Agreement.
 
“Illegality Lender” has the meaning given to that term in clause 10.2 (Illegality) of this Agreement.
 
“Increased Costs” has the meaning given to that term in clause 16.1 (Increased costs) of this Agreement.
 
“Insolvency Event” means, in relation to any Obligor, any circumstances described in clause 29.6 ( Insolvency ) of this Agreement.
 
“Insolvency Proceedings” means, in relation to any Obligor, any circumstances described in clause 29.7 ( Insolvency proceedings ) of this Agreement.
 
“Insurance” or “Insurances” means any or all of the contracts of insurance which Kosmos is required from time to time to purchase or procure and maintain pursuant to the Schedule of Insurances.
 
“Insurance Consultant” means the appointed insurance consultant, currently Moore-McNeil, LLC, appointed in accordance with a scope of work and budget for fees and expenses agreed with the Borrower, the Facility Agent and the Technical and Modelling Bank.
 
“Insurance Consultant Appointment Letter” means the letter between Kosmos, the Facility Agent and the Insurance Consultant setting out the terms of appointment of the Insurance Consultant, in the Agreed Form.
 
“Insurance Proceeds” means all moneys which may at any time be or become payable to or received by an Obligor (other than proceeds in respect of third party liability insurances) under or pursuant to the Agreed Insurances and any reinsurance contract in which the relevant Obligor has an interest.
 
22

 
“Insurance Proceeds Accounts” means any of the KED Insurance Proceeds Account, the KEG Insurance Proceeds Account, the KEI Insurance Proceeds Account, the KEO Insurance Proceeds Account, the Borrower Insurance Proceeds Account and any account deemed to be an “Insurance Proceeds Account” in accordance with clause 20 ( Bank Accounts and Cash Management ) and which is secured in favour of the Secured Parties, each an “ Insurance Proceeds Account ”.
 
“Intercompany Borrower” means a borrower under an Intercompany Loan Agreement.
 
“Intercompany Loan Agreement” means each loan agreement in Agreed Form pursuant to which a Borrower makes advances to an Obligor from the proceeds of a Utilisation under the Facility.
 
“Intercreditor Agreement” means the intercreditor agreement, entered into on or about the date of this Agreement, between, amongst others, the Facility Agent, the Lenders, the Hedging Counterparties, the Original Borrower and the Security Agent.
 
“Interest Period” means, in relation to a Loan, each period determined in accordance with clause 12 ( Interest Periods ) of this Agreement and, in relation to an Unpaid Sum, each period determined in accordance with clause 11.4 ( Default interest ) of this Agreement.
 
“Interested Third Party” has the meaning given to the term in clause 20.2(A)(iii) (Other bank accounts) of this Agreement.
 
“IPO” means in relation to a company, a transaction in which shares in that company are sold or issued to investors and in connection with such sale or issue are admitted to trading on a regulated market or other stock exchange.
 
“IPO Reorganisation” means any Reorganisation implemented by KEH, or any of its Subsidiaries from time to time (or any group of them), which is undertaken for the purpose of facilitating an IPO.
 
“ISDA Master Agreement” means the 1992 ISDA Master Agreement or the 2002 ISDA Master Agreement, as the case may be.
 
“Joint Operating Agreements” means:
 
(A)               the DWT JOA;
 
(B)                 the WCTP JOA; and
 
(C)                 the joint operating agreement between Societe Nationale des Hydrocarbures, Perenco Oil and Gas (Cameroon) Ltd and Kosmos Energy Cameroon HC dated 3 July 2008 pursuant to which the parties, to ensure good management of the petroleum operations, agreed to further define their respective rights in relation to the Kombe-Nsepe Permit, Cameroon (and all amendments and supplementals thereto).
 
23

 
“Jubilee Field” means the hydrocarbon accumulation so named that is located approximately 63km offshore Ghana and which extends across the Ghana Blocks.
 
“Jubilee Field Phase 1” means the Phase 1 development of the Jubilee Field, as described in the Phase 1 Plan of Development for the Jubilee Field, including the Project Infrastructure and all appraisal, exploration, construction, operations, maintenance and exploitation works and activities, and the treatment, processing, storage, delivery, lifting and sale of Unit Substances therefrom.
 
“KED Insurance Proceeds Account” means an account designated “KED — Insurance Proceeds Account” established by KED with the Offshore Account Bank in London pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement which is secured in favour of the Secured Parties.
 
“KED Offshore Proceeds Account” means an account designated “Kosmos Energy Development — Offshore” established by KED with the Account Bank in London pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement which is secured in favour of the Secured Parties.
 
“KED Offshore Security Assignment” means the English law security assignment and debenture, dated on or about the date of this Agreement, between KED and the Security Agent.
 
“KEG Insurance Proceeds Account” means an account designated “KEG — Insurance Proceeds Account” established by KEG with the Offshore Account Bank in London pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement which is secured in favour of the Secured Parties.
 
“KEG Offshore Proceeds Account” means an account or accounts where the designated name includes the words “Kosmos Energy Ghana HC — Offshore” established by KEG with the Account Bank in London pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement which is secured in favour of the Secured Parties.
 
“KEG Offshore Project Accounts Agreement” means the offshore project accounts agreement, dated on or about the date of this Agreement, between KEG, the Offshore Account Bank, the Facility Agent and the Security Agent.
 
“KEG Offshore Security Assignment” means the English law security assignment and debenture, dated on or about the date of this Agreement, between KEG and the Security Agent.
 
“KEG Onshore Project Accounts Agreement” means the onshore project accounts agreement, dated on or about the date of this Agreement, between KEG, the Onshore Account Bank, the Facility Agent and the Security Agent.
 
“KEG Onshore Security Assignment” means the Ghanaian law debenture, dated on or about the date of this Agreement, between KEG and the Security Agent.
 
24

 
“KEH” means Kosmos Energy Holdings, a company incorporated under the laws of the Cayman Islands with registered number 133483 and having its registered office at PO Box 32332, 4th Floor, Century Yard, Cricket Square, Elgin Avenue, George Town, Grand Cayman KY1-1209, Cayman Islands.
 
“KEI and KEO Offshore Security Assignment” means the English law security assignment dated on or about the date of this Agreement between KEI, KEO and the Security Agent.
 
“KEI Insurance Proceeds Account” means an account designated “KEI — Insurance Proceeds Account” established by KEI with the Offshore Account Bank in London pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement which is secured in favour of the Secured Parties.
 
“KEI Offshore Proceeds Account” means an account designated “Kosmos Energy International — Offshore” established by KEI with the Account Bank in London pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement which is secured in favour of the Secured Parties.
 
“KEI Offshore Security Assignment” means the English law security assignment and debenture, dated on or about the date of this Agreement, between KEI and the Security Agent.
 
“KEL” means Kosmos Energy Ltd., a company incorporated under the laws of Bermuda with registered number 45011 and having its registered office at Clarendon House, 2 Church Street, Hamilton HM 11, Bermuda.
 
“KEO Insurance Proceeds Account” means an account designated “KEO — Insurance Proceeds Account” established by KEO with the Offshore Account Bank in London pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement which is secured in favour of the Secured Parties.
 
“KEO Offshore Proceeds Account” means an account designated “Kosmos Energy Operating — Offshore” established by KEO with the Account Bank in London pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement which is secured in favour of the Secured Parties.
 
“KEO Offshore Security Assignment” means the English law security assignment and debenture, dated on or about the date of this Agreement, between KEO and the Security Agent.
 
“Kosmos” means KEG or the Borrower, as the context so requires.
 
“LC Cash Collateral Account” means an account designated “Kosmos — LC Cash Collateral Account” which is established and maintained by the Original Borrower pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement, with the relevant LC Issuing Bank or Lender (as applicable, in accordance with the terms of clause 7.1(B)(viii)(a)), which is secured in favour of the relevant LC Issuing Bank or Lender, as applicable.
 
25

 
“LC Issuing Bank” means the Mandated Lead Arrangers and Underwriters and such other Lenders (each an LC Issuing Bank) appointed to such role from time to time and who issue, pursuant to clause 7.6 ( Issue of Letters of Credit ) of this Agreement, a Letter of Credit.
 
“LC Lender” means each Lender, unless otherwise agreed.
 
“Lender” means:
 
(A)               any Original Lender;
 
(B)                 any bank or financial institution which has become a Party as a lender in accordance with clause 30 (Changes to the Lenders ) of this Agreement; and
 
(C)                 any entity which has become a Party as a lender in accordance with clause 3.3 (Additional Commitment) of this Agreement,
 
which in each case has not ceased to be a Party in accordance with the terms of this Agreement.
 
“Lender Accession Notice” means a notice substantially in the form set out under Schedule 8 (Form of Lender Accession Notice ) to be delivered by an Additional Lender pursuant to and in accordance with clause 3.3 ( Additional Commitment ) of this Agreement.
 
“Letter of Credit” means a letter of credit:
 
(A)               substantially in the form set out in Schedule 12 (Form of Letter of Credit) of this Agreement subject to such amendments as any beneficiary may reasonably require;
 
(B)                 in such form as already issued by Kosmos on the date of this Agreement (together with such amendments as may reasonably be required by the beneficiary thereunder); or
 
(C)                 in any other form requested by Kosmos and agreed by the Facility Agent (pursuant to instructions from the Majority Lenders (acting reasonably)) and each LC Lender.
 
“LIBOR” means the British Bankers’ Association Interest Settlement Rate for the relevant Interest Period, as displayed on the appropriate page of the Reuters screen or, if that page is replaced or service ceases to be available, such reasonable alternative page or service which the Facility Agent reasonably specifies, or if no such rate or screen is available, the arithmetic mean of the rates (rounded to four decimal places) provided by three Reference Banks.
 
“Loan” means each loan or Letter of Credit made or to be made under this Agreement or the principal amount outstanding for the time being of that loan or Letter of Credit.
 
26

 
“Loan Life Cover Ratio” or “LLCR” means the ratio of (i) the net present value of Net Cash Flow (calculated on the basis of the Forecast Assumptions) from the relevant Forecast Date until the Final Maturity Date plus the net present value of Relevant Capital Expenditure to (ii) the aggregate of all Loans outstanding under the Facility on that Forecast Date.
 
“Majority Lenders” means, as applicable, those Lenders whose participation in advances under the Facility are equal to 66 2 / 3  per cent. of the aggregate advances then outstanding, or if there are no advances outstanding, whose Commitments then aggregate at least 66 2 / 3  per cent. of the Total Commitments under the Facility.
 
“Mandatory Cost” means the percentage rate per annum calculated by the Facility Agent in accordance with Schedule 6 ( Mandatory Cost Formulae ) of this Agreement.
 
“Margin” means the percentage rate per annum determined in accordance with clause 11.2 (Margin) of this Agreement.
 
“Market Disruption Event” has the meaning given to that term in clause 13.2 (Market disruption) of this Agreement.
 
“Material Adverse Effect” means, in relation to any event (or series of events) or circumstance which occurs or arises (other than fluctuations in Crude Oil prices), that event (or events) or circumstance (or any effect or consequence thereof), in the opinion of the Majority Lenders, would reasonably be expected materially and adversely to affect the financial condition, operations, or business of any Obligor or the Borrowing Base Assets, or the ability of any Obligor to perform its obligations under the Finance Documents in full and on the basis contemplated therein in a way which is materially prejudicial to the interests of the Lenders or results in the Obligors being unable to pay any amounts when due and payable under the Finance Documents.
 
“Material Contracts” means the following contracts and agreements in Agreed Form at the Signing Date:
 
(A)               The Drilling Contract for the provision of a semi-submersible drilling unit ‘Eirik Raude’ and associated drilling services between Tullow Oil plc and Ocean Rig 2 AS (as contractor) dated 15 February 2008.
 
(B)                 The Atwood Hunter Offshore Drilling Contract made between Kosmos Energy Ghana HC, Noble Energy EG Ltd and Alpha Offshore Drilling Services Company dated 23 June 2008
 
(C)                 The Atwood Hunter Rig Sharing Agreement between Kosmos Energy Ghana HC, Noble Energy EG Ltd and Alpha Offshore Drilling Services Company dated June 24, 2008.
 
(D)                The agreement for the construction, installation, lease, operations and maintenance of a floating, production, storage and offloading facility to be signed between Tullow Ghana Limited and Jubilee Ghana MV21 B.V. as the contractor entered into as of 7 May 2010.
 
27

 
(E)                  Daywork Drilling Contract — Offshore (Deepwater Millennium), is made between Anadarko Petroleum Corporation, and Transocean Offshore Deepwater Holdings Limited, effective date April 17, 2008.
 
(F)                  Master Crude Sales Agreement, Trafigura Beheer B.V., Amsterdam, Branch Office Lucerne, and Kosmos Energy Ghana HC; effective date September 24, 2010 and as per first and second amendments dated January 17, 2011 and February 2, 2011.
 
(G)                 Jubilee Field Unit Crude Oil Lifting Agreement between, Ghana National Petroleum Corporation, Tullow Ghana Limited, Kosmos Energy Ghana HC, Anadarko WCTP Company, Sabre Oil & Gas Holdings Limited and EO Group Limited, dated December 8, 2010.
 
“Minister” means the Government’s Minister for Energy.
 
“Model” means the computer model in the Agreed Form at the Signing Date, as such model may be updated from time to time pursuant to clause 19 ( Forecasts and Calculations ) of this Agreement.
 
“Model Auditor” means Operis Group plc appointed in accordance with a scope of work and budget for fees and expenses agreed with the Borrower, the Facility Agent and the Technical and Modelling Bank.
 
“Model Auditor Appointment Letter” means the letter between Kosmos, the Facility Agent, the Technical and Modelling Bank and the Model Auditor setting out the terms of appointment of the Model Auditor in the Agreed Form.
 
“Moody’s” means Moody’s Investors Service, Inc., a Delaware corporation and any successor thereto and if such corporation shall for any reason no longer perform the functions of a securities rating agency, Moody’s shall be deemed to refer to any other internationally recognised rating agency agreed by the Facility Agent and Kosmos (both acting reasonably).
 
“Morocco Block Assets” means all activities, assets and developments in the Boujdour Offshore area of interest in Morocco (including exploration), as such area of interest is further described in the relevant Project Agreements defined below.
 
“Morocco Blocks” means all of the blocks in the Boujdour Offshore area of interest as such area of interest is further described in the relevant Project Agreements defined below.
 
“Net Cash Flow” means, for any relevant period (but without any double counting):
 
(A)               Net Revenues; minus
 
(B)                 Project Costs,
 
28

 
projected to be paid or received during that period converted if necessary into USD at the rate of exchange used in the Forecast Assumptions on the date of projected receipt or payment.
 
“Net Revenues” means Gross Revenues minus Royalty Payments and Additional Oil Entitlement payments.
 
“New Commitment Rebalancing” has the meaning given to it in clause 3.3 (Additional Commitment) of this Agreement.
 
“New Lender” has the meaning given to it in clause 30.1 (Assignments and transfers and changes in Facility Office by the Lenders ).
 
“New Project Agreement” means any project agreement relating to any Approved Development or Permitted Acquisition over which the Lenders have, or are to receive, a Security Interest.
 
“Non-Funding Lender” means:
 
(A)               any Lender who fails to participate in any Utilisation in the amount and at the time required;
 
(B)                 any Lender who has indicated publicly or to the Facility Agent or an Obligor that it does not intend to participate in all or part of any Utilisation;
 
(C)                 any Lender which has repudiated its obligations under the Facility; or
 
(D)                any Lender in respect of which or in respect of whose holding company any of the events specified in clause 29.6 ( Insolvency ) or clause 29.7 ( Insolvency proceedings ) of this Agreement (disregarding paragraph (B) of clause 29.7) ( Insolvency  proceedings) applies or has occurred.
 
“Obligors” means the Borrowers and the Guarantors.
 
“Offshore Proceeds Accounts” means any of the KED Offshore Proceeds Account, the Borrower Offshore Proceeds Account, the KEG Offshore Proceeds Account, the KEI Offshore Proceeds Account, the KEO Offshore Proceeds Account, the Borrower Offshore Proceeds Account and any account deemed to be an “Offshore Proceeds Account” in accordance with clause 20.1 ( Project Accounts ), and which is secured in favour of the Secured Parties, each an “ Offshore Proceeds Account ”.
 
“Onshore Working Capital Accounts” means the Ghana Working Capital Cedi Account and the Ghana Working Capital USD Account.
 
“Operator” means, in relation to each Borrowing Base Asset or each Developing Asset, the relevant operator of that Borrowing Base Asset or Developing Asset.
 
“Operator Report” means the semi-annual report prepared by the Operator in relation to each Borrowing Base Asset and each Developing Asset.
 
29

 
“ORGL LC” means the Letter of Credit dated 24 December 2010 issued by BNP Paribas to Ocean Rig Ghana Limited as beneficiary originally at the request of KEF in respect of the obligations of Tullow Ghana Limited to the beneficiary thereof, a copy of which is appended in Schedule 16 (Copy of ORGL LC), under which the amount of USD 23,000,000 is outstanding as at the date of this Agreement.
 
“Original Guarantor” means KEO, KEI and KED, KEG and any subsidiary of a Borrower which owns Borrowing Base Assets.
 
“Participating Interest” has the meaning given to it in the relevant Petroleum Agreement and details of each such participating interest as at the date of this Agreement are as set out in clause 26.14 ( Assets ) of this Agreement.
 
“Participating Member State” means any member state of the European Union that adopts or has adopted the euro as its lawful currency in accordance with legislation of the European Union relating to Economic and Monetary Union.
 
“Party” means a party to a Finance Document.
 
“Permitted Acquisition” means any acquisitions or investments:
 
(A)               which are made in the ordinary course of the day to day business of the acquiring company;
 
(B)                 which are funded by equity or debt subordinated on terms acceptable to the Majority Lenders (acting reasonably);
 
(C)                 which are in respect of the implementation and development of the Borrowing Base Assets;
 
(D)                which are included within a Forecast;
 
(E)                  in respect of which the aggregate consideration paid (which shall exclude the amount of any debt assumed) does not in any calendar year exceed USD 50 million, or such higher figure as the Majority Lenders may agree (acting reasonably);
 
(F)                  by an Obligor which are to be Borrowing Base Assets as approved by the Majority Lenders (acting reasonably); or
 
(G)                 which are approved by the Majority Lenders (acting reasonably),
 
provided in each case that such acquisition or investment may not take place in Iran, Myanmar, North Korea, Sudan, Syria, Cuba, any country which is subject to a Sanctions Regime or any country designated by the Majority Lenders (acting reasonably).
 
“Permitted Disposals” means any:
 
(A)                                          disposal permitted in accordance with clause 28.8 (Disposals) of this Agreement;
 
30

 
 
(B)                 disposals made in the ordinary course of the day to day business of operating the Borrowing Base Assets;
 
(C)                 disposals expressly permitted under any Project Agreement;
 
(D)                disposals of cash for purposes not prohibited by the Finance Documents;
 
(E)                  disposals expressly required in order to comply with its obligations under the Project Agreements;
 
(F)                  disposals of assets in exchange for other assets of comparable, or superior as to, type, value and quality;
 
(G)                 disposals of obsolete assets;
 
(H)                disposals from one Obligor to another or from a subsidiary to an Obligor;
 
(I)                     disposals on arms length terms for market value of its Entitlements from a Field or petroleum products to which an Obligor is entitled by virtue of its ownership or investment in a Petroleum Asset;
 
(J)                    disposals on arms length terms with a net market value not exceeding USD 50 million in any calendar year or, from the date of this Agreement, USD 100 million in aggregate; and
 
(K)                disposals not falling within (A) to (J) above which are consented to by the Majority Lenders.
 
“Permitted Financial Indebtedness” means:
 
(A)               any Financial Indebtedness arising under or contemplated by the Finance Documents;
 
(B)                 any Financial Indebtedness the proceeds of which are applied, promptly on receipt by Kosmos, in making or procuring the making of a prepayment of all amounts outstanding under the Finance Documents in full;
 
(C)                 any Financial Indebtedness subordinated to the Lenders on terms approved by the Majority Lenders (each acting reasonably) provided that there shall be no subordination in respect of amounts held in any Distributions Reserve Account;
 
(D)                any Financial Indebtedness owed to an Obligor;
 
(E)                  any Financial Indebtedness arising under finance or capital leases of vehicles, plant, equipment or computers, provided that the aggregate capital value of all such items so leased under outstanding leases by members of the Group does not exceed USD 100 million (or its equivalent in other currencies) at any time;
 
(F)                  any Financial Indebtedness arising under any Derivative Agreement that Kosmos may enter further to the provisions of clause 28.17(A) ( Hedging) ; or
 
31

 
(G)                 any Financial Indebtedness otherwise approved by the Majority Lenders (such approval not to be unreasonably withheld or delayed).
 
“Permitted Party” has the meaning given to it in clause 30.7 (Disclosure of information).
 
“Permitted Security” means:
 
(A)               any netting or set-off arrangement entered into in the ordinary course of financing arrangements for the purpose of netting or setting off debit and credit balances;
 
(B)                 any lien securing obligations no more than 90 days overdue arising by operation of law;
 
(C)                 any Security Interest arising under or contemplated by the Finance Documents or pursuant to the express terms of any Project Agreement;
 
(D)                any title retention provisions in a supplier’s standard conditions of supply of goods;
 
(E)                  any Security Interest created over or in respect of any Distributions Reserve Accounts; and
 
(F)                  any Security Interest not falling within (A) to (E) above which is consented to by the Majority Lenders.
 
“Permitted Transferee” shall have the meaning given to that term in clause 10.6 (Change of Control) of this Agreement.
 
“Petroleum Agreements” means:
 
(i)                      the DWT PA and the WCTP PA (and all amendments and supplements thereto);
 
(ii)                   the petroleum agreement between Office National des Hydrocarbures et des Mines and Kosmos Energy Offshore Morocco HC dated 3 May 2006 in relation to the Boujdour Offshore area of interest in Morocco (and all amendments and supplementals thereto);
 
(iii)                the memorandum of understanding between Office National des Hydrocarbures et des Mines, acting on behalf of the Kingdom of Morocco and Kosmos Energy Offshore Morocco HC, dated 27 September 2010;
 
(iv)               the production sharing agreement between The Republic of Cameroon and Kosmos Energy Cameroon HC in respect of the Ndian River Block in Cameroon (and all amendments and supplementals thereto);
 
(v)                  the convention of establishment (the “CoE”) between The Republic of Cameroon, CMS Nomeco Cameroon Ltd and Globex Cameroon, LLC dated 11 December 1997 pursuant to which The Republic of Cameroon granted certain mining titles to CMS Nomeco Cameroon Ltd and Globex Cameroon, LLC in relation to the
 
32

 
Douala/Kribi-Campo Basin, the Rio Del Rey Basin, certain Deep Water Zones and certain Other Interior Basins (both aforementioned terms as defined in the CoE), which rights, together with the rights conferred under the Contract of Association referred to below, are referred to as the governing rights of the Kombe-Nsepe Permit, Cameroon (and all amendments and supplementals thereto);
 
(vi)               the exploration agreement between Perenco Oil and Gas (Cameroon) Ltd and Kosmos Energy Cameroon HC dated 5 October 2005 pursuant to which Perenco Oil and Gas (Cameroon) Ltd transferred by way of farm-out to Kosmos Energy Cameroon HC a portion of its interest in the Kombe-Nsepe Permit, Cameroon (and all amendments and supplementals thereto),
 
as such documents may be updated, amended or replaced from time to time.
 
“Petroleum Asset” means any assets related to the exploration for or exploitation, production, treatment, processing, transportation, storage, marketing and sale of petroleum products including, but without limitation, any contractual rights under any agreement entered into in relation to or incidental or ancillary thereto, any equity or participating interest in any entity which has such an interest or which conducts such activities and any right which would allow a person to obtain title to or an interest in any petroleum products.
 
“Phase 1 Plan of Development for the Jubilee Field” means the relevant plan for the development of the Jubilee Field (Phase 1) approved by the Government.
 
“Process Agent” has the meaning given to it in clause 45 (Service of Process).
 
“Project Accounts” means any or all of each Debt Service Reserve Account, the LC Cash Collateral Account, the Offshore Proceeds Accounts, the Onshore Working Capital Accounts and the Insurance Proceeds Accounts, in each case, as established pursuant to clause 20 ( Bank Accounts and Cash Management ) of this Agreement and any account established further to clause 10.3 ( Aggregate outstandings exceed the Borrowing Base Amount ) of this Agreement, with such accounts being secured in favour of the Secured Parties.
 
“Project Accounts Agreements” means the KEG Offshore Project Accounts Agreement, the KEG Onshore Project Accounts Agreement and the Borrower Offshore Project Accounts Agreement.
 
“Project Agreements” means (when entered into by the relevant Obligor):
 
(A)               each Petroleum Agreement;
 
(B)                 the Joint Operating Agreements;
 
(C)                 the UUOA;
 
(D)                the contract of association (the “Contract of Association”) between The Republic of Cameroon, CMS Nomeco Cameroon Ltd, Globex Cameroon LLC
 
33

 
and Societe Nationale des Hydrocarbures dated 11 December 1997 pursuant to which the parties have agreed the terms upon which they will carry out petroleum operations in relation to the M’VIA field, which rights, together with the rights conferred under the CoE referred to above, are referred to as the governing rights of the Kombe-Nsepe Permit, Cameroon (and all amendments and supplementals thereto);
 
(E)                  the association contract between Office National des Hydrocarbures et des Mines and Kosmos Energy Offshore Morocco dated 3 May 2006 in relation to the Boujdour Offshore area of interest in Morocco (and all amendments and supplementals thereto); and
 
(F)                  each New Project Agreement and any other agreement which the Facility Agent and the Original Borrower agree shall be a Project Agreement,
 
as such documents may be updated, amended or replaced from time to time.
 
“Project Costs” means all costs and expenses (including without limitation exploration costs and any costs incurred under any Derivative Agreement pursuant to any Derivative Transaction) in relation to:
 
(A)               Borrowing Base Assets;
 
(B)                 the Ghana Block Assets in the following 12 months;
 
(C)                 the Cameroon Blocks in the following 12 months;
 
(D)                the Morocco Blocks in the following 12 months; and
 
(E)                  any other project, venture, Field or Petroleum Asset which can be funded by headroom under the Borrowing Base Amount, such headroom in any Forecast Period being the amount by which the Borrowing Base Amount exceeds the projected aggregate costs and expenses shown in the then current Forecast for that period for (A) to (D) above.
 
“Project Infrastructure” means:
 
(A)               the FPSO for the Jubilee Field Phase 1;
 
(B)                 a taut-leg mooring system for that vessel;
 
(C)                 seven production wells;
 
(D)                five production drill centers;
 
(E)                  five production manifolds;
 
(F)                  four water injection wells;
 
(G)                 two water-injection drill centers;
 
34

 
(H)                two water injection manifolds;
 
(I)                     three gas-injection wells;
 
(J)                    one gas-injection drill center;
 
(K)                one gas-injection manifold;
 
(L)                  two riser bases;
 
(M)             six subsea distribution units; and
 
(N)                associated flowlines, risers, umbilicals and jumpers.
 
“Qualifying Bank” means an internationally recognised bank which:
 
(A)               is not on a sanctions list or subject to a sanctions regime issued, imposed or administered by the United States or any member country of the European Union, or the European Union itself or the United Nations (or any agency of any of them) (a “ Sanctions Regime ”); or
 
(B)                 does not have its principal place of business in a country which is subject to a Sanctions Regime; or
 
(C)                 is not a bank whose principal place of business is in a country notified by Kosmos to the Facility Agent prior to signing of this Agreement.
 
“Quotation Day” means, in relation to any period for which an interest rate is to be determined two Business Days before the first day of that period.
 
“Reference Banks” means the principal London offices of Société Générale, London Branch and BNP PARIBAS, or such other Reference Banks appointed under clause 32.16 ( Reference Banks ) of this Agreement.
 
“Relevant Capital Expenditure” means capital expenditure incurred or to be incurred in relation to the Borrowing Base Assets and Ghana Block Assets in the next twelve months or, in respect of exploration and appraisal costs for Ghana Block Assets, in the next six months as determined pursuant to a Forecast and which is or will be funded by the Facility or by contributions to the capital of an Obligor (including loans subordinated on terms acceptable to the Facility Agent (acting reasonably)).
 
“Reorganisation” means (without limitation) any transaction, deemed transaction, step, procedure or agreement, including (but without limitation) the transfer, distribution, contribution or settlement of assets and/or liabilities.
 
“Repayment Date” means the date specified as such in the Amortisation Schedule, as may be adjusted in accordance with clause 34.6 ( Business Days ) of this Agreement.
 
“Repayment Instalment” means each repayment instalment required pursuant to the Amortisation Schedule (as adjusted from time to time).
 
35

 
“Repeating Representations” means the representations set out under:
 
(A)               clauses 26.1 (Status), 26.2 (Legal validity), 26.3 (Non-conflict), 26.4 (Powers and authority) of this Agreement, each as at the time the power or authority was exercised only; and
 
(B)                 clauses 26.5 (Authorisations), 26.9 (Financial Statements and other factual information), 26.10 (Proceedings pending or threatened ), 26.11 ( Breach of laws ), 26.12 ( Ranking of security ), 26.13 ( Pari passu ranking ), 26.14 ( Assets ), 26.15 ( Project Agreements ), 26.16 ( No Immunity ) and 26.17 ( Ownership of Obligors ) of this Agreement.
 
“Replacement Lender” has the meaning given to that term in clause 10.10 (Right of repayment and cancellation in relation to a single Lender ) of this Agreement.
 
“Required Approvals” means all material approvals, licenses, consents and authorisations necessary in connection with the execution, delivery, performance or enforcement of any Finance Document or the development, construction and ownership of the relevant Obligor’s interest in a Borrowing Base Asset.
 
“Required Balance” means a balance which is sufficient to meet the payment of interest and fees only due and payable in the next six months on the Facility.
 
“Reserve Tail Date” means, at any time, the semi-annual Repayment Date immediately preceding the date on which a Forecast projects that the aggregate economically recoverable reserves remaining to be produced from the Borrowing Base Assets (as reflected in the current Forecast) is projected to be equal to or less than 25 per cent. of the aggregate of the economically recoverable reserves from the Borrowing Base Assets reflected in the Forecast agreed as a condition to first Utilisation. The Reserve Tail Date will be re-determined by each Forecast by reference to the aggregate of reserves for the Borrowing Base Assets adjusted for any reserves upgrades or downgrades, for additional reserves acquired pursuant to any Approved Development or Permitted Acquisition and for any disposal of reserves.
 
“Reserves Consultant” means Netherland Sewell & Associates, Inc., (or any other reputable consultant agreed to by the Technical and Modelling Bank (acting reasonably)) appointed in accordance with a scope of work and budget for fees and expenses agreed with the Borrower, the Facility Agent and the Technical and Modelling Bank.
 
“Reserves Consultant Appointment Letter” means the letter between Kosmos, the Facility Agent, the Technical and Modelling Bank and the Reserves Consultant setting out the terms of appointment of the Reserves Consultant, in the Agreed Form.
 
“Resignation Letter” means a letter substantially in the form set out in Schedule 10 (Form of Resignation Letter ).
 
“Retiring Guarantor” has the meaning given to it in clause 25.8 (Release of Guarantors’ right of contribution ).
 
36

 
“Revised Final Repayment Date” has the meaning given to that term in clause 9.2 (Amendment to Amortisation Schedule ) of this Agreement.
 
“Rollover Loan” means one or more Loans:
 
(A)               made or to be made on the same day that a maturing Loan is due to be repaid;
 
(B)                 the aggregate amount of which is equal to or less than the amount of the maturing Loan;
 
(C)                 made or to be made to the same Borrower for the purpose of refinancing a maturing Loan.
 
“Royalty Payments” means royalties payable to the Government by a contractor out of, or calculated by reference to, petroleum to which such contractor is entitled under the terms and conditions of the relevant Petroleum Agreement.
 
“Sanctions Regime” has the meaning given to it in paragraph (A) of the definition of “Qualifying Bank”.
 
“Schedule of Insurances” means the schedule of insurances in the Agreed Form (and initialled by the Borrower and/or KEG and the Facility Agent) setting out the insurances to be maintained by the Obligors.
 
“Second Currency” has the meaning given to it in clause 17.1 (Currency indemnity).
 
“Secured Liabilities” means at any time and without double counting, all present and future obligations and liabilities (actual or contingent) of each Obligor (whether or not for the payment of money and including any obligation to pay damages for breach of contract) which are, or are expressed to be, or may become due, owing or payable to any or all of the Secured Parties under or in connection with any of the Finance Documents, together with all costs, charges and expenses incurred by the Security Agent or any Secured Party which any Obligor is obliged to pay under any Finance Document.
 
“Secured Party” means each party to a Finance Document (other than an Obligor or Intercompany Borrower).
 
“Security Documents” means each of the following documents:
 
(A)               the KEG Offshore Security Assignment;
 
(B)                 the KEG Onshore Security Assignment;
 
(C)                 the KED Offshore Security Assignment;
 
(D)                the KEI Offshore Security Assignment;
 
(E)                  the KEO Offshore Security Assignment;
 
37

 
(F)                  the Borrower Offshore Security Assignment;
 
(G)                 the KEI and KEO Offshore Security Assignment;
 
(H)                the Charge over Shares in KED;
 
(I)                     the Charge over Shares in KEG;
 
(J)                    the Charge over Shares in KEO;
 
(K)                the Charge over Shares in KEI;
 
(L)                  the Charge over Shares in the Original Borrower;
 
(M)             the Assignment of Reinsurance Rights;
 
(N)                the KEG Offshore Project Accounts Agreement;
 
(O)                the KEG Onshore Project Accounts Agreement;
 
(P)                  the Borrower Offshore Project Accounts Agreement; and
 
(Q)                subject to the provisions of the Intercreditor Agreement, each other document evidencing or creating any Security Interest held or obtained from an Obligor for or in respect of any Secured Liabilities.
 
“Security Interest” means a mortgage, charge, pledge, lien or other security interest or any other agreement or arrangement having a similar effect.
 
“Service Document” has the meaning given to it in clause 45 (Service of Process).
 
“Shareholder” means any funds affiliated with Warburg Pincus and Blackstone Capital Partners or the Blackstone Group.
 
“Shareholder Affiliate” means any Affiliate of a Shareholder, any trust of which a Shareholder or any of its Affiliates is a trustee, any partnership of which a Shareholder or any of its Affiliates is a partner and any trust, fund or other entity which is managed by, or is under the control of, a Shareholder or any of its Affiliates, provided that any such trust, fund or other entity which has been established for at least 6 months solely for the purpose of making, purchasing or investing in loans or debt securities and which is managed or controlled independently from all other trusts, funds or other entities managed or controlled by a Shareholder or any of its Affiliates which have been established for the primary or main purpose of investing in the share capital of companies shall constitute a Shareholder Affiliate.
 
“Shareholder Distribution” means a shareholder distribution as calculated and defined in clause 28.23 ( Distributions ) of this Agreement.
 
“Signing Date” means the date on which each of the Finance Documents have been signed.
 
38

 
“Sources and Uses Statement” has the meaning given to it in clause 24.8 (Sources and Uses).
 
“Specified Time” means 11:00 a.m. London time on the relevant Quotation Day.
 
“Standard and Poor’s” means Standard & Poor’s Ratings Service, a division of the McGraw-Hill Companies, Inc., and any successor thereto and if such corporation shall for any reason no longer perform the functions of a securities rating agency, Standard & Poor’s shall be deemed to refer to any other internationally recognised rating agency agreed by the Facility Agent and Kosmos (both acting reasonably).
 
“Subordinated Creditor” means any Obligor whose rights are subordinated to those of the Creditors pursuant to a Deed of Subordination.
 
“Subordinated Debt” means all present and future moneys, debts, obligations and liabilities which are, or are expressed to be, or may become due, owing or payable by any Obligor to any Affiliate (in each case, whether alone or jointly, or jointly and severally, with any other person, whether actually or contingently, and whether as principal, surety or otherwise) together with any related Additional Debt.
 
“Successful Syndication” means the Underwriters each reduce their participation in the Facility to a final hold of not more than USD 200 million.
 
“Sum” has the meaning given to it in clause 17.1 (Currency indemnity).
 
“Tax” means any tax, levy, impost, duty or other charge or withholding of a similar nature (including any penalty or interest payable in connection with any failure to pay or any delay in paying any of the same).
 
“Technical and Environmental Consultant Appointment Letter” means the letter between Kosmos, the Facility Agent and the Technical Consultant, the Technical and Modelling Bank and Environmental Consultant setting out the terms of appointment of the Technical Consultant and Environmental Consultant, in the Agreed Form.
 
“Technical and Modelling Bank” means the Technical Bank and the Modelling Bank, provided that if the Technical Bank and the Modelling Bank cannot reach agreement on a certain issue, then the opinion of the Technical Consultant will be requested (to the extent a Technical Consultant is not already appointed and the parties do not agree on a replacement within 5 Business Days of notification of the failure to reach agreement, the Technical Bank and the Modelling Bank shall request the President of the Energy Institute of London to appoint an independent consultant within 5 Business Days). If no agreement can be reached after consulting the relevant Consultant, the three parties forming the Technical Bank (or in case of a modelling issue the two parties forming the Modelling Bank and the Consultant) will vote and the final decision shall be determined by a two-thirds majority vote.
 
“Technical Assumptions” means the technical assumptions agreed or determined in accordance with clause 19.1 ( Forecast Procedures ) of this Agreement.
 
39

 
“Technical Consultant” means Shaw Consultants International, Inc. (or any other reputable technical consultant agreed to by the Technical and Modelling Bank (acting reasonably)), appointed in accordance with a scope of work and budget for fees and expenses agreed with the Borrower, the Facility Agent and the Technical and Modelling Bank.
 
“Third Parties Act” has the meaning given to it in clause 1.4 (Third Party Rights).
 
“Total Available Facility Amount” means at any time the amount calculated as such pursuant to clause 3.2 ( Total Available Facility Amount ) of this Agreement.
 
“Total Commitments” means the aggregate of the Commitments of the Lenders.
 
“Total Facility Amount” means at any time, the total facility made available under the Facility but as reduced by the amount of any cancellation of the Facility.
 
“Transaction Document” means each Finance Document and each Project Agreement.
 
“Transfer Certificate” means a certificate substantially in the form set out in Schedule 7 (Form of Transfer Certificate ) of this Agreement or any other form agreed between the Facility Agent and Kosmos.
 
“Transfer Date” means, in relation to a transfer, the later of:
 
(A)               the proposed Transfer Date specified in the Transfer Certificate; and
 
(B)                 the date on which the Facility Agent executes the Transfer Certificate.
 
“Unit Substances” shall have the meaning given to that term in the UUOA.
 
“Unpaid Sum” means any sum due and payable but unpaid by an Obligor under the Finance Documents.
 
“USD” or “US Dollar” means the lawful currency of the United States of America.
 
“Utilisation” means a utilisation of the Facility by way of a Loan.
 
“Utilisation Date” means the date of a Utilisation, being the date on which the relevant Loan is to be made.
 
“Utilisation Request” means a notice substantially in the form set out in Schedule 4 (Utilisation Requests) of this Agreement or in the Agreed Form.
 
“UUOA” means the unitization and unit operating agreement entered into between GNPC, Tullow Ghana Limited, KEG, Anadarko WCTP Company, Sabre Oil and Gas Holdings Limited and EO dated 13 July 2009.
 
“VAT” means value added tax as provided for in the Value Added Tax Act 1994 or any regulations promulgated thereunder and any other tax of a similar nature.
 
40

 
 
“WCTP Block” means West Cape Three Points area offshore Ghana, being the area described in Annex 1 of the WCTP PA, but excluding any portions of such area in respect of which Contractor’s rights thereunder are from time to time relinquished or surrendered pursuant to the WCTP PA.
 
“WCTP JOA” means the joint operating agreement dated 27 July 2004 between KEG and EO in respect of the West Cape Three Points Block Off-shore Ghana (and all amendments and supplements thereto).
 
“WCTP PA” means the petroleum agreement dated 22 July 2004 between the Government, represented by the Minister, the GNPC, KEG and EO in respect of the West Cape Three Points Block Off-shore Ghana (and all amendments and supplements thereto).
 
1.2                 Construction of particular terms
 
Unless a contrary indication appears, any reference in this Agreement to:
 
(A)               “this Agreement” shall be construed as a reference to the agreement or document in which such reference appears together with all recitals and Schedules thereto;
 
(B)                 a reference to “assets” includes properties, revenues and rights of every description;
 
(C)                 an “authorisation” or “consent” shall be construed as including any authorisation, consent, approval, resolution, licence, exemption, permission, recording, notarisation, filing or registration;
 
(D)                an “authorised officer” shall be construed, in relation to any Party, as a reference to a Director or other person duly authorised by such Party as notified by such Party to the Facility Agent as being authorised to sign any agreement, certificate or other document or to take any decision or action, as applicable. The provision of any certificate or the making of any certification by any authorised officer of Kosmos shall not create for that authorised officer any personal liability to the Finance Parties;
 
(E)                  a “calendar year” is a reference to a period starting on (and including) 1 January and ending on (and including) the immediately following 31 December;
 
(F)                  a “certified copy” shall be construed as a reference to a copy of that document, certified by an authorised officer of the relevant Party delivering it to be a complete, accurate and up-to-date copy of the original document;
 
(G)                 a “clause” shall, subject to any contrary indication, be construed as a reference to a clause of the agreement or document in which such reference appears;
 
(H)                “continuing” shall, in relation to any Default or Event of Default, be construed as meaning that such Default or Event of Default has not been remedied or waived;
 
41

 
(I)                     the “equivalent” on any given date in any currency (the “first currency”) of an amount denominated in another currency (the “second currency”) is a reference to the amount of the first currency which could be purchased with the amount of the second currency at the spot rate of exchange quoted by the Facility Agent in the normal course of business at or about 11.00 a.m. on such date for the purchase of the first currency with the second currency in the London foreign exchange markets for delivery on the second Business Day thereafter;
 
(J)                    the “group” of any person, shall be construed as a reference to that person, its subsidiaries and any holding company of that person and all other subsidiaries of any such holding company, from time to time;
 
(K)                a “holding company” of a company or corporation shall be construed as a reference to any company or corporation of which the first-mentioned company or corporation is a subsidiary;
 
(L)                  “include” or “including” shall be deemed to be followed by “without limitation” or “but not limited to” whether or not they are followed by such phrase or words of like import;
 
(M)             a “month” or “Month” is a reference to a period starting on one day in a calendar month and ending on the numerically corresponding day in the next succeeding calendar month save that, where any such period would otherwise end on a day which is not a Business Day, it shall end on the next succeeding Business Day, unless that day falls in the calendar month succeeding that in which it would otherwise have ended, in which case it shall end on the immediately preceding Business Day provided that, if a period starts on the last Business Day in a calendar month or if there is no numerically corresponding day in the month in which that period ends, that period shall end on the last Business Day in that later month (and references to “ months ” and “ Months ” shall be construed accordingly);
 
(N)                a “person” shall be construed as a reference to any person, trust, firm, company, corporation, government, state or agency of a state or any association or partnership (whether or not having separate legal personality) of two or more of the foregoing;
 
(O)                a reference to a “regulation” includes any regulation, rule, official directive, request or guideline (whether or not having the force of Law but, if not having the force of Law, being a regulation, rule, official directive, request or guideline with which a prudent person carrying on the same or a similar business to Kosmos would comply) of any governmental body, Agency, department or regulatory, self-regulatory or other authority or organisation;
 
(P)                  a “right” shall be construed as including any right, title, interest, claim, remedy, discretion, power or privilege, in each case whether actual, contingent, present or future;
 
42

 
(Q)                a “Schedule” shall, subject to any contrary indication, be construed as a reference to a schedule of the agreement or document in which such reference appears;
 
(R)                 a “subsidiary” of a company or corporation means a subsidiary undertaking within the meaning of section 1162 of the Companies Act 2006 which shall be construed as a reference to any company or corporation:
 
(i)                       which is controlled, directly or indirectly, by the first-mentioned company or corporation;
 
(ii)                    more than half the issued share capital of which is beneficially owned, directly or indirectly, by the first-mentioned company or corporation; or
 
(iii)                 which is a subsidiary of another subsidiary of the first-mentioned company or corporation,
 
and, for these purposes, a company or corporation shall be treated as being controlled by another if that other company or corporation is able to direct its affairs and/or to control the composition of its board of directors or equivalent body;
 
(S)                  the “winding-up”, “dissolution” or “administration” of a company or corporation shall be construed so as to include any equivalent or analogous proceedings under the law of the jurisdiction in which such company or corporation is incorporated or any jurisdiction in which such company or corporation carries on business including the seeking of liquidation, bankruptcy, winding-up, reorganisation, dissolution, administration, receivership, judicial custodianship, administrative receivership, arrangement, adjustment, protection or relief of debtors; and
 
(T)                 a “year” is a reference to a period starting on one day in a month in a calendar year and ending on the numerically corresponding day in the same month in the next succeeding calendar year, save that, where any such period would otherwise end on a day which is not a Business Day, it shall end on the next succeeding Business Day, unless that day falls in the month succeeding that in which it would otherwise have ended, in which case it shall end on the immediately preceding Business Day Provided that, if a period starts on the last Business Day in a month, that period shall end on the last Business Day in that later month (and references to “ years ” shall be construed accordingly).
 
1.3                 Interpretation
 
(A)               Words importing the singular shall include the plural and vice versa.
 
(B)                 Words indicating any gender shall include each other gender.
 
(C)                 Unless a contrary indication appears, a term used in any other Finance Document or in any notice given under or in connection with any Finance Document to:
 
43

 
(i)                       any party or person shall be construed so as to include its and any subsequent successors, permitted transferees and permitted assigns in accordance with their respective interests;
 
(ii)                    such agreement or document or any other agreement or document shall be construed as a reference to each such agreement or document or, as the case may be, such other agreement or document as the same may have been, or may from time to time be, amended, varied, novated or supplemented, in each case to the extent permitted under the Finance Documents;
 
(iii)                 a time of day shall, save as otherwise provided in any agreement or document, be construed as a reference to London time.
 
(D)                Section, Part, Clause and Schedule headings contained in, and any index or table of contents to, any agreement or document are for ease of reference only.
 
1.4                 Third Party Rights
 
(A)               Any Hedging Counterparty may enforce the terms of clause 21.2 (Withdrawals — No Default Outstanding), clause 25 ( Guarantee and Indemnity ) and clause 41.2(C) ( Exceptions ) of this Agreement by virtue of the Contracts (Rights of Third Parties) Act 1999 (the “ Third Parties Act ”). This clause 1.4(A) confers a benefit on each such Hedging Counterparty, and, subject to the remaining provisions of this clause 1.4, is intended to be enforceable by each Hedging Counterparty by virtue of the Third Parties Act.
 
(B)                 Subject to paragraph (A) above, a person who is not a party to this Agreement has no right under the Third Parties Act to enforce or enjoy the benefit of any term of this Agreement.
 
(C)                 Notwithstanding any term of any Finance Document, this Agreement may be rescinded or varied without the consent of any person who is not a Party hereto.
 
44

 
PART 2
CONDITIONS PRECEDENT
 
2.                        CONDITIONS PRECEDENT
 
2.1                 Conditions Precedent to first Utilisation
 
Kosmos may not deliver a Utilisation Request unless the Facility Agent has received all of the documents and other evidence listed in Part I of Schedule 3 ( Conditions Precedent ) in form and substance satisfactory to the Facility Agent (acting reasonably), or their delivery has otherwise been waived in accordance with clause 2.3 ( Waivers of Conditions Precedent ). The Facility Agent (acting reasonably) shall notify Kosmos and the Lenders promptly upon being so satisfied.
 
2.2                 Conditions Precedent to each Utilisation
 
The Lenders will only be obliged to comply with clause 6.5 (Lenders’ participation) if, on the proposed Utilisation Date:
 
(A)               no Default or Event of Default is continuing or will result from the proposed Loan;
 
(B)                 an Authorised Signatory of Kosmos certifies that
 
(i)                       the funds from that Utilisation are expected to be applied in payment of amounts subject to and in accordance with the Cash Waterfall within 90 days of the relevant drawdown date (other than making a distribution in accordance with paragraph (vii) of the Cash Waterfall) or are otherwise required to maintain a reasonable and prudent level of working capital in the Project Accounts;
 
(ii)                    the aggregate principal amount outstanding under the Facility does not exceed the Borrowing Base Amount, and the making of the Utilisation would not result in the aggregate principal amount outstanding under the Facility exceeding the Borrowing Base Amount; and
 
(iii)                 the Repeating Representations to be made by each Obligor are, in the light of the facts and circumstances then existing, true and correct in all material respects (or, in the case of a Repeating Representation that contains a materiality concept, true and correct in all respects).
 
2.3                 Waivers of Conditions Precedent
 
(A)               The Facility Agent as applicable, acting in accordance with the instructions of the Lenders, may waive the requirement under clause 2.1  (Conditions Precedent to first Utilisation ) to deliver any one or more of the documents and other evidence listed in Schedule 3 ( Conditions Precedent to each Utilisation ), as applicable.
 
45

 
(B)                 Satisfaction of any of the conditions set out in clause 2.2 (Conditions Precedent) may be waived by the Facility Agent acting in accordance with the instructions of the Majority Lenders.
 
(C)                 Any waiver effected by the Facility Agent in accordance with this clause shall be binding on all Parties.
 
(D)                For avoidance of doubt, no Utilisation may be made under the Facility, until the Facility Agent has confirmed all relevant Conditions Precedent have been satisfied (acting reasonably) or waived in accordance with this clause 2 ( Conditions Precedent ).
 
(E)                  Prior to the first Utilisation of the Facility (and not thereafter), any Default or Event of Default which arises by virtue of the fact that the Security Interests granted pursuant to the Security Documents are second-ranking (due to the subsistence during such period of Security Interests (as defined in the Existing Finance Documents) which were granted pursuant to the Existing Finance Documents), shall be deemed not to have arisen.
 
46

 
PART 3
OPERATION OF THE FACILITY
 
3.                        THE FACILITY
 
3.1                 Facility Commitment amounts
 
(A)               Subject to the terms of this Agreement, the Lenders have agreed to make available to the Borrower a secured US Dollar revolving loan facility and a letter of credit facility in an aggregate amount equal to the Total Commitments.
 
(B)                 The Facility may be utilised by way of Loans (which, during the Availability Period only, shall include Rollover Loans) and Letters of Credit up to an aggregate amount not exceeding USD 200 million.
 
3.2                 Total Available Facility Amount
 
(A)               The Total Available Facility Amount shall be computed in accordance with this clause 3.2.
 
(B)                 If at any time the aggregate amount of all Loans exceeds the Borrowing Base Amount, the Total Available Facility Amount shall be zero.
 
(C)                 Notwithstanding any increase to the Total Available Facility Amount by the addition of (a) Additional Commitment pursuant to clause 3.3 below; or (b) the IFC Commitment pursuant to clause 3.4 below and subject to paragraph (B) above, the Total Available Facility Amount shall be an amount equal to the lesser of:
 
(i)                       the Total Facility Amount less (1) the amount of all Loans which have not been either prepaid or repaid and (2) the aggregate amount of any Letters of Credit issued, or to be issued, under the Facility (only to the extent not cash collateralised by amounts standing to the credit of the LC Cash Collateral Account); and
 
(ii)                    the Borrowing Base Amount less (1) the amount of all Loans and (2) the aggregate amount of any Letters of Credit issued, or to be issued, under the Facility (only to the extent not cash collateralised by amounts standing to the credit of the LC Cash Collateral Account),
 
where the Borrowing Base Amount is determined by reference to the most recent Forecast prepared in accordance with the Forecasting Procedures.
 
(D)                For the avoidance of doubt, if at any time a Letter of Credit is cash collateralised in whole in or part in accordance with clause 7.1(B) of this Agreement, the Total Available Facility Amount shall, subject always to paragraphs (B) and (C) above, automatically increase by the amount of such deposit. Conversely, in the event that the whole or any part of the cash collateral is withdrawn in accordance with clause 7.1(B) of this Agreement, then the Total Available Facility Amount will reduce by the amount of such withdrawal.
 
47

 
3.3                 Additional Commitment
 
(A)               Kosmos may notify the Facility Agent (such notice being an “Additional Commitment Notice”) that it has agreed with any Lender or any other bank or financial institution (in each case, an “ Additional Lender ”) to increase the Total Facility Amount by the provision of additional commitments under the Facility (each such increase in commitments being an “ Additional Commitment ”), provided that:
 
(i)                       the Additional Commitment Notice is delivered at any time after the earlier of (1) the date of Successful Syndication; and (2) the date falling six months after Financial Close, and prior to the expiry of the Availability Period;
 
(ii)                    all existing Lenders have been given a right of first refusal over a period of 30 days to provide the Additional Commitment following delivery of a copy of the Additional Commitment Notice to the Facility Agent;
 
(iii)                 the increase is to take effect before the expiry of the Availability Period and the maximum aggregate amount of Additional Commitment (including all previous increases) does not exceed USD 1 billion less any amount of IFC Commitment which has then been provided;
 
(iv)                no Event of Default is continuing or would arise as a result of the provision of the Additional Commitment; and
 
(v)                   the terms of the Additional Commitment shall, for all purposes of this Agreement, be treated pursuant to the terms of this Agreement in the same manner as the existing Commitments.
 
(B)                 Each Additional Commitment Notice shall:
 
(i)                       confirm that the requirements of clause 3.3(A) above are fulfilled;
 
(ii)                    specify the date upon which the Additional Commitment is anticipated to be made available to the Borrower (the “ Additional Commitment Date ”); and
 
(iii)                 where the Additional Lender is IFC, include any further details that may be required by the Facility Agent (acting reasonably) pursuant to clause 3.4 ( IFC as Additional Lender ).
 
(C)                 In the event that the Additional Lender is not a Party to this Agreement, Kosmos shall procure that each Additional Lender:
 
(i)                       delivers a Lender Accession Notice in the form set out in Schedule 8 (Form of Lender Accession Notice) duly completed and signed on behalf of the Additional Lender and specifying its Additional Commitment to the Facility Agent; and
 
48

 
(ii)                    accedes to the Intercreditor Agreement in accordance with the terms of the Intercreditor Agreement,
 
in each case, on or prior to the Additional Commitment Date.
 
(D)                Subject to the conditions in paragraph (B) and (C) above being met, from the relevant Additional Commitment Date:
 
(i)                       the Additional Lender shall make available the relevant Additional Commitment for Utilisation under the Facility in accordance with the terms of this Agreement (as amended);
 
(ii)                    the Additional Commitment shall rank pari passu with respect to existing Commitments; and
 
(iii)                 any necessary rebalancing of the Commitments and outstandings under the Facility and the Additional Commitment provided by the Additional Lender to ensure that they are pro rata (the “ New Commitment Rebalancing ”) will be made, at the Borrower’s election, by the Borrower making utilisations from the Additional Commitment:
 
(a)                   in priority to utilisations from Commitments under the Facility; or
 
(b)                  to effect a prepayment under the Facility to the existing Lenders (which amount may be redrawn by the Borrower),
 
in each case to procure, as far as practicable, any New Commitment Rebalancing, following which all utilisations shall be made pro rata.
 
(E)                  Each Additional Lender shall become a party to this Agreement (and be entitled to share in the Security created under the Security Documents in accordance with the terms of the Finance Documents) if such Additional Lender accedes to the Intercreditor Agreement in accordance with the Intercreditor Agreement.
 
(F)                  Each party (other than the relevant Additional Lender) irrevocably authorises and instructs the Facility Agent to execute on its behalf any Lender Accession Notice which has been duly completed and signed on behalf of that proposed Additional Lender and each Party agrees to be bound by such accession. The Facility Agent must promptly sign any such Lender Accession Notice (and in any event within three Business Days of receipt).
 
(G)                 The Facility Agent shall only be obliged to execute a Lender Accession Notice delivered to it by an Additional Lender once the Facility Agent (acting reasonably) has, to the extent that the necessary information is not already available to it, received all required information to comply with all necessary “know your customer” or other similar checks under all applicable laws and regulations in relation to the accession of such Additional Lender.
 
(H)                On the date that the Facility Agent executes a Lender Accession Notice:
 
49

 
(i)                       the Additional Lender party to that Lender Accession Notice, each other Finance Party and the Obligors shall acquire the same rights and assume the same obligations between themselves as they would have acquired and assumed had that Additional Lender been an Original Lender with the rights and/or obligations acquired or assumed by it as a result of that accession and with the Commitment specified by it as its Additional Commitment; and
 
(ii)                    that Additional Lender shall become a Party to this Agreement as a “Lender”.
 
3.4                 IFC as Additional Lender
 
(A)               In the event that the Additional Commitment is to be provided by IFC, subject to compliance with the provisions of clause 3.3 ( Additional Commitment ), IFC may provide its Additional Commitment (the “ IFC Commitment ”) through a separate tranche, facility or facilities ranking pari passu with the Facility (the “ IFC Facility ”) details of which, together with any amendments to the Finance Documents as Kosmos and IFC (each acting reasonably) consider necessary, shall be provided with the Additional Commitment Notice.
 
(B)                 Any IFC Commitment shall be provided on substantially the same terms and conditions as the Facility, save that the IFC Facility shall include such additional or alternative terms and conditions as required by IFC’s policies and practices (the rights in relation to which shall not be available to the Finance Parties).
 
(C)                 In order to rebalance the Commitments and outstandings under the Facility and the IFC Facility to ensure that they are pro rata (the “ IFC Rebalancing ”), at the Borrower’s election, the Borrower will make utilisations under the IFC Facility:
 
(i)                       in priority to the Facility; or
 
(ii)                    to effect a prepayment under the Facility (which amount may be redrawn by the Borrower),
 
in each case to procure, as far as practicable, the IFC Rebalancing, following which all drawings under the IFC Facility and the Facility shall be pro rata.
 
3.5                 Amendments to Finance Documents
 
(A)               The Parties shall, acting reasonably, make such amendments to the Finance Documents as may be necessary to increase the Total Facility Amount pursuant to clause 3.3 ( Additional Commitment ) above (including such amendments as required to implement any alternative terms and conditions as required by IFC’s policies and practices) and to enable each Additional Lender to accede to the Finance Documents and provide its Additional Commitment hereunder. The Facility Agent may effect, on behalf of the Finance Parties, any such amendment. Any Lender Accession Notice or accession in respect of the Intercreditor Agreement entered into, or any amendment to the Finance Documents effected pursuant to clause 3.3 ( Additional Commitment ) above, by
 
50

 
 
the Facility Agent, the Additional Lender or the Original Borrower, shall be binding on all Parties.
 
(B)                 Notwithstanding paragraph (A) above, any amendments to the Finance Documents or additional or alternative terms and conditions, in each case as may be reasonably required as a consequence of any IFC Commitment being provided to the Borrower shall not require the consent of the Finance Parties.
 
4.                        FINANCE PARTIES’ RIGHTS AND OBLIGATIONS
 
(A)               The obligations of each Finance Party under the Finance Documents are several. Failure by a Finance Party to perform its obligations under any Finance Documents to which it is a Party does not affect the obligations of any other Party under the Finance Documents. No Finance Party is responsible for the obligations of any other Finance Party under the Finance Documents.
 
(B)                 The rights of each Finance Party under or in connection with the Finance Documents to which it is a Party are separate and independent rights and any debt arising under the Finance Documents to a Finance Party from an Obligor shall be a separate and independent debt.
 
(C)                 A Finance Party may, except as otherwise stated in the Finance Documents, separately enforce its rights under the Finance Documents.
 
5.                        PURPOSE
 
5.1                 Purpose
 
The proceeds of any Loan or Letter of Credit may only be used by the Borrower for the following purposes:
 
(A)               in the case of a first Utilisation of the Facility, to repay all amounts outstanding under the Existing Finance Documents in full;
 
(B)                 to pay Project Costs (including Relevant Capital Expenditure);
 
(C)                 to pay Financing Costs (other than principal and interest);
 
(D)                to make advances to an Obligor under an Intercompany Loan Agreement to enable such Obligor to pay Project Costs;
 
(E)                  to fund the DSRA and the LC Cash Collateral Account;
 
(F)                  to meet all costs and expenses incurred in respect of making any Permitted Acquisition; and
 
(G)                 to issue Letters of Credit under the Facility.
 
51

 
5.2                 Monitoring
 
No Finance Party is bound to monitor or verify the application of any Loan made pursuant to the Finance Documents.
 
6.                        UTILISATION
 
6.1                 Availability Period
 
Subject to satisfaction of the relevant Conditions Precedent, the Facility shall be available for drawing during the period from and including the Signing Date to and including 15 May 2014.
 
6.2                 Delivery of a Utilisation Request
 
A Borrower may borrow a loan under the Facility by delivery to the Facility Agent of a duly completed Utilisation Request not later than 10:00 am on the third Business Day (or in the case of the first Utilisation only, the second Business Day) prior to the proposed Utilisation Date and the Facility Agent shall deliver such Utilisation Request to the Lenders within one Business Day of receipt of the same by it. For this purpose, if the Facility Agent receives the Utilisation Request on a day which is not a Business Day or after 10:00 am on a Business Day, it will be treated as having received the Utilisation Request on the following Business Day.
 
6.3                 Completion of a Utilisation Request
 
(A)               Each Utilisation Request is irrevocable and will not be regarded as having been duly completed unless:
 
(i)                       the proposed Utilisation Date is a Business Day within the Availability Period;
 
(ii)                    the amount of the Utilisation complies with clause 6.4 (Amount); and
 
(iii)                 the proposed Interest Period complies with clause 12 (Interest Periods).
 
(B)                 Only one Loan may be requested in each Utilisation Request and a maximum of 3 Utilisation Requests may be requested in any one month.
 
(C)                 A Borrower may not deliver a Utilisation Request if as a result of the proposed Utilisation 10 or more Loans would be outstanding.
 
6.4                 Amount
 
Kosmos must notify the Facility Agent and the Technical and Modelling Bank (giving notice of not less than three Business Days’ prior to the Utilisation Date) of the amount of any proposed Loan under the Facility that must be:
 
(A)               a minimum of USD 10 million (or, in any event, such lesser amount as the Facility Agent may agree); and
 
52

 
(B)                 an integral multiples of USD 10 million (or, in any event, such lesser amount as the Facility Agent may agree),
 
or, if less, the balance of the Facility.
 
6.5                 Lenders’ participation
 
(A)               If the conditions set out in this Agreement have been met, each Lender under the Facility shall make its participation in the relevant Loan available by the Utilisation Date through its Facility Office in accordance with the terms of this Agreement.
 
(B)                 The amount of a Lender’s participation in that Loan will be equal to the proportion borne by its Available Commitment to the Available Commitments under the Facility immediately prior to the making of the relevant Loan.
 
(C)                 The Facility Agent shall notify each Lender of the amount of each Loan under the Facility and the amount of its participation in each such Loan not less than 3 Business Days before the Utilisation Date.
 
(D)                A Business Day for the purposes of clause 6 (Utilisation) shall mean a day (other than a Saturday or Sunday) when banks are open for business in London, New York and Paris.
 
7.                        LETTERS OF CREDIT — UTILISATION
 
7.1                 General
 
(A)               In this clause 7 and clause 8 (Letters of Credit):
 
(i)                       “Expiry Date” means, for a Letter of Credit, the last day of its Term;
 
(ii)                    “LC Proportion” means, in relation to a Lender in respect of any Letter of Credit, the proportion (expressed as a percentage) borne by the Available Commitment of such Lender under the Facility to the aggregate Available Commitments of all the Lenders under the Facility immediately prior to the issue of that Letter of Credit, adjusted to reflect any assignment or transfer under this Agreement to or by that Lender;
 
(iii)                 “Renewal or Extension Request” means a written notice delivered to the Facility Agent in accordance with clause 7.7 ( Renewal or extension of a Letter  of Credit);
 
(iv)                “Start Date” means, for a Letter of Credit, the first day of its Term; and
 
(v)                   “Term” means each period determined under this Agreement for which an LC Issuing Bank is under a liability under a Letter of Credit.
 
(B)                 Any reference in this Agreement to:
 
53

 
(i)                       a “Finance Party” includes each of the LC Lenders and each of the LC Issuing Banks;
 
(ii)                    an amount borrowed under the Facility includes any amount utilised by way of Letter of Credit;
 
(iii)                 a Utilisation under the Facility made or to be made to the Borrower includes a Letter of Credit issued on its behalf;
 
(iv)                a Lender funding its participation in a Utilisation under the Facility includes a Lender participating in a Letter of Credit;
 
(v)                   amounts outstanding under the Facility include amounts outstanding under or in respect of any Letter of Credit;
 
(vi)                an outstanding amount of a Letter of Credit at any time is the maximum amount that is or may be payable in respect of that Letter of Credit at that time;
 
(vii)             the Borrower “repaying” or “prepaying” a Letter of Credit means:
 
(a)                   the Borrower providing cash collateral for that Letter of Credit by depositing funds into the LC Cash Collateral Account;
 
(b)                  the maximum amount payable under the Letter of Credit being reduced in accordance with its terms; or
 
(c)                   an LC Issuing Bank being satisfied (acting reasonably) that it has no further liability under that Letter of Credit,
 
and the amount, subject to the Cash Waterfall, by which a Letter of Credit is repaid or prepaid under sub-paragraphs (viii)(a) and (viii)(b) below is the amount of the relevant cash collateral or reduction; and
 
(viii)          the Borrower providing “cash collateral” for a Letter of Credit means the Borrower paying an amount in the currency of the Letter of Credit in to the LC Cash Collateral Account and the following conditions are met:
 
(a)                   the account is with the LC Issuing Bank (if the cash collateral is to be provided for all the Lenders) or with a Lender (if the cash collateral is to be provided for that Lender);
 
(b)                  withdrawals from the LC Cash Collateral Account may only be made at any time provided that:
 
(1)                    there is no Default or Event of Default outstanding at the time;
 
(2)                    the withdrawal does not occur during a BBA Cure Period;
 
54

 
(3)                    the latest Sources and Uses Statement does not show that there is a shortfall in funding projected to be available to meet Project Costs; and
 
(4)                    the Available Commitment at that time is equal to or exceeds the amount of the withdrawal; and
 
(c)                   any amount withdrawn from the LC Cash Collateral Account is deposited into the account from which the original payment was made into the LC Cash Collateral Account.
 
(C)                 clause 6 (Utilisation) does not apply to a Utilisation by way of Letter of Credit.
 
(D)                For the avoidance of doubt, in determining the amount of the Available Commitment and a Lender’s LC Proportion of a proposed Letter of Credit for the purposes of this Agreement the Available Commitment of a Lender will be calculated taking account of any cash collateral provided for outstanding Letters of Credit, subject to the Total Available Facility Amount not exceeding the lesser of (i) the Total Facility Amount and (ii) the Borrowing Base Amount.
 
(E)                  A “Business Day” for the purposes of clause 7 (Letters of Credit — Utilisation) shall mean a day (other than a Saturday or Sunday) when banks are open for business in London, New York and Paris.
 
(F)                  The ORGL LC shall be deemed to have been issued by BNP Paribas as LC Issuing Bank (such appointment as LC Issuing Bank being solely in respect of the ORGL LC) pursuant to a Utilisation Request submitted by the Borrower in accordance with the terms of this Agreement and such utilisation shall be deemed to have occurred immediately after the first Utilisation under the Facility (the “ ORGL LC Utilisation ”). For the avoidance of doubt:
 
(i)                       BNP Paribas shall pay the cash collateral already posted with it pursuant to the ORGL LC to the Distribution Reserve Account; and
 
(ii)                    no conditions other than those which are required in order to facilitate the first Utilisation will be required to be satisfied in order for the ORGL LC Utilisation to be effective.
 
7.2                 Letter of Credit Option
 
(A)               The Facility may also be utilised by way of Letters of Credit at any time prior to the Final Maturity Date.
 
(B)                 Letters of Credit may be issued under the Facility by any LC Issuing Bank or LC Issuing Banks as may be selected by the Borrower.
 
(C)                 The Borrower may at any time request any or all Lenders to agree to become a LC Issuing Bank. If any such Lender or Lenders so agree, the Borrower may in its absolute discretion decide which of those Lenders (if any) it wishes to appoint as a LC Issuing Bank.
 
55

 
(D)                The Borrower may appoint any Lender as an LC Issuing Bank at any time by notice in writing to the Facility Agent (accompanied by a deed of accession in the form agreed between the Agent and the Borrower, signed by the relevant Lender confirming its appointment as an LC Issuing Bank), following receipt of which the Facility Agent shall promptly countersign any such deed of accession on behalf of the Finance Parties (and in any event within 3 Business Days of receipt of the notice) and notify the Finance Parties (with a copy to the Borrower) that the relevant Lender has become an LC Issuing Bank.
 
7.3                 Delivery of a Utilisation Request for Letters of Credit
 
Subject to a LC Issuing Bank having been appointed, the Borrower may request a Letter of Credit to be issued by delivery to the Facility Agent and one or more LC Issuing Banks (as may be selected by the Borrower) of a duly completed Utilisation Request substantially in the form of Part II of Schedule 4 ( Utilisation Requests ) not later than the third Business Day prior to the proposed Utilisation Date and a maximum of 3 such Utilisation Requests may be delivered in any one month, provided that there shall not, at any time, be more than 10 Letters of Credit outstanding.
 
7.4                 Completion of a Utilisation Request for Letters of Credit
 
Each Utilisation Request for a Letter of Credit is irrevocable and will not be regarded as having been duly completed unless:
 
(A)               it specifies that it is for a Letter of Credit;
 
(B)                 it specifies the amount that is to be utilised under the Facility;
 
(C)                 the proposed Utilisation Date is a Business Day within the Availability Period;
 
(D)                the currency and amount of the Letter of Credit comply with clause 7.5 (Amount);
 
(E)                  the form of Letter of Credit is attached;
 
(F)                  the Expiry Date of the Letter of Credit falls on or before the Final Repayment Date for the Facility; and
 
(G)                 the delivery instructions for the Letter of Credit are specified.
 
7.5                 Amount
 
The amount of the proposed Letter of Credit must be an amount which is not more than the Total Available Facility Amount and which is a minimum of USD 5 million or, if less, the Total Available Facility Amount and which otherwise complies with clause 7.6(B)(ii).
 
7.6                 Issue of Letters of Credit
 
(A)               If the conditions set out in this Agreement have been met, the relevant LC Issuing Bank shall issue the Letter of Credit on the Utilisation Date.
 
56

 
(B)                 The relevant LC Issuing Bank will only be obliged to comply with paragraph (A) above if on the date of the Utilisation Request or Renewal or Extension Request and on the proposed Utilisation Date:
 
(i)                       in the case of a Letter of Credit renewed in accordance with clause 7.7 (Renewal or extension of a Letter of Credit), no Event of Default is continuing or would result from the proposed Utilisation and, in the case of any other Utilisation, no Default is continuing or would result from the proposed Utilisation;
 
(ii)                    the making of the proposed Utilisation would not result in (i) the aggregate principal amount outstanding under the Facility exceeding the lesser of the Total Facility Amount and the Borrowing Base Amount or (ii) the aggregate of all outstanding Letters of Credit issued by the LC Issuing Banks exceeding USD 200 million;
 
(iii)                 the Repeating Representations to be made by each Obligor are true in all material respects (or, in the case of a Repeating Representation that contains a materiality concept, true and correct in all respects); and
 
(iv)                the LC Issuing Bank and the Lenders have completed all applicable know-your-customer and compliance requirements which are required by law in relation to the beneficiary of the Letter of Credit.
 
(C)                 The amount of each Lender’s participation in each Letter of Credit will be equal to the proportion borne by the Available Commitment of such Lender under the Facility to the aggregate Available Commitments of all the Lenders under the Facility immediately prior to the issue of the Letter of Credit.
 
(D)                The Facility Agent shall notify the LC Issuing Bank and each Lender of the details of the requested Letter of Credit and its participation in that Letter of Credit by the Specified Time.
 
7.7                 Renewal or extension of a Letter of Credit
 
(A)               The Borrower may request any Letter of Credit issued on its behalf be renewed or extended by delivery to the Facility Agent and the relevant LC Issuing Bank of a Renewal or Extension Request by the sixth Business Day before the date of the proposed renewal.
 
(B)                 The Lenders shall treat any Renewal or Extension Request in the same way as a Utilisation Request for a Letter of Credit except that the conditions set out in paragraph (E) of clause 7.4 ( Completion of a Utilisation Request for Letters of Credit ) shall not apply.
 
(C)                 The terms of each renewed or extended Letter of Credit shall be the same as those of the relevant Letter of Credit immediately prior to its renewal, except that:
 
57

 
(i)                       its amount may be less than the amount of the Letter of Credit immediately prior to its renewal or extension;
 
(ii)                    (in relation to a renewal only) its Term shall start on the date which was the Expiry Date of the Letter of Credit immediately prior to its renewal, and shall end on the proposed Expiry Date specified in the Renewal or Extension Request subject to clause 7.4(F); and
 
(iii)                 (in relation to an extension only) its Term shall start on the date which was the Start Date of the Letter of Credit immediately prior to its extension, and shall end on the proposed Expiry Date specified in the Renewal or Extension Request subject to clause 7.4(F)
 
(D)                If the conditions set out in this Agreement have been met, the relevant LC Issuing Bank shall re-issue and/or amend any Letter of Credit pursuant to a Renewal or Extension Request.
 
8.                        LETTERS OF CREDIT — GENERAL PROVISIONS
 
8.1                 When immediately repayable or prepayable
 
If a Letter of Credit or any amount outstanding under a Letter of Credit becomes payable, the Borrower shall repay or prepay that amount within five Business Days of demand by the relevant LC Issuing Bank.
 
8.2                 Fee payable in respect of Letters of Credit
 
(A)               The Borrower shall pay to each of the LC Issuing Banks a fronting fee in respect of each Letter of Credit issued by it, in the amount and at the times agreed in the letter between each relevant LC Issuing Bank and the Borrower. A reference in this Agreement to a Fee Letter shall include the letter referred to in this paragraph.
 
(B)
 
(i)                       Subject to (ii) below, the Borrower shall pay to the Facility Agent (for the account of each LC Lender) a letter of credit fee computed at the same rate as the Margin on the outstanding amount of each Letter of Credit for the period from the issue of that Letter of Credit until its Expiry Date. This fee shall be distributed according to each LC Lender’s LC Proportion of that Letter of Credit.
 
(ii)                    The Borrower shall be entitled to deduct, from the letter of credit fee calculated as described in (i) above and paid to the Facility Agent, in respect of each Relevant Lender, an amount which is the product of the Margin and any Borrower Replacement Collateral (as defined in clause 8.10 below) held in respect of such Relevant Lender (the “ RL Reduction ”). The net fee distributed by the Facility Agent to each Relevant Lender shall be the fee calculated according to such Relevant
 
58

 
Lender’s LC Proportion then reduced by the amount of the RL Reduction.
 
(C)                 The accrued letter of credit fee on a Letter of Credit shall be payable quarterly (on each of 31 March, 30 June, 30 September and 31 December and as from the first of such dates falling after the date of issue of that Letter of Credit) and on the Expiry Date for that Letter of Credit.
 
(D)                If the Borrower uses cash collateral to cover any part of a Letter of Credit then the fronting fee payable to the relevant LC Issuing Bank and the letter of credit fee payable for the account of each LC Lender shall not (in respect of the part of the Letter of Credit covered by the cash collateral) be payable.
 
8.3                 Claims under a Letter of Credit
 
(A)               The Borrower irrevocably and unconditionally authorises each LC Issuing Bank to pay any claim made or purported to be made under a Letter of Credit and which appears on its face to be in order (a “ claim ”).
 
(B)                 The Borrower shall immediately on demand pay to the Facility Agent for the account of the relevant LC Issuing Bank an amount equal to the amount of any claim under that Letter of Credit.
 
(C)                 The Borrower acknowledges that the LC Issuing Bank:
 
(i)                       is not obliged to carry out any investigation or seek any confirmation from any other person before paying a claim; and
 
(ii)                    deals in documents only and will not be concerned with the legality of a claim or any underlying transaction or any available set-off, counterclaim or other defence of any person.
 
(D)                The obligations of the Borrower under this clause will not be affected by:
 
(i)                       the sufficiency, accuracy or genuineness of any claim or any other document; or
 
(ii)                    any incapacity of, or limitation on the powers of, any person signing a claim or other document.
 
8.4                 Indemnities
 
(A)               The Borrower shall immediately on demand indemnify each LC Issuing Bank against any cost, loss or liability incurred by such LC Issuing Bank (otherwise than by reason of such LC Issuing Bank’s gross negligence or wilful misconduct and otherwise in respect of the obligation of any Lender to provide cash collateral pursuant to Clause 8.10) in acting as an LC Issuing Bank under any Letter of Credit.
 
59

 
(B)                 Each Lender shall (according to its LC Proportion) immediately on demand by the Facility Agent (acting on the instructions of the relevant LC Issuing Bank), indemnify each LC Issuing Bank against any cost, loss or liability incurred by the LC Issuing Bank (otherwise than by reason of such LC Issuing Bank’s gross negligence or wilful misconduct) in acting as such LC Issuing Bank under any Letter of Credit (unless that LC Issuing Bank has been reimbursed by the Borrower pursuant to a Finance Document).
 
(C)                 The Borrower shall immediately on demand reimburse any Lender for any payment it makes to an LC Issuing Bank under this clause 8.4 ( Indemnities ) (other than any Cash Deposit made pursuant to Clause 8.10 but including in respect of any amount withdrawn from the Cash Deposit and payment to any LC Issuing Bank under Clause 8.10(C) or 8.10(D)). In the absence of reimbursement of the LC Issuing Bank or Lenders by the Borrower pursuant to this clause 8.4 within 5 Business Days of demand (the “ LC Payment Date ”), the Borrower shall be deemed to have requested a Loan of an amount (in Dollars) equal to the outstanding amount payable on the LC Payment Date and the Borrower shall be treated as having agreed to borrow that Loan on the LC Payment Date. The proceeds of each Loan made available by the Lenders in accordance with this clause 8.4(C) and deemed to be made to the Borrower shall be paid to the LC Issuing Bank (or, as the case may be, the Facility Agent on behalf of the Lenders) in satisfaction of the obligations of the Borrower in accordance with this clause 8.4 to reimburse the LC Issuing Bank or Lenders for the amount of the outstanding payment.
 
(D)                The obligations of each Lender and the Borrower under this clause are continuing obligations and will extend to the ultimate balance of sums payable by that Lender or, as the case may be, the Borrower in respect of any Letter of Credit, regardless of any intermediate payment or discharge in whole or in part.
 
(E)                  The obligations of a Lender or a Borrower under this clause will not be affected by any act, omission, matter or thing which, but for this clause, would reduce, release or prejudice any of its obligations under this clause (without limitation and whether or not known to it or any other person) including:
 
(i)                       any time, waiver or consent granted to, or composition with, any Obligor, any beneficiary under a Letter of Credit or any other person;
 
(ii)                    the release of any other Obligor or any other person under the terms of any composition or arrangement;
 
(iii)                 the taking, variation, compromise, exchange, renewal or release of, or refusal or neglect to perfect, take up or enforce, any rights against, or security over assets of, any Obligor, any beneficiary under a Letter of Credit or other person or any non-presentation or non-observance of any formality or other requirement in respect of any instrument or any failure to realise the full value of any security;
 
60

 
(iv)                any incapacity or lack of power, authority or legal personality of or dissolution or change in the members or status of an Obligor, any beneficiary under a Letter of Credit or any other person;
 
(v)                   any amendment (however fundamental) or replacement of a Finance Document, any Letter of Credit or any other document or security;
 
(vi)                any unenforceability, illegality or invalidity of any obligation of any person under any Finance Document, any Letter of Credit or any other document or security; or
 
(vii)             any insolvency or similar proceedings.
 
8.5                 Rights of contribution
 
The Borrower will not be entitled to any right of contribution or indemnity from any Finance Party in respect of any payment it may make under this clause 8.
 
8.6                 Role of a LC Issuing Bank
 
(A)               Nothing in this Agreement constitutes a LC Issuing Bank as a trustee or fiduciary of any other person.
 
(B)                 An LC Issuing Bank shall not be bound to account to any Lender for any sum, or the profit element of any sum received by it for its own account.
 
(C)                 An LC Issuing Bank may accept deposits from, lend money to and generally engage in any kind of banking or other business with any member of the Group.
 
(D)                An LC Issuing Bank may rely on:
 
(i)                       any representation, notice or document believed by it to be genuine, correct and appropriately authorised; and
 
(ii)                    any statement made by a director, Authorised Signatory or employee of any person regarding any matters which may reasonably be assumed to be within his knowledge or within his power to verify.
 
(E)                  An LC Issuing Bank may engage, pay for and rely on the advice or services of any lawyers, accountants, surveyors or other experts.
 
(F)                  An LC Issuing Bank may act in relation to the Finance Documents through its personnel and agents.
 
(G)                 An LC Issuing Bank is not responsible for:
 
(i)                       the adequacy, accuracy and/or completeness of any information (whether oral or written) provided by any Party (including itself), or any other person under or in connection with any Finance Document, the transactions contemplated by the Finance Documents or any other
 
61

 
agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document; or
 
(ii)                    the legality, validity, effectiveness, adequacy or enforceability of any Finance Document or any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document.
 
8.7                 Exclusion of liability
 
(A)               Without limiting paragraph (B) below, the LC Issuing Bank will not be liable for any action taken by it under or in connection with any Finance Document, unless directly caused by its gross negligence or wilful misconduct.
 
(B)                 No Party (other than the LC Issuing Bank) may take any proceedings against any officer, employee or agent of the LC Issuing Bank in respect of any claim it might have against the LC Issuing Bank or in respect of any act or omission of any kind by that officer, employee or agent in relation to any Finance Document and any officer, employee or agent of the LC Issuing Bank may rely on this clause subject to clause 1.4 ( Third Party Rights ) and the provisions of the Third Parties Act.
 
8.8                 Credit appraisal by the Lenders
 
Without affecting the responsibility of any Obligor for information supplied by it or on its behalf in connection with any Finance Document, each LC Lender confirms to the LC Issuing Bank that it has been, and will continue to be, solely responsible for making its own independent appraisal and investigation of all risks arising under or in connection with any Finance Document including, but not limited to, those listed in paragraphs (A) to (D) of clause 32.15 ( Credit appraisal by the Lenders ).
 
8.9                 Amendments and Waivers
 
Notwithstanding any other provision of any Finance Document, an amendment or waiver which relates to the rights or obligations of an LC Issuing Bank may not be effected without the consent of the LC Issuing Bank.
 
8.10          Cash collateralisation
 
(A)               If and for so long as:
 
(i)                       the long-term senior unsecured credit rating of a Lender is, or is reduced to, below A-(Standard & Poor’s) or A3 (Moody’s); or
 
(ii)                    it becomes unlawful in any applicable jurisdiction for a Lender to perform its obligations under Clause 8.4 ( Indemnities ) of this Agreement,
 
(any such Lender being a “Relevant Lender”) then, within two (2) Business Days of the date of publication by S&P or Moody’s of such rating downgrade or the date upon which the obligations become unlawful, the Relevant Lender shall,
 
62

 
unless otherwise agreed by the LC Issuing Bank, as security for (but without prejudice to) its obligations under Clause 8.4 ( Indemnities ), pay to the LC Issuing Bank an amount equal to its LC Proportion of the aggregate outstandings under all issued Letters of Credit at such date (the “ Cash Deposit ”). The Relevant Lender shall, within ten (10) Business Days of any increase in such aggregate outstandings, pay to the LC Issuing Bank an amount equal to its LC Proportion of any such increase (unless otherwise agreed by the Issuing Bank) (and any additional amount so paid shall form part of the Cash Deposit). If requested by the LC Issuing Bank, the Relevant Lender shall enter into security documentation over the Cash Deposit in form and substance satisfactory to the LC Issuing Bank (acting reasonably).
 
(B)                 Any Cash Deposit made pursuant to this Clause 8.10 shall be placed by the LC Issuing Bank in a separately designated bank account and shall bear interest (at the rate of interest customarily given by the LC Issuing Bank for short-term cash deposits in amounts equal to such Cash Deposit) from (and including) the date of deposit of any amounts in, until (but excluding) the date of withdrawal of any amounts from, such account (such amount held being the “ Borrower Replacement Collateral ”).
 
(C)                 The LC Issuing Bank shall only withdraw amounts standing to the credit of such account:
 
(i)                       for payment to the LC Issuing Bank up to (and including) the amount of the Cash Deposit in accordance with Clause (D) below; and
 
(ii)                    in excess of the Cash Deposit, for payment to the Relevant Lender, if so instructed by the Relevant Lender.
 
(D)                Without prejudice to the provisions of Clause 8.4(B), each Relevant Lender hereby irrevocably authorises the LC Issuing Bank to withdraw from any account established pursuant to this Clause 8.10 in relation to such Relevant Lender such Relevant Lender’s LC Proportion of the amount specified in any claim made under a Letter of Credit, up to the amount of the Relevant Lender’s Cash Deposit in discharge of such Relevant Lender’s obligations to it under Clause 8.4(B).
 
(E)                  If and to the extent the Relevant Lender at any time fails to comply with its payment obligations under Clause 8.10(A), then (without prejudice to Clause 8.4(B)):
 
(i)                       the Relevant Lender hereby irrevocably authorises the Agent to apply its entitlement to sums received by the Agent from any source in respect of payment under, and/or any other sum received by the Agent under or in respect of, the Finance Documents, towards such payment obligations;
 
(ii)                    the Borrower and the LC Issuing Bank may (in their sole discretion) agree that the Borrower shall pay an amount to the LC Issuing Bank:
 
63

 
(a)                   which may or may not be equal to the Relevant Lender’s Cash Deposit or such part thereof as is unpaid by the Relevant Lender; and
 
(b)                  which shall be placed by the LC Issuing Bank in a separately designated bank account and shall bear interest (at the rate of interest customarily given by the LC Issuing Bank for short-term cash deposits in amounts equal to such amounts) from (and including) the date of deposit of any amounts in, until (but excluding) the date of withdrawal of any amounts from, such account,
 
and
 
(iii)                 the LC Issuing Bank may withdraw amounts standing to the credit of such account:
 
(a)                   to pay the LC Issuing Bank such Relevant Lender’s LC Proportion of any claim made under a Letter of Credit; and
 
(b)                  as otherwise agreed between the Borrower and the LC Issuing Bank.
 
64

 
PART 4
PAYMENTS, CANCELLATION, INTEREST AND FEES
 
9.                        REPAYMENT
 
9.1                 Repayment of the Facility
 
(A)               Subject to paragraph (B) below, all Loans outstanding under the Facility will be repaid semi-annually on each successive 15 June and 15 December commencing on 15 June 2014. Repayment Instalments will be sufficient to ensure that the Amortisation Schedule is met.
 
(B)                 Any repayment made during the Availability Period may be redrawn, but any repayment may not be redrawn after the expiry of the Availability Period.
 
9.2                 Amendment to Amortisation Schedule
 
(A)               In the event that the Reserve Tail Date is earlier than the Final Maturity Date, the Amortisation Schedule will be amended so that:
 
(i)                       the final Repayment Instalment for the Facility is to be paid on the Reserve Tail Date (the “Revised Final Repayment Date ”); and
 
(ii)                    the Repayment Instalment payable on each Repayment Date shall be adjusted on a pro rata basis so as to ensure that all Loans under the Facility are fully repaid on the Reserve Tail Date.
 
(B)                 In the event that the Total Facility Amount is increased pursuant to clause 3 (The Facility), the Amortisation Schedule will be amended accordingly to reflect such increase.
 
10.                 PREPAYMENT AND CANCELLATION
 
10.1          General
 
(A)               Subject to there being no Event of Default outstanding and other than an obligation to make a prepayment where the aggregate outstandings under the Facility exceed the Borrowing Base Amount at the end of the BBA Cure Period or upon a Change of Control, prepayments in respect of the Facility shall be paid at the end of the next Interest Period falling not less than 15 days after the date on which the event giving rise to the obligation to make the prepayment occurs, and shall be applied pro rata to each Repayment Instalment under the Facility.
 
(B)                 Any amount prepaid may only be redrawn if such prepayment and Utilisation occurs prior to expiry of the Availability Period.
 
(C)                 Any prepayment shall be made with accrued interest on the amount prepaid and, subject to Break Costs (excluding any Margin), without premium or penalty.
 
65

 
10.2          Illegality
 
(A)               If it becomes unlawful in any applicable jurisdiction for a Lender (an “Illegality Lender”) to perform any of its obligations as contemplated by the Finance Documents, or to fund or maintain its participation in any Utilisation:
 
(i)                       that Lender shall promptly notify the Facility Agent upon becoming aware of that event;
 
(ii)                    upon the Facility Agent notifying Kosmos, the Commitment of that Lender will be immediately cancelled; and
 
(iii)                 the Borrower shall either:
 
(a)                   if the Lender so requires, repay that Lender’s participation in the Utilisations made to the Borrower on the last day of the Interest Period for each Utilisation occurring after the Facility Agent has notified the Borrower or, if earlier, the date specified by the Lender in the notice delivered to the Facility Agent (being no earlier than the last day of any applicable grace period permitted by law); or
 
(b)                  replace that Lender in accordance with paragraph (B) of clause 10.10 (Right of repayment and cancellation in relation to a single Lender ) on or before the first date applicable under paragraph (a) above in respect of which a payment is due and payable.
 
(B)                 If it becomes unlawful in any applicable jurisdiction for the Borrower to perform any of its obligations as contemplated by the Finance Documents:
 
(i)                       the Borrower shall promptly notify the Facility Agent upon becoming aware of that event;
 
(ii)                    the Facility Agent shall notify the Lenders; and
 
(iii)                 the Borrower shall repay each Utilisation made to it on the last day of the Interest Period for that Utilisation occurring after the Facility Agent have notified the Lenders or, if earlier, the last day of any applicable grace period permitted by law.
 
(C)                 If it becomes unlawful for an LC Issuing Bank to issue or leave outstanding any Letter of Credit, the relevant LC Issuing Bank shall promptly notify the Facility Agent upon becoming aware of that event, and upon the Facility Agent notifying the Borrower, (i) the Facility shall cease to be available for the issue of Letters of Credit unless and until the relevant LC Issuing Bank is replaced by another Lender in accordance with paragraph (B) of clause 10.10 ( Right of repayment and cancellation in relation to a single Lender ) and (ii) the Borrower shall prepay all Letters of Credit issued by such LC Issuing Bank and use its reasonable
 
66

 
endeavours to procure the release of such LC Issuing Bank from all outstanding Letters of Credit.
 
10.3          Aggregate outstandings exceed the Borrowing Base Amount
 
(A)               In the event that a Forecast shows that the aggregate of the outstandings under the Facility on the relevant Forecast Date exceeds the Borrowing Base Amount as determined in such Forecast, the Borrower shall, within 90 days of the date of the relevant Forecast (in addition to Repayment Instalments under the Amortisation Schedule), make an additional mandatory repayment of the Facility as necessary to ensure that the aggregate of the outstandings under the Facility does not exceed the Borrowing Base Amount provided always that:
 
(i)                       subject to (ii) below, an Event of Default shall arise in respect of such mandatory prepayment only if such prepayment has not been made in full after a period of 90 days from the relevant Forecast Date (the “ BBA Cure Period ”); and
 
(ii)                    such mandatory repayment will be required at the expiry of the BBA Cure Period only if, at such time, a Forecast prepared immediately prior to the expiry of the BBA Cure Period confirms that the aggregate of the outstandings under the Facility exceeds the Borrowing Base Amount.
 
(B)                 The Obligors shall be entitled to make any such mandatory prepayment by (i) depositing cash into an account with the Account Bank secured in favour of the Lenders (which shall be a Project Account) which has been established solely for this purpose or (ii) procuring a letter of credit on terms approved by the Facility Agent (acting reasonably), in favour of the Facility Agent, in each case, in an amount equal to the mandatory prepayment required. Any excess standing to the credit of such account on any Forecast Date shall be released and may be withdrawn by the Borrower and applied for any purpose as it sees fit (without reference to the Cash Waterfall) provided that prior to being paid into such account none of the Secured Parties had any rights to such amounts (if any Secured Parties had any rights to such amount, such amount shall be paid into an Offshore Proceeds Account).
 
10.4          Permitted disposals
 
If, as a result of a Permitted Disposal, the amount outstanding under the Facility exceeds the Borrowing Base Amount, then the required amount of proceeds from such Permitted Disposal to ensure that there is no such excess, after having taken into account the impact of the Permitted Disposal on the Borrowing Base Amount will be used to make a prepayment of the Facility.
 
10.5          Insurance Receipts
 
(A)               All Insurance Proceeds received by an Obligor in excess of 10 million shall be paid into and retained in the Insurance Proceeds Account until applied in accordance with the terms of this clause.
 
67

 
(B)                 All net proceeds of any insurance claim received by an Obligor in respect of a Borrowing Base Asset shall, unless the Majority Lenders otherwise agree, first be applied in prepayment of the Facility:
 
(i)                       where the aggregate amount of the insurance proceeds received is in excess of USD 100 million (less expenses); or
 
(ii)                    if less than USD 100 million but more than USD 10 million, to the extent not applied or committed to be applied to meet a third party claim or to cover operating losses of, or in the reinstatement of, a Borrowing Base Asset or purchase of a replacement Borrowing Base Asset or otherwise in amelioration of the loss to a Borrowing Base Asset or reinvestment in the Borrowing Base Asset within, in each case, one year of receipt.
 
10.6          Change of Control
 
(A)               Upon a Change of Control:
 
(i)                       the Obligor shall promptly notify the Facility Agent upon becoming aware of the occurrence of that event; and
 
(ii)                    if the Majority Lenders so require, the Facility Agent shall, on not less than 30 days written notice to Kosmos, cancel the Commitments and the Borrower shall repay each Lender’s participation in any Utilisations on the last day of the then current period under the Facility, together with accrued interest and all other amounts accrued under the Finance Documents.
 
(B)                 For the purposes of paragraph (A) above, a “Change of Control” means any person (or persons with whom they act in concert) other than a Permitted Transferee acquiring, directly or indirectly, more than 50 per cent. of the ordinary share capital in any Obligor carrying a right to vote in general meetings of that company. For the avoidance of doubt, a Change of Control shall not occur on an IPO of any Shareholder (directly or indirectly) in KEO or the Borrower, or an IPO of any Obligor.
 
(C)                 For the purposes of paragraph (B) above, any persons includes more than one person acting in concert and a “ Permitted Transferee ” means:
 
(i)                       an Affiliate of a Shareholder or KEH, so long as they remain an Affiliate (including any funds associated with Warburg Pincus and Blackstone Capital Partners or the Blackstone Group); or
 
(ii)                    a person who is otherwise approved by the Majority Lenders (acting reasonably) provided that any Lender which does not grant its approval may, on not less than 30 days written notice to the Facility Agent and Kosmos, demand that its participation in the Facility be prepaid in full and that its Commitment be immediately cancelled, provided that Kosmos may, in accordance with paragraph (B) of clause 10.10 ( Right of repayment and cancellation in relation to a single Lender ), procure
 
68

 
the replacement of that Lender or the transfer of its participation and Commitment to another Lender (with that Lender’s consent) rather than such prepayment and cancellation provided that such replacement or transfer is completed within the relevant notice period given by the relevant Lender. If such replacement or transfer does not occur within the relevant period, that Lender’s participation in the Facility shall be immediately due and payable in full by the Borrower and its Commitment immediately cancelled.
 
10.7          Automatic Cancellation
 
At the close of business in London on the last Business Day of the Availability Period for the Facility, the undrawn Commitment of each Lender under the Facility at that time shall be automatically cancelled.
 
10.8          Voluntary Cancellation
 
(A)               Kosmos may, by giving not less than ten Business Days’ (or such shorter period as the Majority Lenders may agree) prior written notice to the Facility Agent, without penalty, cancel the undrawn Commitments under any Facility in whole or in part (but if in part, in a minimum amount of USD 1 million or, if less, the balance of the undrawn Commitments). The relevant Commitments in respect of the Facility will be cancelled on a date specified in such notice, being a date not earlier than ten Business Days after the relevant notice is received by that Facility Agent.
 
(B)                 Any valid notice of cancellation will be irrevocable and will specify the date on which the cancellation shall take effect. No part of any Commitment which has been cancelled or which is the subject of a notice of cancellation may subsequently be utilised.
 
(C)                 When any cancellation of Commitments under the Facility takes effect, each Lender’s Available Commitment under the Facility will be reduced by an amount which bears the same proportion to the total amount being cancelled as its Available Commitment under the Facility bears to the Available Commitment (at that time) under the Facility.
 
10.9          Voluntary Prepayment of Loans
 
(A)               Subject to clause 10.1 (General), a Utilisation may be prepaid whether in whole or in part by the Borrower without penalty upon ten Business Days’ prior written notice to the Facility Agent.
 
(B)                 Any valid notice of prepayment will be irrevocable and, unless a contrary indication appears in this Agreement, will specify the date on which the cancellation shall take effect. Any amount prepaid or repaid may not be redrawn if such prepayment or repayment and Utilisation occurs after the expiry of the Availability Period.
 
(C)                 Prepayment shall take effect:
 
69

 
(i)                       on the last day of the then current Interest Period; or
 
(ii)                    on any other date subject to payment by the Borrower, on demand of Break Costs (if any), in accordance with clause 13.4 ( Break Costs ).
 
(D)                Unless a contrary indication appears in this Agreement, when any prepayment of the whole or part of a Loan takes place, each Lender’s participation in the relevant Loan shall be reduced rateably.
 
10.10   Right of repayment and cancellation in relation to a single Lender
 
(A)               If:
 
(i)                       Kosmos reasonably believes that the sum payable to any Lender by an Obligor is required to be increased under clause 15.2 ( Tax gross-up );
 
(ii)                    Kosmos receives a notice from the Facility Agent under clause 15.3 (Tax Indemnity) or clause 16 (Increased Costs );
 
(iii)                 any Lender is or becomes a Non-Funding Lender; or
 
(iv)                any Lender is or becomes entitled to increase its rate of interest further to clause 13.2 (Market disruption),
 
Kosmos may, while (in the case of paragraph (i) and (ii) above) the circumstance giving rise to the belief or notice continues or (in the case of (iii) or (iv) above) the relevant circumstance continues:
 
(a)                   give the Facility Agent notice of cancellation of the Commitment of that Lender and its intention to procure the repayment of that Lender’s participation in the Utilisations;
 
(b)                  in the case of a Non-Funding Lender or Illegality Lender, give the Facility Agent notice of cancellation of the Available Commitment of that Lender in relation to the Facility and reinstate all or part of such Available Commitment in accordance with paragraph (B) below;
 
(c)                   or replace that Lender in accordance with paragraph (B) below.
 
(B)                 Kosmos may:
 
(i)                       in the circumstances set out in paragraph (A) above or pursuant to clause 10.1 (General) or clause 10.2 ( Illegality ) or clause 10.6(A)(ii) ( Change of Control ), replace an Existing Lender (as defined in clause 30 ( Changes to the Lenders )), with one or more other Lenders (which need not be Existing Lenders) (each a “ Replacement Lender ”), which have agreed to purchase all or part of the Commitment and participations of that Existing Lender in Utilisations made to Kosmos
 
70

 
pursuant to an assignment or transfer in accordance with the provisions of clause 30 (Changes to the Lenders ); or
 
(ii)                    in the circumstances set out in paragraph (A)(iv)(a) of this clause 10.10, cancel the Available Commitments of the Non-Funding Lender or Illegality Lender in respect of the Facility and procure that one or more Replacement Lenders assume Commitments under the Facility in an aggregate amount not exceeding the Available Commitment of the relevant Non-Funding Lender or Illegality Lender in relation to the Facility,
 
in each case on condition that:
 
(a)                    each assignment or transfer under this paragraph (B) shall be arranged by Kosmos (with such reasonable assistance from the Existing Lender as Kosmos may reasonably request); and
 
(b)                   no Existing Lender shall be obliged to make any assignment or transfer pursuant to this paragraph (B) unless and until it has received payment from the Replacement Lender or Replacement Lenders in an aggregate amount equal to the outstanding principal amount of the participations in the Utilisations owing to the Existing Lender, together with accrued and unpaid interest and fees (including, without limitation, any Break Costs to the date of payment) and all other amounts payable to the Existing Lender under this Agreement.
 
(C)                 On receipt of a notice from Kosmos referred to in paragraph (A) above, the Commitment of that Lender shall immediately be reduced to zero.
 
(D)                On the last day of each Interest Period which ends after Kosmos has given notice under paragraph (A) above (or, if earlier, the date specified by Kosmos in that notice), Kosmos shall repay that Lender’s participation in the relevant Utilisation.
 
(E)                  Paragraphs (A) and (B) do not in any way limit the obligations of any Finance Party under clause 18.1 ( Mitigation ).
 
11.                 INTEREST
 
11.1          Calculation of interest
 
The rate of interest on each Loan for each Interest Period is the percentage rate per annum which is the aggregate of the applicable:
 
(A)               Margin;
 
(B)                 LIBOR; and
 
(C)                 Mandatory Cost (if any).
 
71

 
11.2          Margin
 
The Margin applicable to a Loan shall be a percentage per annum, based on utilisation of the Facility, as follows:
 
Years (counting	 	Utilisation of Facility	 	 	 	
from and including	 	is less than or equal	 	Utilisation of Facility is	 	
the year of the	 	to 75% of the Total	 	more than 75% of the Total	 	
Signing Date)	 	Facility Amount	 	Facility Amount	 	
1 to 3 (inclusive)	 	3.25	%	3.50	%	
4 to 5 (inclusive)	 	3.75	%	4.00	%	
6 to 7 (inclusive)	 	4.50	%	4.75	%	
 
11.3          Payment of interest
 
The Borrower shall pay accrued interest on each Loan on the last day of each Interest Period (and, if the Interest Period is longer than six months, on the dates falling at six-monthly intervals after the first day of the Interest Period).
 
11.4          Default interest
 
(A)               If an Obligor fails to pay any amount payable by it under a Finance Document on its due date, interest shall accrue on the overdue amount from the due date up to the date of actual payment (both before and after judgment) at a rate which, subject to paragraph (B) below, is 1.0 per cent. higher than the rate which would have been payable if the overdue amount had, during the period of non payment, constituted a Loan in the currency of the overdue amount for successive Interest Periods, each of a duration selected by the Facility Agent (acting reasonably). Any interest accruing under this clause shall be immediately payable by the Obligor on demand by that Facility Agent.
 
(B)                 If any overdue amount consists of all or part of a Loan which became due on a day which was not the last day of an Interest Period relating to that Loan:
 
(i)                       the first Interest Period for that overdue amount shall have a duration equal to the unexpired portion of the current Interest Period relating to that Loan; and
 
(ii)                    the rate of interest applying to the overdue amount during that first Interest Period shall be 1.0 per cent. higher than the rate which would have applied if the overdue amount had not become due.
 
(C)                 Default interest (if unpaid) arising on an overdue amount will be compounded with the overdue amount at the end of each Interest Period applicable to that overdue amount but will remain immediately due and payable.
 
72

 
11.5          Notification of rates of interest
 
The Facility Agent shall promptly notify the relevant Lenders and Kosmos of the determination of a rate of interest under this Agreement.
 
12.                 INTEREST PERIODS
 
12.1          Selection of Interest Periods
 
(A)               The Borrower shall select an Interest Period for a Loan in the Utilisation Request for that Loan.
 
(B)                 Subject to this clause, the Borrower may select an Interest Period of 1, 3 or 6 months or such other period as may be agreed between Kosmos and the Facility Agent.
 
(C)                 No Interest Period for a Loan under the Facility shall extend beyond the Final Maturity Date.
 
(D)                The first Interest Period of each Loan shall commence on the Utilisation Date and end on the same day as the end of the selected Interest Period. In the case of each Loan (other than the first Loan under the Facility), each subsequent Interest Period shall end on the same day as the current Interest Period of any outstanding Loan made under the Facility.
 
12.2          Non-Business Days
 
If an Interest Period ends on a day which is not a Business Day, that Interest Period will instead end on the next Business Day, unless the next Business Day is in another month, in which case the Interest Period will end on the preceding Business Day.
 
12.3          Consolidation and division of Loans
 
(A)               Subject to paragraph (B) below, if two or more Interest Periods for Loans under the Facility end on the same date, those Loans will, unless Kosmos specifies to the contrary in the Utilisation Request or in a notice to the Facility Agent, be consolidated into, and treated as, a single Loan under the Facility on the last day of the Interest Period.
 
(B)                 If Kosmos requests (in either a Utilisation Request or otherwise in a notice to the Facility Agent) that a Loan be divided into two or more Loans, that Loan will, on the last day of its Interest Period, be so divided into the amounts specified in such request, being an aggregate amount equal to the amount of the Loan immediately before its division.
 
73

 
13.                 CHANGES TO THE CALCULATION OF INTEREST
 
13.1          Absence of quotations
 
Subject to clause 13.2 (Market disruption), if LIBOR is to be determined by reference to the Reference Banks but up to four Reference Banks do not supply a quotation by the Specified Time, the applicable LIBOR shall be determined on the basis of the quotations of the remaining Reference Banks.
 
13.2          Market disruption
 
(A)               If a Market Disruption Event occurs in relation to a Loan for any Interest Period, then the rate of interest on each Lender’s share of that Loan for the Interest Period shall be the percentage rate per annum which is the sum of:
 
(i)                       the Margin;
 
(ii)                    the rate notified to the Facility Agent by that Lender as soon as practicable and in any event before interest is due to be paid in respect of that Interest Period, to be that which expresses as a percentage rate per annum the cost to that Lender of funding its participation in that Loan from whatever source it may reasonably select; and
 
(iii)                 the Mandatory Cost, if any, applicable to that Lender’s participation in the Loan.
 
(B)                 In this Agreement “Market Disruption Event” means if, on or about noon in London on the Quotation Day for the relevant Interest Period none or only one of the Reference Banks supplies a rate to the Facility Agent to determine LIBOR for the Interest Period, or the Facility Agent receives notifications from a Lender or Lenders (whose participations exceed 35 per cent. in aggregate of all participations) that the cost to it of obtaining matching deposits in the London interbank market would be materially in excess of LIBOR.
 
(C)                 The Facility Agent shall notify Kosmos immediately upon receiving notice from the Lender(s).
 
13.3          Alternative basis of interest or funding
 
(A)               If a Market Disruption Event occurs and the Facility Agent or the Borrower so requires, the Facility Agent and the Borrower shall enter into negotiations (for a period of not more than thirty days) with a view to agreeing a substitute basis for determining the rate of interest.
 
(B)                 Any alternative basis agreed pursuant to paragraph (A) above shall, with the prior consent of all the Lenders and Kosmos, be binding on all Parties.
 
74

 
13.4                       Break Costs
 
(A)                Kosmos shall, within three Business Days of demand by a Finance Party, pay to that Finance Party its Break Costs attributable to all or any part of a Loan or Unpaid Sum being paid by it on a day other than the last day of an Interest Period for that Loan or Unpaid Sum.
 
(B)                  Each Lender shall, as soon as reasonably practicable after a demand by the Facility Agent, provide a certificate confirming the amount of its Break Costs for any Interest Period in which they accrue.
 
(C)                  If, following a payment by Kosmos of all or part of a Loan or Unpaid Sum on a day other than the last day of an Interest Period for that Loan or Unpaid Sum, a Lender realises a profit, and no Event of Default is continuing, that Lender must pay an amount equal to that profit to Kosmos as soon as practicable.
 
14.                              FEES
 
14.1                       Commitment fee
 
(A)                The Borrower shall pay to the Facility Agent, a fee computed as follows:
 
(i)                     when Commitment is available for utilisation, at a rate equal to 40 per cent. per annum of the then applicable Margin; and
 
(ii)                  when Commitment is not then available for utilisation, at a rate equal to 20 per cent. per annum of the then applicable Margin.
 
(B)                 The accrued commitment fee is payable quarterly (on each of 31 March, 30 June, 30 September and 31 December) in arrears on any undrawn and uncancelled portion of the Commitments for the period from the date of this Agreement until and including the last day of the Availability Period.
 
(C)                 Notwithstanding paragraphs (A) and (B) above, the Borrower shall not be required to pay any such commitment fees to the Facility Agent for the account of any Lender during the period in which such Lender is a Non-Funding Lender.
 
14.2                       Front end and underwriting fees
 
The Borrower shall pay to each Original Lender, front end and underwriting fees in the amount and at the times agreed in a Fee Letter.
 
14.3                       Facility Agent fee
 
The Borrower shall pay to the Facility Agent (for its own account) an agency fee in the amount and at the times agreed in a Fee Letter.
 
75

 
14.4                       Security Agent fee
 
The Borrower shall pay to the Security Agent (for its own account) a trustee fee in the amount and at the times agreed in a Fee Letter.
 
14.5                       The Technical Bank fee
 
The Borrower shall pay to the lead technical bank and to each co-technical bank (for its own account in each case) a technical bank fee in the amount and at the times agreed in a Fee Letter.
 
14.6                       The Modelling Bank fee
 
The Borrower shall pay to the lead modelling bank and the co-modelling bank (for its own account in each case) a modelling bank fee in the amount and at the times agreed in a Fee Letter.
 
14.7                       The Documentation Bank fee
 
The Borrower shall pay to the Documentation Bank (for its own account) a documentation bank fee in the amount and at the times agreed in a Fee Letter.
 
76

 
PART 5
TAXES, INCREASED COSTS AND INDEMNITIES
 
15.                              TAX GROSS UP AND INDEMNITIES
 
15.1                       Definitions
 
In this Agreement:
 
“Tax Credit” means a credit against, relief or remission for, or repayment of any Tax.
 
“Tax Deduction” means a deduction or withholding for or on account of Tax from a payment under a Finance Document.
 
“Tax Payment” means either the increase in a payment made by an Obligor to a Finance Party under clause 15.2 ( Tax gross-up ) or a payment under clause 15.3 ( Tax Indemnity ).
 
15.2                       Tax gross-up
 
(A)               Each Obligor shall make all payments to be made by it without any Tax Deduction, unless a Tax Deduction is required by law.
 
(B)                 Kosmos shall promptly upon becoming aware that an Obligor must make a Tax Deduction (or that there is any change in the rate or the basis of a Tax Deduction) notify the Facility Agent accordingly.
 
(C)                 If a Tax Deduction is required by law to be made by an Obligor, the amount of the payment due from that Obligor shall be increased to an amount which (after making any Tax Deduction) leaves an amount equal to the payment which would have been due if no Tax Deduction had been required.
 
(D)                If an Obligor is required to make a Tax Deduction, that Obligor shall make that Tax Deduction and any payment required in connection with that Tax Deduction within the time allowed and in the minimum amount required by law.
 
(E)                  Within thirty days of making either a Tax Deduction or any payment required in connection with that Tax Deduction, the Obligor making that Tax Deduction shall deliver to the Facility Agent for the Finance Party entitled to the payment evidence reasonably satisfactory to that Finance Party (acting reasonably) that the Tax Deduction has been made or (as applicable) any appropriate payment paid to the relevant taxing Authority.
 
(F)                  If an Obligor makes any payment to a Finance Party in respect of or relating to a Tax Deduction, but such Obligor was not obliged to make such payment, the relevant Finance Party shall within five Business Days of demand refund such payment to such Obligor.
 
77

 
15.3                       Tax Indemnity
 
(A)                Except as provided below, the Borrower shall (within five Business Days of demand by the Facility Agent) indemnify a Finance Party against any loss, liability or cost which that Finance Party determines will be or has been (directly or indirectly) suffered by that Finance Party for or on account of Tax, by that Finance Party in respect of a Finance Document.
 
(B)                  Paragraph (A) above shall not apply:
 
(i)                      with respect to any Tax assessed on a Finance Party under the law of the jurisdiction in which:
 
(a)                   that Finance Party is incorporated or, if different, the jurisdiction (or jurisdictions) in which that Finance Party is treated as resident for tax purposes; or
 
(b)                  that Finance Party’s Facility Office is located in respect of amounts received or receivable in that jurisdiction,
 
if in either such case that Tax is imposed on or calculated by reference to the net income received or receivable (but not any sum deemed to be received or receivable) by that Finance Party or that Finance Party’s Facility Office; or
 
(ii)                  to the extent a loss, liability or cost is compensated for by an increased payment under clause 15.2 (Tax gross-up ); or
 
(iii)               with respect to any Tax assessed prior to the date which is 180 days prior to the date on which the relevant Finance Party requests such a payment from the Borrower, unless a determination of the amount claimed could only be made on or after the first of those dates.
 
(C)                  A Finance Party making, or intending to make a claim under paragraph (A) above shall promptly notify the Facility Agent of the event which will give, or has given, rise to the claim, following which the Facility Agent shall provide to Kosmos a copy of the notification by such Finance Party.
 
(D)                 A Finance Party shall, on receiving a payment from an Obligor under this clause, notify the Facility Agent. The Finance Parties will undertake to use reasonable endeavours to obtain reliefs and remissions for taxes and deductions and to reimburse Kosmos for reliefs, remissions or credits obtained (but without any obligation to arrange its tax affairs other than as it sees fit nor to disclose any information about its tax affairs).
 
15.4                       Tax Credit
 
(A)                If:-
 
(i)                      an Obligor makes a Tax Payment, and
 
78

 
(ii)                   a Tax Credit is attributable either to an increased payment of which that Tax Payment forms part, or to that Tax Payment, and
 
(iii)                that Finance Party has obtained, utilised and retained that Tax Credit,
 
the Finance Party shall pay an amount to the Obligor which that Finance Party reasonably determines will leave it (after that payment) in the same after-Tax position as it would have been in but for its utilisation of the Tax Credit.
 
(B)                  Nothing in this clause will:
 
(i)                      interfere with the rights of any Finance Party to arrange its affairs in whatever manner it thinks fit; or
 
(ii)                   oblige any Finance Party to disclose any information relating to its Tax affairs or computations.
 
15.5                       Stamp Taxes
 
Kosmos shall, within five Business Days of demand, pay and indemnify each Finance Party against any cost, loss or liability that Finance Party incurs in relation to all stamp duty, registration and other similar Taxes payable in respect of any Finance Document other than in respect of an assignment or transfer by a Lender or any breach by any Finance Party of the terms of clauses 28.27 ( Due execution of security Assignments ) and 28.29 ( Lenders’ custody of documents ).
 
15.6                       Value added tax
 
(A)               All consideration expressed to be payable under a Finance Document by any Party to a Finance Party shall be deemed to be exclusive of any VAT. If VAT is chargeable on any supply made by any Finance Party to any Party in connection with a Finance Document, that Party shall pay to the Finance Party (in addition to and at the same time as paying the consideration) an amount equal to the amount of the VAT against delivery of an appropriate VAT invoice.
 
(B)                 Where a Finance Document requires any Party to reimburse a Finance Party for any costs or expenses, that obligation shall be deemed to extend to all VAT incurred by the Finance Party in respect of the costs or expenses to the extent that the Finance Party reasonably determines that neither the Finance Party nor any other member of any VAT group of which it is a member is entitled to credit or repayment of the VAT.
 
16.                              INCREASED COSTS
 
16.1                       Increased costs
 
(A)               Subject to clause 16.3 (Exceptions) the Borrower shall, within five Business Days of a demand by the Facility Agent, pay for the account of a Finance Party the amount of any Increased Costs incurred by that Finance Party or any of its Affiliates as a result of the introduction of or any change in (or in the
 
79

 
interpretation, administration or application by any governmental body or regulatory Authority of) any law or regulation (whether or not having the force of law, but if not, being of a type with which that Finance Party or Affiliate is expected or required to comply), or as a result of the implementation or application of, or compliance with, Basel III or any law or regulation that implements or applies Basel III.
 
(B)                 In this Agreement “Increased Costs” means:
 
(i)                      a reduction in the rate of return from the Facility or on a Finance Party’s (or its Affiliate’s) overall capital;
 
(ii)                   an additional or increased cost; or
 
(iii)                a reduction of any amount due and payable under any Finance Document,
 
which is (a) material and (b) incurred or suffered by a Finance Party or any of its Affiliates but only to the extent that it is attributable to that Finance Party having entered into its Commitment or funding or performing its obligations under any Finance Document.
 
16.2                       Increased cost claims
 
(A)               A Finance Party intending to make a claim pursuant to clause 16.1 (Increased costs) shall notify the Facility Agent of the event giving rise to the claim, following which the Facility Agent shall promptly notify the company.
 
(B)                 Each Finance Party shall provide a certificate confirming the amount of its Increased Costs.
 
16.3                       Exceptions
 
(A)               clause 16.1 (Increased costs) does not apply to the extent any Increased Cost is:
 
(i)                     attributable to a Tax Deduction required by law to be made by an Obligor provided that this clause is without prejudice to any rights which the affected Lender may have under clause 15.2 ( Tax gross-up ) to receive a grossed up payment;
 
(ii)                 the subject of a claim under clause 15.3 (Tax Indemnity) (or might be or have been the subject of a claim under clause 15.3 ( Tax Indemnity ) but for any of the exclusions in paragraph (B) of clause 15.3 ( Tax Indemnity ));
 
(iii)              incurred prior to the date which is 180 days prior to the date on which the Finance Party makes a claim in accordance with clause 16.2 ( Increased cost claims ), unless a determination of the amount incurred could only be made on or after the first of those dates;
 
80

 
(iv)             any of the types of cost dealt with by Schedule 6 (Mandatory Cost Formulae);
 
(v)                attributable to the wilful breach by the relevant Finance Party or any of its Affiliates of any law or regulation; or
 
(vi)             attributable to the implementation or application of or compliance with the “International Convergence of Capital Measurement and Capital Standards, a Revised Framework” published by the Basel Committee on Banking Supervision in June 2004 in the form existing on the date of this Agreement (but excluding any amendment contained in Basel III) (“ Basel II ”) or any other law or regulation which implements Basel II (whether such implementation, application or compliance is by a government, regulator, Finance Party or any of its Affiliates).
 
(B)                  In this clause 16.3 (Exceptions), a reference to a “Tax Deduction” has the same meaning given to the term in clause 15.1 ( Definitions ).
 
17.                              OTHER INDEMNITIES
 
17.1                       Currency indemnity
 
(A)                If any sum due from an Obligor under the Finance Documents (a “Sum”), or any order, judgment or award given or made in relation to a Sum, has to be converted from the currency (the “ First Currency ”) in which that Sum is payable into another currency (the “ Second Currency ”) for the purpose of:
 
(i)                      making or filing a claim or proof against that Obligor; or
 
(ii)                   obtaining or enforcing an order, judgment or award in relation to any litigation or arbitration proceedings,
 
that Obligor shall as an independent obligation, within five Business Days of demand, indemnify each Finance Party to whom that Sum is due against any cost, loss or liability arising out of or as a result of the conversion including any discrepancy between (a) the rate of exchange used to convert that Sum from the First Currency into the Second Currency and (b) the rate or rates of exchange available to that person at the time of its receipt of that Sum.
 
(B)                 Each Obligor waives any right it may have in any jurisdiction to pay any amount under the Finance Documents in a currency or currency unit other than that in which it is expressed to be payable.
 
17.2                       Other indemnities
 
Each Obligor shall, within five Business Days of demand, indemnify each Finance Party against any cost, loss or liability incurred by that Finance Party as a result of:
 
(A)                the occurrence of any Event of Default;
 
81

 
(B)                  a failure by an Obligor to pay any amount due under a Finance Document on its due date;
 
(C)                 funding, or making arrangements to fund, its participation in a Utilisation requested by the Borrower in a Utilisation Request but not made by reason of a Default or an act or omission on the part of an Obligor; and
 
(D)                 a Utilisation (or part of a Utilisation) not being prepaid in accordance with a notice of prepayment given by Kosmos.
 
17.3                       Indemnity to the Facility Agent
 
Each Obligor shall promptly on demand, indemnify the Facility Agent against any cost, loss or liability incurred by the Facility Agent (acting reasonably) as a direct result of:
 
(A)                investigating any event which it reasonably believes is a Default; and
 
(B)                 acting or relying on any notice, request or instruction which it reasonably believes to be genuine, correct and appropriately authorised by an Obligor.
 
18.                              MITIGATION BY THE LENDERS
 
18.1                       Mitigation
 
(A)               Each Finance Party shall, in consultation with Kosmos, use all reasonable endeavours to mitigate or remove any circumstances which arise and which would result in any facility ceasing to be available or any amount becoming payable under or pursuant to, or cancelled pursuant to, any of clause 10.2 ( Illegality ), clause 15.2 ( Tax gross-up ), clause 16.1 ( Increased costs ) or clause 13.2 ( Market disruption ) including (but not limited to) transferring its rights and obligations under the Finance Documents to another Affiliate or Facility Office.
 
(B)                 Paragraph (A) above does not in any way limit the obligations of any Obligor under the Finance Documents.
 
(C)                 Each Finance Party shall notify the Facility Agent as soon as it becomes aware that any circumstances of the kind described in paragraph (A) above have arisen or may arise. The Facility Agent shall notify Kosmos promptly of any such notification from a Finance Party.
 
18.2                       Limitation of liability
 
(A)               Each Obligor shall promptly indemnify each Finance Party for all costs and expenses reasonably incurred by that Finance Party as a result of steps taken by it under clause 18.1 ( Mitigation ).
 
(B)                 A Finance Party is not obliged to take any steps under clause 18.1 (Mitigation) if, in the bona fide opinion of that Finance Party (acting reasonably), to do so might in any way be prejudicial to it.
 
82

 
PART 6
FORECASTS AND CALCULATIONS AND BORROWING BASE AMOUNT
 
19.                              FORECASTS AND CALCULATIONS
 
19.1                       Forecast Procedures
 
(A)                Not less than 30 Business Days before any proposed or required Forecast Date, the Borrower and the Technical and Modelling Bank shall consult together with a view to preparing and agreeing the relevant Forecast including the Forecast Assumptions and all associated calculations and information. Kosmos shall ensure that a new or updated reserves report is prepared by the Reserves Consultant for the Forecast prepared for 15 June 2011 and for each Forecast prepared on subsequent Forecast Dates falling at twelve monthly intervals (or such earlier dates as Kosmos may elect). Each party shall consult in good faith and act reasonably, and shall make available sufficiently experienced personnel, with a view to reaching agreement as soon as reasonably practicable. Each Forecast (and all Forecast Assumptions used) shall have due and proper regard to any reasonable view expressed by any of the Consultants in a report delivered for the purpose of preparing the Forecast, any plan of development, work program and budget and the provisions and requirements of the Project Agreements (and any updates thereto). Any product pricing proposal by the Technical and Modelling Bank shall be reasonable in the circumstances and shall be made in accordance with current business practices, applied on a consistent, reasonable and non-discriminatory basis and reflecting market practice at the time.
 
(B)                 The Borrower shall provide its proposed Forecast to each Lender 15 Business Days before the relevant Forecast Date and the Technical and Modelling Bank shall provide its commentary on such Forecast, including whether it agrees or disagrees with such Forecast (including, if applicable, details of the grounds for its determination not to agree with the Forecast). Each Lender shall have 10 Business Days to approve the Forecast and, once approved by the Majority Lenders, that Forecast will apply for the relevant Forecast Period. If any such Lender has not objected in writing to the Forecast within such 10 Business Day period, then such Lender shall be deemed to have approved the Forecast. A Forecast shall only be deemed to have been accepted by such Lenders if it has been approved (or deemed approved) by the Majority Lenders. In making any objection, such Lenders must act reasonably and no objection may be made other than on the grounds that a Forecast Assumption which has been used in the Forecast is not reasonable in the circumstances, or on the grounds of proven or manifest error.
 
(C)                 In making any determination in the Forecasting Procedures the Majority Lenders shall give due and proper regard to any information provided (including any report delivered by the Consultants for the purposes of the Forecast) or representations made by the Borrower and the Technical and Modelling Bank. Any determination shall take due and proper regard of any plan of development, work program and budget (and any updates thereto) and the provisions and requirements of the Project Agreements. Any determination in relation to
 
83

 
product prices shall be reasonable in the circumstances and shall be made in accordance with current business practices, applied on a consistent, reasonable and non-discriminatory basis and reflecting market practice at the time.
 
(D)                If the Majority Lenders do not approve the Forecast, the Borrower and the Technical and Modelling Bank shall prepare a revised Forecast which satisfies, in all reasonable respects, the objections of the Majority Lenders.
 
(E)                  If, for any reason, a Forecast is not agreed prior to the applicable Forecast Date, the then applicable Forecast shall continue to apply until the new Forecast is prepared and agreed in accordance with the Forecast Procedures.
 
19.2                       Contents of Forecast
 
(A)                Each Forecast will set out or include:
 
(i)                      the Technical Assumptions and Economic Assumptions upon which the Forecast is based (including, without limitation, on product prices);
 
(ii)                   an updated Model;
 
(iii)                the calculation of the Borrowing Base Amount;
 
(iv)               the calculation of any mandatory prepayment required because the aggregate of outstandings under the Facility exceeds the Borrowing Base Amount;
 
(v)                  calculations of the Field Life Cover Ratio and the Loan Life Cover Ratio;
 
(vi)               the calculation of the Reserve Tail Date;
 
(vii)           the aggregate economically recoverable proved (1P) reserves and the proved and probable (2P) reserves remaining to be produced from the Borrowing Base Assets (reflecting any updated reserves report produced by the Reserves Consultant in respect of that Forecast, or if no such updated reserves report has been produced, reflecting the immediately preceding reserves report as may be updated by Kosmos with the agreement of the Technical Consultant and the Technical and Modelling Bank (acting reasonably);
 
(viii)        the revised Amortisation Schedule (if required) or confirmation that no revision to the Amortisation Schedule is required pursuant to clause 9.2 ( Amendment to Amortisation Schedule ); and
 
(ix)                such other reasonable information as the Technical and Modelling Bank or the Facility Agent may reasonably require.
 
(B)                 All projections and calculations to be made under this clause shall be expressed and made in US Dollars (at the Facility Agent’s spot rate of exchange at the time if so required (which the Facility Agent will provide promptly on request)).
 
84

 
19.3          New Borrowing Base Assets
 
Whenever a new asset becomes, or is to become, a Borrowing Base Asset, a new Forecast must first be prepared and provided to each Lender, in accordance with this clause 19 ( Forecasts and Calculations ), together with a Sources and Uses Statement, including that asset.
 
19.4          Manner of Calculations
 
(A)               All the calculations required for each Forecast will be calculated using the Model on the basis of the Technical Assumptions and Economic Assumptions determined for the purposes of that Forecast.
 
(B)                 Where the manner of determining any of the calculations required for a Forecast differs between the programme on which the Model operates and the provisions of the Finance Documents, the Finance Documents will prevail.
 
19.5          Borrowing Base Amount
 
The Borrowing Base Amount shall be determined on each Forecast Date pursuant to a Forecast prepared in accordance with the Forecasting Procedures. The Borrowing Base Amount so determined shall apply for the duration of the next succeeding Forecast Period or until a new Forecast is prepared.
 
19.6          Calculation of Borrowing Base Amount
 
(A)               The Borrowing Base Amount for the purposes of the Facility shall be the lesser of:
 
(i)                       the sum of: (a) the net present value of Net Cash Flow until the Field Depletion Date plus (b) the net present value of Relevant Capital Expenditure, divided by 1.5;
 
(ii)                    the sum of: (a) the net present value of Net Cash Flow until the Final Maturity Date plus (b) the net present value of Relevant Capital Expenditure, divided by 1.3.
 
(B)                 The discount rate utilised to determine the net present values referred to in paragraph (A) above shall be eight per cent. and shall be applied in calculating the net present value of cash flows.
 
19.7          Model
 
(A)               The Facility Agent, the Technical and Modelling Bank and Kosmos may each make proposals with regard to amendments to the Model which it believes:
 
(i)                       in good faith are required for the purpose of correcting any manifest error in the form or structure of the Model; or
 
(ii)                    to incorporate additional assumptions.
 
85

 
(B)                 If the Facility Agent, Technical and Modelling Bank and Kosmos are unable to agree on the required changes to the Model within 15 Business Days from the date on which such changes were proposed, then the matter shall, on the request of Kosmos or the Technical and Modelling Bank, or on the initiation of the Facility Agent, be referred for resolution to an appropriate expert appointed by the Facility Agent (being a person having appropriate independent expertise with respect to, but no interest in, the outcome of the matter referred to it).
 
(C)                 The costs of any references to an expert and the costs, if any, incurred in giving effect to any agreed revision to the Model will be borne by Kosmos except, in the case of the costs of any reference to an expert only, if the expert determines that any proposal by the Technical and Modelling Bank or the Facility Agent in respect of the changes to the Model which are in dispute could not be regarded as reasonable and are rejected by such expert, in which case such costs shall be borne by the Lenders.
 
(D)                Any amendments to the Model will not be made until such time as such amendment has been agreed or determined (as appropriate) pursuant to paragraphs (A) and (B) above. Prior to such amendment being incorporated into the Model, the Model will continue to be utilised without such amendment.
 
(E)                  Where the manner of determining any of the calculations required for a Forecast is amended as a consequence of any amendments made to the Model, the Finance Documents shall be deemed to be amended to reflect any such amendment.
 
19.8          Approved Developments and Permitted Acquisitions
 
Prior to requesting the consent of the Majority Lenders to the carrying out of any Approved Development (or the inclusion of any Field or Petroleum Asset (or any part thereof) in the Borrowing Base Assets as an Approved Development) or to the making of any Permitted Acquisition, the Technical and Modelling Bank and the Borrower shall consult in good faith, and acting reasonably, they shall prepare a proposal for the consideration of each Lender which includes all relevant information for the Lenders to make an informed decision on whether to grant the requisite consent (including appropriate reports from the Technical Consultant, the Environmental Consultant, the Reserves Consultant and the Insurance Consultant). Any Approved Development or Permitted Acquisition must be compliant with the Equator Principles (as confirmed by the Environmental Consultant). The Technical and Modelling Bank shall include its recommendation with the proposal on whether consent should be given. In considering whether to grant any such consent, the Lenders shall act reasonably and shall take due and proper regard of any recommendation of the Technical and Modelling Bank (but without any liability on the part of the Technical and Modelling Bank and each Lender being deemed to make its own independent assessment) and the information provided with the proposal. If the Majority Lenders refuse their consent, they shall provide the Borrower with reasonable details of the reasons why they have refused their consent. A Permitted Acquisition may not take place in Iran, Libya, Myanmar, North Korea, Sudan, Syria, Cuba, any country which is on a sanctions list issued by the United States, the European Union (or any member state) or the United Nations or any country designated by the Majority Lenders (acting reasonably).
 
86

 
PART 7
BANKS ACCOUNTS, CASH MANAGEMENT AND RESERVE EQUITY
 
20.                 BANK ACCOUNTS AND CASH MANAGEMENT
 
20.1          Project Accounts
 
(A)               Each Obligor shall establish and maintain each of the Project Accounts, as required under the terms of this Agreement, with the Account Bank in London or such other jurisdiction approved by the Facility Agent (acting reasonably).
 
(B)                 The Project Accounts (other than the Ghana Working Capital Cedi Account which shall be denominated in Ghanaian Cedi) shall be denominated in US Dollars. Any sum constituting interest paid in respect of the credit balance on any Project Account shall be treated in the same manner as any other sum credited to a Project Account.
 
(C)                 Each Project Account will be a separate account at the Account Bank. The Project Accounts will be maintained until the Discharge Date.
 
(D)                Amounts may be deposited into the Onshore Working Capital Accounts, to the extent necessary, to meet local onshore payments only, provided that the aggregate balance in such accounts may not exceed USD 10 million (or equivalent) or such higher amount agreed by the Facility Agent (acting reasonably).
 
(E)                  Subject to paragraph (D) above and to the order of payments provided for in the Cash Waterfall, Kosmos shall maintain the balance of the Offshore Proceeds Accounts and the Onshore Working Capital Accounts, which, when aggregated and taken together with amounts paid in advance for its liabilities under the Project Agreements, is prudent and reasonable.
 
20.2          Other bank accounts
 
(A)               Each Obligor shall not open or maintain any bank accounts other than:
 
(i)                       the Project Accounts (including such other accounts established by KEG with the Account Bank which would be Project Accounts but for the execution of the Onshore Security Assignment and the Offshore Security Assignment by all the parties thereto in accordance with this Agreement), which shall not be overdrawn at any time and any withdrawals from such Project Accounts shall only be made out of cleared funds;
 
(ii)                    the Distributions Reserve Accounts, which shall not be overdrawn at any time; and
 
(iii)                 such accounts as may be necessary or appropriate for it to perform its obligations as an operator in relation to the Ghana Blocks and, except into which moneys received from, or for the account of, any other party
 
87

 
may be paid as required (but any money being related to any carried interest (including in respect of the carried interest of EO) in relation to any Borrowing Base Asset shall be paid into an Offshore Proceeds Account) (an “ Interested Third Party ”),
 
provided that in no event shall such accounts referred to in (ii) and (iii) above, or any moneys standing to the credit of such accounts referred to in (ii) and (iii) above, be available to the Lenders (except on an unsecured basis following the occurrence of any of the events described in clause 29.6 ( Insolvency ) and/or clause 29.7 ( Insolvency proceedings )) or subject to any restrictions under the Finance Documents and shall not be subject to any Security Interest in favour of any Finance Party (but may be secured in favour of any other person other than the Finance Parties).
 
(B)                 The Lenders will account to KEH and/or the relevant Obligor if and to the extent they receive any proceeds from any account referred to in clause 20.2(A)(ii) or (A)(iii) above, and shall hold any such moneys to the account of, and on trust for, KEH.
 
(C)                 Any Lender that is in receipt of proceeds as described in paragraph (B) above shall:
 
(i)                       within five Business Days notify details of the receipt or recovery to Kosmos, KEH and the Facility Agent; and
 
(ii)                    within five Business Days of demand by KEH, pay an amount equal to such receipt or recovery to KEH.
 
20.3          Appointment of Account Bank
 
(A)               Any appointment of or change to the Account Bank will become effective only upon the Account Bank executing, or new Account Bank acceding to the terms of, the Project Accounts Agreements or such other terms as may be approved by Kosmos and the Facility Agent (acting reasonably).
 
(B)                 Kosmos may, with the consent of the Facility Agent (not to be unreasonably withheld or delayed), change the Account Bank to another bank which meets the requirements of paragraph (C) below, but subject to paragraph (A) above and clause 20.1 ( Project Accounts ). If the Account Bank resigns, then Kosmos will appoint a replacement Account Bank which meets the requirements of paragraph (C), but subject to paragraph (A) and clause 20.1 ( Project Accounts ).
 
(C)                 Each Account Bank shall be a bank whose long-term unguaranteed, unsecured securities or debt has a rating of A- or higher from Standard and Poor’s or A3 or higher from Moody’s (or equivalent) or such lower rating as the Facility Agent and Kosmos shall agree in writing.
 
88

 
20.4          Security Documents and Project Accounts Agreements
 
(A)               The Project Accounts shall be subject to a first ranking Security Interest in favour of the Secured Parties. Kosmos shall forthwith upon any change to the Account Bank, or upon opening any Project Account which is not subject to the security constituted by the relevant Security Documents, execute and deliver to the Security Agent such supplemental Security Documents as the Security Agent and the Facility Agent may reasonably require in order to create a first priority Security Interest over that Project Account in favour of the Finance Parties. Such supplemental Security Documents must be in a form and in substance satisfactory to the Facility Agent and the Security Agent.
 
(B)                 Kosmos shall, before any Project Account is opened, procure that the Obligor and the Account Bank have entered into the Project Accounts Agreements.
 
(C)                 In the case of execution of any of the Security Documents and Project Accounts Agreements referred to in paragraphs (A) and (B) above, Kosmos shall deliver to the Facility Agent documents which are the equivalent of those referred to in paragraph 1 of Schedule 3 ( Conditions Precedent ) in respect of such Security Documents and Project Accounts Agreements, together with any legal opinions which the Facility Agent may reasonably require, such legal opinions to be provided at the reasonable expense of Kosmos. All such documents must be in a form and in substance satisfactory to the Facility Agent.
 
(D)                The detailed operating procedures for the Project Accounts will be agreed between Kosmos and the Account Bank, but in the event of any inconsistency between those procedures and the Project Accounts Agreements or this Agreement, the provisions of this Agreement shall prevail.
 
20.5          Control on withdrawals following Default
 
If a Default has occurred and is continuing and has not been waived, no Obligor may withdraw any moneys from the Project Accounts except:
 
(A)               with the prior consent of the Facility Agent;
 
(B)                 to meet an Obligor’s payment obligations under the Finance Documents or the Project Agreements on the relevant due date; or
 
(C)                 to pay for Project Costs not included in paragraph (B) above where:
 
(i)                       the payment in question has been budgeted for and the Facility Agent have given their written consent to the relevant expenditure or cost being incurred; or
 
(ii)                    the failure to make the payment in question would materially and adversely affect the business or financial condition of Kosmos or any other Obligor.
 
89

 
20.6          Distributions Reserve Account
 
(A)               Each Obligor may maintain a Distributions Reserve Account into which the amount of any permitted distribution under clause 28.23 ( Distributions ), permitted indebtedness (other than drawdowns under the Facility) and contributions to the capital of an Obligor may be credited subject to compliance with the Cash Waterfall and such amounts shall not be subordinated to the rights of the Lenders. Amounts standing to the credit of the Distributions Reserve Accounts shall not be available to the Finance Parties whether as secured or unsecured creditors of Kosmos and irrespective of whether an Event of Default has occurred. The Obligors may grant security over their Distributions Reserve Account in favour of any person and shall not be required to grant any Security Interest over the Distributions Reserve Account in favour of the Finance Parties. Sums standing to the credit of the Distributions Reserve Accounts may be withdrawn and applied as the Obligor sees fit.
 
(B)                 The Lenders will account to KEH and/or the relevant Obligor if and to the extent they receive any proceeds from a Distributions Reserve Account, and shall hold any such moneys to the account of, and on trust for, KEH. If any other person has a Security Interest or claim against amounts standing to the credit of a Distributions Reserve Account, any such interest or claim shall be limited to these amounts and they shall not have recourse to the assets of any Obligor generally, nor shall they be entitled to make any claim or enforce against, or initiate any Insolvency Proceedings of any kind, against any Obligor.
 
(C)                 Any Lender that is in receipt of proceeds as described in paragraph (B) above, shall turnover such proceeds to KEH in accordance with paragraph (C) of clause 20.2 ( Other bank accounts ) above.
 
21.                 OPERATION OF THE OFFSHORE PROCEEDS ACCOUNTS
 
21.1          Payments in
 
Unless a Finance Document expressly requires an amount to be paid into any other Project Account, each Obligor must ensure that:
 
(A)               all Gross Revenues received;
 
(B)                 the proceeds of any Loan;
 
(C)                 the proceeds of repayment of any loan made pursuant to any FPSO Construction Financing;
 
(D)                the proceeds of any Permitted Disposals; and
 
(E)                  any other amount payable to, or received by an Obligor (including payments received under any offtake contract (and the Obligors shall direct any person making such payments that any such payment shall be paid into that account only)), but excluding any amount which may be credited to the Distribution Reserve Account of Kosmos,
 
90

 
are paid directly into an Offshore Proceeds Account.
 
21.2          Withdrawals — No Default Outstanding
 
(A)               Unless otherwise provided and unless there is a Default outstanding, amounts may only be withdrawn from the Offshore Proceeds Accounts and the Onshore Working Capital Accounts (including by way of transfer to any other account) if they are applied for the following purposes and subject to the following priority:
 
(i)                       first, payment of Project Costs provided that, if the latest Sources And Uses Statement shows that there is a shortfall in funding projected to be available, then such available funding must, unless the Majority Lenders otherwise agree, be allocated to meet costs in the following order of priority:
 
(a)                   Borrowing Base Assets;
 
(b)                  Ghana Block Assets;
 
(c)                   the Cameroon Block Assets and the Morocco Block Assets; and
 
(d)                  any other Project Costs.
 
In the event that there is any projected shortfall in funding, then the Facility may not be used for a purpose set out above unless each of the other purposes higher in the order of priority is fully funded by committed and available funding for the then applicable Forecast Period (including amounts under the Facility and assuming that there is no Default or Event of Default under the Finance Documents).
 
(ii)                    secondly, pari passu, payment of (or the funding of an Obligor, including by way of payment under any Intercompany Loan Agreement, to enable it to pay) any Financing Costs (excluding any payments of principal) under the Facility due but unpaid (applied to overdue amounts first, unpaid fees second, and unpaid interest third) or scheduled payments due but unpaid under a Hedging Agreement;
 
(iii)                 thirdly, pari passu, payments of (or the funding of an Obligor, including by way of payment under any Intercompany Loan Agreement to enable it to pay) principal under the Facility due but unpaid (applied to overdue amounts first and then to unpaid principal payments) and payment of (or the funding of the Borrower, including by way of payment under any Intercompany Loan Agreement to enable it to pay) any liabilities, including any early termination payment, due but unpaid under a Hedging Agreement;
 
(iv)                fourthly, payment of any mandatory prepayments required because the outstandings under the Facility exceed the Borrowing Base Amount as determined by the most recent Forecast;
 
91

 
(v)                   fifthly, payments required to be made into the DSRA up to the Required Balance;
 
(vi)                sixthly, prepayments under the Finance Documents and/or providing cash collateral under any Letter of Credit; and
 
(vii)             lastly, so long as the Dividend Release Test is met, to make distributions to its shareholders at the Borrower’s discretion, which shall include making payments to the Distribution Reserve Account and payments under any Intercompany Loan Agreement provided that the amount distributed shall be based on the aggregate amount standing to the credit of the Offshore Proceeds Accounts on the relevant payment date after the amounts in (i) to (vi) above have been deducted.
 
22.                 DEBT SERVICE RESERVE ACCOUNT
 
22.1          Funding of Debt Service Reserve Account
 
(A)               Kosmos shall ensure on an ongoing basis that deposits are made into the Debt Service Reserve Account in accordance with the Cash Waterfall until the balance of such account is not less than the Required Balance. The funding of the Debt Service Reserve Account shall continue in accordance with the Cash Waterfall until the Discharge Date.
 
(B)                 Failure to maintain the Required Balance standing to the credit of the Debt Service Reserve Account shall not constitute an Event of Default for the purposes of clause 29 ( Events of Default ), but failure to apply amounts from the Project Accounts during the relevant Forecast Period in accordance with the Cash Waterfall shall constitute an Event of Default for the purposes of clause 29 ( Events of Default ).
 
(C)                 Notwithstanding the provisions of paragraphs (A) and (B) above, Kosmos may (without being restricted by the Cash Waterfall) make a Utilisation under the Facility to fund the Debt Service Reserve Account.
 
22.2          Withdrawals from Debt Service Reserve Account
 
(A)               Subject to paragraph (B) below, amounts standing to the credit of the DSRA may be withdrawn only to pay any Financing Costs under the Facility in accordance with the Cash Waterfall.
 
(B)                 In addition, withdrawals may be made from the Debt Service Reserve Account to the extent the amount withdrawn is equal to or less than the amount (if any) by which the amount standing to the credit of the Debt Service Reserve Account exceeds the applicable Required Balance at that time. Any such withdrawal may be applied in accordance with, and for the purposes set out in, the Cash Waterfall.
 
92

 
23.                 AUTHORISED INVESTMENTS
 
23.1          Power of investment
 
Subject always to clause 20.1 (Project Accounts), Kosmos may require that such part of the amounts standing to the credit of any of the Project Accounts as it may consider prudent (having reasonable grounds for so considering) shall be invested from time to time in Authorised Investments in accordance with this clause and in a manner consistent with the provisions of clause 28.17(A) ( Hedging) .
 
23.2          Type of investment
 
(A)               Kosmos shall use its reasonable endeavours to procure that there are maintained from time to time a prudent spread of Authorised Investments and that the maturity of Authorised Investments is such that they can be liquidated to enable all payment obligations under the Finance Documents to be met on the due date.
 
(B)                 If any Authorised Investment ceases to be an Authorised Investment, Kosmos will, as soon as reasonably practicable upon becoming aware of this, procure that the relevant investment is replaced by an Authorised Investment or cash, provided that if it does not propose liquidating the relevant investment earlier than its maturity, it shall notify the Facility Agent that such investment is no longer an Authorised Investment promptly upon becoming aware of this and, subject to it having provided such notice, it will not be obliged to liquidate such investment before its maturity date unless either of the Facility Agent, acting reasonably, requests it to do so.
 
23.3          Realisations
 
(A)               Upon the realisation (whether by way of disposal, maturity or otherwise) of any Authorised Investment, the net proceeds of realisation shall either immediately be credited directly to the Project Account from which the Authorised Investment or such investment was made, or (unless a Default has occurred and is continuing) immediately be invested in another Authorised Investment, whichever Kosmos directs.
 
(B)                 Upon the receipt of any interest, dividends or other income from or in respect of any Authorised Investment, such interest, dividends or other income shall be credited to the Project Account concerned with the Authorised Investment or such other investment from which such interest, dividend or other income derives, or (if such interest, dividend or other income is derived from an Authorised Investment and such Authorised Investment is to be retained after such interest, dividend or other income is received and Kosmos so requests) the relevant interest, dividend or other income shall be reinvested in that Authorised Investment.
 
93

 
23.4          Project Accounts include Authorised Investments
 
(A)               Any reference in this Agreement to the balance standing to the credit of one of the Project Accounts shall be deemed to include a reference to the Authorised Investments in which all or part of such balance is for the time being invested. (other than for the purposes of determining the balance required to comply with clause 20.1 ( Project Accounts )). In the event of any dispute as to the value of any Authorised Investment for the purpose of determining the amount deemed to be standing to the credit of a Project Account, that value shall be determined by the Facility Agent acting reasonably and in good faith and following consultation with Kosmos and having given due consideration to any representations given by Kosmos within the period required by the Facility Agent (which period shall not, in any event, be of shorter duration than five Business Days). If Kosmos so requests, the Facility Agent will give Kosmos details of the basis or method of its determination.
 
(B)                 Kosmos may, by notice in writing to the Facility Agent and the Account Bank, deem an Authorised Investment to be concerned with a different Project Account so as to transfer Authorised Investments between Project Accounts, if:
 
(i)                       the aggregate amount standing to the credit of each Project Account remains the same; or
 
(ii)                    the transfer of an equivalent amount between those Project Accounts would be permitted.
 
23.5          Security over Authorised Investments
 
Prior to the Borrower making any Authorised Investment in England, the Borrower shall ensure that it has entered into the Offshore Security Assignment. To the extent that any Authorised Investment is made in a jurisdiction other than England, the Borrower shall execute and deliver, such other security as the Facility Agent may reasonably require from time to time in order to ensure that such Authorised Investment is secured to the Finance Parties by way of first priority security, in a form and substance satisfactory to the Facility Agent and the Security Agent, acting reasonably.
 
23.6          Interest on balances in Project Accounts
 
Each sum credited to a Project Account from time to time shall, from the time it is so credited until the time it is withdrawn therefrom (whether for the purpose of making an Authorised Investment or otherwise for application in accordance with the terms of this Agreement), bear interest at such rate as Kosmos may from time to time agree with the relevant Account Bank.
 
94

 
PART 8
FINANCIAL AND PROJECT INFORMATION
 
24.                 INFORMATION UNDERTAKINGS
 
The undertakings in this clause remain in force from the date of this Agreement until the Discharge Date.
 
24.1          Books of account and auditors
 
Each Obligor shall:
 
(A)               keep proper books of account relating to its business; and
 
(B)                 appoint and maintain as its auditors any Approved Auditor.
 
24.2          Financial statements
 
(A)               Before (but for the avoidance of doubt not after) KEL or any of its Subsidiaries from time to time undertakes an IPO, the Borrower shall procure that KEH shall supply to the Facility Agent (in sufficient copies as most recently notified by the Facility Agent as being sufficient to allow one copy for each Lender):
 
(i)                       as soon as they become available, but in any event within 180 days of the end of each financial year, its audited consolidated financial statements for that financial year;
 
(ii)                    within 90 days of the end of each semi-annual period, its unaudited semi-annual consolidated financial statements for that period; and
 
(iii)                 within 90 days of the end of each quarter, its quarterly management reports for that period.
 
(B)                 After (but for the avoidance of doubt not before) KEL or any of its Subsidiaries from time to time undertakes an IPO, the Borrower shall procure that KEL shall supply to the Facility Agent (in sufficient copies as most recently notified by the Facility Agent as being sufficient to allow one copy for each Lender):
 
(i)                       as soon as they become available, but in any event within 180 days of the end of each financial year, its audited consolidated financial statements for that financial year;
 
(ii)                    within 90 days of the end of each semi-annual period, its unaudited semi-annual consolidated financial statements for that period; and
 
(iii)                 within 90 days of the end of each quarter, its quarterly management reports for that period.
 
(C)                 KEO shall supply to the Facility Agent (in sufficient copies as most recently notified by the Facility Agent as being sufficient to allow one copy for each
 
95

 
Lender) within 90 days of the end of each quarter, its quarterly management reports for that period.
 
(D)                If any audited consolidated financial statements which have been provided to the Facility Agent pursuant to either Clause (A)(i) or (B)(i) above contain an auditors’ qualification then, in each case if instructed to do so by the Facility Agent (acting only on the instructions of the Majority Lenders):
 
(i)                       KEO shall supply to the Facility Agent (in sufficient copies as most recently notified by the Facility Agent as being sufficient to allow one copy for each Lender), as soon as practicable, but in any event within 120 days of being so requested, its audited financial statements for its last financial year; and
 
(ii)                    the Borrower shall supply to the Facility Agent (in sufficient copies as most recently notified by the Facility Agent as being sufficient to allow one copy for each Lender), as soon as practicable, but in any event within 120 days of being so requested, its audited financial statements for its last financial year.
 
(E)                  If during any financial year of the Borrower there is a material change in the nature and extent of the accounting transactions which the Borrower enters into, it shall promptly inform the Facility Agent thereof and the Borrower shall, if instructed to do so by the Facility Agent (acting on the instructions of the Majority Lenders (acting reasonably)), supply to the Facility Agent (in sufficient copies for each Lender), as soon as they become available, but in any event within 180 days of request, its audited consolidated financial statements for its last financial year.
 
24.3          Year-end
 
Neither KEO nor the Borrower shall change its Accounting Reference Date without the consent of the Majority Lenders.
 
24.4          Form of financial statements
 
(A)               KEO and the Borrower must ensure that each set of financial statements supplied under the Facility Agreement:
 
(i)                       is certified by an Authorised Signatory of the relevant company as a true and correct copy; and
 
(ii)                    gives (if audited) a true and fair view of, or (if unaudited) fairly represents, the financial condition of the relevant company for the period to the date on which those financial statements were drawn up.
 
(B)                 Unless otherwise agreed with the Facility Agent, all accounts of KEH, KEL, KEO and the Borrower delivered under the Facility Agreement shall be prepared in accordance with the Approved Accounting Principles.
 
96

 
(C)                 KEO and the Borrower must notify the Facility Agent of any material change to the manner in which any audited financial statements delivered under the Facility Agreement are prepared.
 
(D)                If requested by the Facility Agent, each of KEH, KEL, KEO and the Borrower must supply to the Facility Agent:
 
(i)                       a full description of any change notified under paragraph (B) above and the adjustments which would be required to be made to those financial statements in order to cause them to use the accounting policies, practices, procedures and reference period upon which such financial statements were prepared prior to such change; and
 
(ii)                    sufficient information, in such detail and format as may be required by the Facility Agent (acting reasonably), to enable the Lenders to make a proper comparison between the financial position shown by the set of financial statements prepared on the changed basis and its most recent audited financial statements delivered to the Facility Agent under the Facility Agreement prior to such change.
 
24.5          Compliance Certificate
 
(A)               KEO and the Borrower must supply (and, in the case of the Borrower, procure that KEH and KEL supply) to the Facility Agent a compliance certificate with each set of financial statements sent to the Facility Agent under Clauses 24.4(A), 24.4(B), 24.4(C), 24.4(D) above certifying the matters specified in clause 24.4(A)(ii) above.
 
(B)                 A compliance certificate supplied in accordance with (A) above must be signed by two Authorised Signatories of KEH, KEL, KEO or the Borrower, as applicable.
 
24.6          Project Information
 
(A)               Each Obligor must (as soon as reasonably practicable) supply to the Facility Agent, in sufficient copies for all the Lenders if the Facility Agent so requests:
 
(i)                       any new updates to each and amendments to each agreed budget, or development and/or work programme in relation to each Borrowing Base Asset owned by it as soon as reasonably practicable following receipt from the relevant Operator (and, in any event, within 21 days of receipt) and, at least semi-annually, the latest Operator Report for each Borrowing Base Asset and each Developing Asset owned by it (as soon as reasonably practicable and, in any event, within 21 days of the end of the semi-annual period when it must be provided);
 
(ii)                    copies of all reports provided to any Government Authority by the Operator which have been copied to Kosmos (and in any event within 21 days of receipt);
 
97

 
(iii)    such technical and commercial information which Kosmos has in its possession relating to a Field or Petroleum Assets or its or their condition and which is relevant to the interests of the Lenders under the Finance Documents as the Facility Agent may reasonably request from time to time (following prior consultation with Kosmos); and
 
(iv)    promptly, details of any material updates or amendments to any Project Agreement.
 
(B)                 The terms of appointment of the Technical Consultant shall require it (in consultation with the Technical and Modelling Bank) to prepare and deliver the following reports and information to the Technical and Modelling Bank and Kosmos for distribution to the Lenders:
 
(i)       a quarterly report on the Project Costs which have been incurred, reconciled against draw-downs made, equity contributed and cash held in the Project Accounts;
 
(ii)      a semi-annual report on the progress of each Developing Asset, including confirmation of the projected date for Completion and the aggregate of Project Costs required to achieve Completion (reconciled against the most recent Forecast) and whether there are, in its opinion, any other material issues or concerns of which it is aware in relation to the Developing Asset which should be brought to the attention of the Lenders;
 
(iii)    a semi-annual report on the operation of each Developed Asset, including the amount and timing of all Entitlement lifted by the Obligors and details of the disposal of that Entitlement (including price); and
 
(iv)    in any of the foregoing reports, such additional information or commentary as the Technical and Modelling Bank may reasonably require (following prior consultation with Kosmos) in order for the Lenders (in the context of their interests under the Finance Documents) to be properly informed about the progress, implementation, development and operation of the Borrowing Base Assets,
 
and the Borrower shall provide the Technical Consultant and the Technical and Modelling Bank with reasonable assistance and provide each of them with such information and other documents as the Technical Consultant and/or the Technical and Modelling Bank may reasonably request in order for the Technical Consultant to prepare and deliver the reports and information referred to in (i) to (iv) above and/or the Technical and Modelling Bank to consider and review such reports and information. Such assistance shall include facilitating visits by the Technical Consultant and the Technical and Modelling Bank to the Borrowing Base Assets and the construction/fabrication facilities of any Obligor’s contractors.
 
98

 
24.7          Information: Miscellaneous
 
Each Obligor shall supply to the Facility Agent, in sufficient copies for all the Lenders, if the Facility Agent so requests:
 
(A)               all documents dispatched by each Obligor to its Shareholders (or any class of them) or its creditors generally, at the same time as they are dispatched;
 
(B)                 promptly after becoming aware of them, the details of any material litigation, arbitration or administrative proceedings which are currently threatened or pending against the Guarantor or any member of the Group or in respect of or relevant to an interest in a Borrowing Base Asset or any Ghana Block Assets;
 
(C)                 promptly after they have been issued, copies of any insurance policies in respect of all Agreed Insurances and any renewals in respect of such insurance policies;
 
(D)                promptly after becoming aware of them, details of any claims made under any Insurance where the claim is for a sum in excess of USD 5 million; and
 
(E)                  promptly, such further information regarding the financial condition, assets, business and operations of the Guarantor or any member of the Group as the Facility Agent may reasonably request.
 
24.8          Sources and Uses
 
(A)               Kosmos must supply to the Facility Agent on each Forecast Date (in sufficient copies for all the Lenders if the Facility Agent so requests), a sources and uses statement (“ Sources and Uses Statement ”) showing, for the following twelve month period:
 
(i)                       the Project Costs projected to be incurred; and
 
(ii)                    the sources of funds to be used to cover such Project Costs.
 
(B)                 In the event that the Project Costs specified under any Sources and Uses Statement delivered to the Facility Agent under paragraph (A)(i) above exceed the funding which is projected to be available to meet those Project Costs, then the Borrower shall consult with the Facility Agent and the Technical and Modelling Bank in good faith with a view to agreeing a plan pursuant to which the Borrower will be able to meet any projected shortfall in funding.
 
(C)                 Notwithstanding paragraph (B) above, within 30 days of the relevant Forecast Date, the Borrower shall deliver to the Facility Agent the Borrower’s remedial plan for the funding of any projected shortfall in funding and the Borrower shall use all reasonable endeavours to comply with such plan (or any update thereto which it delivers to the Facility Agent), and shall consult on a regular basis with the Facility Agent and the Technical and Modelling Bank on the remedial steps being taken to fund any projected shortfall in funding.
 
99

 
(D)                A Default or an Event of Default will not occur under any circumstances if a Sources and Uses Statement shows a shortfall in funding.
 
24.9          Approved Development
 
Kosmos must supply to the Facility Agent (in sufficient copies for all the Lenders if the Facility Agent so requests) quarterly (and monthly, but only to the extent available) project reports in respect of an Approved Development.
 
24.10   Compliance with Remedial Plan
 
The Borrower shall use all reasonable endeavours to implement the remedial plan (or amended plan provided to the Facility Agent) and shall continue to consult on a regular basis with (and when requested by) the Facility Agent and the Technical Bank on implementation of the plan.
 
24.11   Notification of Default
 
Each Obligor must notify the Facility Agent of any Default (and the steps, if any, being taken to remedy it) and any material default under or material breach of any Project Agreement promptly upon becoming aware of its occurrence.
 
24.12   “Know your customer” and “customer due diligence” requirements
 
(A)               If:
 
(i)      the introduction of or any change in (or in the interpretation, administration or application by any government or regulatory Authority of) any law or regulation (having the force of law) made after the date of the Facility Agreement;
 
(ii)     any change in the ownership of an Obligor after the date of the Facility Agreement; or
 
(iii)    a proposed assignment or transfer by a Lender of any of its rights and obligations under the Facility Agreement to a party that is not a Lender prior to such assignment or transfer,
 
obliges the Facility Agent or any Lender (or, in the case of paragraph (C) below, any prospective new Lender) to comply with “know your customer”, “customer due diligence” or similar identification procedures in circumstances where the necessary information is not already available to it (or, in the case of paragraph (C) below, cannot be provided by the transferring Lender from information already provided to it), Kosmos shall, as soon as reasonably practicable upon the request of the Facility Agent or the relevant Lender, supply, or procure the supply of, such reasonable documentation and other evidence as is within an Obligor’s possession and control to enable the Facility Agent or such Lender to comply with all necessary “know your customer”, “customer due diligence” or other similar checks required under the relevant laws and regulations.
 
100

 
(B)                 Each Lender shall promptly upon the request of the Facility Agent supply, or procure the supply of, such documentation and other evidence as is reasonably requested by the Facility Agent (for itself) in order for the Facility Agent, as the case may be, to carry out and be satisfied it has complied with all necessary “know your customer” or other similar checks under all applicable laws and regulations pursuant to the transactions contemplated in the Finance Documents.
 
(C)                 The Borrower shall, by not less than 10 Business Days’ prior written notice to the Facility Agent, notify the Facility Agent (which shall promptly notify the Lenders) of its intention to request that one of the subsidiaries (other than a subsidiary of a Borrower which owns Borrowing Base Assets) becomes an Additional Guarantor pursuant to the Facility Agreement.
 
(D)                Following the giving of any notice pursuant to paragraph (C) above, if the accession of such Additional Guarantor obliges the Facility Agent or any Lender to comply with “know your customer” or similar identification procedures in circumstances where the necessary information is not already available to it, the Borrower shall promptly upon the request of the Facility Agent or any Lender supply, or procure the supply of, such documentation and other evidence as is reasonably requested by the Facility Agent (for itself or on behalf of any Lender) or any Lender (for itself or on behalf of any prospective new Lender) in order for the Facility Agent or such Lender or any prospective new Lender to carry out and be satisfied it has complied with all necessary “know your customer” or other similar checks under all applicable laws and regulations pursuant to the accession of such subsidiary to the Facility Agreement as an Additional Guarantor.
 
24.13   Use of websites
 
(A)               Except as provided below, each Obligor may deliver any information under the Facility Agreement to the Facility Agent by posting it on to an electronic website if:
 
(i)                       it maintains or has access to an electronic website for this purpose and provides the Facility Agent with the details and password to access the website and the information; and
 
(ii)                    the information posted is in a format required by the Facility Agreement or is otherwise agreed between each Obligor and the Facility Agent (whose approval shall not be unreasonably withheld or delayed).
 
The Facility Agent must supply each relevant Lender with the address of and password for the website.
 
(B)                 Notwithstanding the above, Kosmos must supply to the Facility Agent in paper form a copy of any information posted on the website together with sufficient copies for:
 
101

 
(i)      any Lender who notifies the Facility Agent in writing (copied to each Obligor) that it does not wish to receive information via the website; and
 
(ii)     within ten Business Days of request, any other Lender, if that Lender so requests.
 
(C)                 Each Obligor must promptly upon becoming aware of its occurrence, notify the Facility Agent if:
 
(i)      the website cannot be accessed;
 
(ii)     the website or any information on the website is infected by any electronic virus or similar software;
 
(iii)    the password for the website is changed; or
 
(iv)    any information to be supplied under the Facility Agreement is posted on the website or amended after being posted.
 
(D)                If the circumstances in sub-paragraph (C)(i) or (ii) above occur, an Obligor must supply any information required under the Facility Agreement in paper form until the circumstances giving rise to the notification are no longer continuing and the information can be provided in accordance with paragraph (A) above.
 
102

 
PART 9
GUARANTEE
 
25.                 GUARANTEE AND INDEMNITY
 
25.1          Guarantee and indemnity
 
Each Guarantor irrevocably and unconditionally jointly and severally:
 
(A)               guarantees to each Finance Party punctual performance by each Borrower of all that Borrower’s obligations under the Finance Documents;
 
(B)                 undertakes with each Finance Party that whenever a Borrower does not pay any amount when due under or in connection with any Finance Document, that Guarantor shall immediately on demand pay that amount as if it was the principal obligor; and
 
(C)                 indemnifies each Finance Party immediately on demand against any cost, loss or liability suffered by that Finance Party if any obligation guaranteed by it is or becomes unenforceable, invalid or illegal. The amount of the cost, loss or liability shall be equal to the amount which that Finance Party would otherwise have been entitled to recover.
 
25.2          Continuing guarantee
 
This guarantee is a continuing guarantee and will extend to the ultimate balance of sums payable by any Obligor under the Finance Documents, regardless of any intermediate payment or discharge in whole or in part.
 
25.3          Reinstatement
 
If any payment by an Obligor or any discharge given by a Finance Party (whether in respect of the obligations of any Obligor or any security for those obligations or otherwise) is avoided or reduced as a result of insolvency or any similar event:
 
(A)               the liability of each Obligor shall continue as if the payment, discharge, avoidance or reduction had not occurred; and
 
(B)                 each Finance Party shall be entitled to recover the value or amount of that security or payment from each Obligor, as if the payment, discharge, avoidance or reduction had not occurred.
 
25.4          Waiver of defences
 
The obligations of each Guarantor under this clause 25 will not be affected by an act, omission, matter or thing which, but for this clause, would reduce, release or prejudice any of its obligations under this clause 25 (without limitation and whether or not known to it or any Finance Party) including:
 
103

 
(A)               any time, waiver or consent granted to, or composition with, any Obligor or other person;
 
(B)                 the release of any other Obligor or any other person under the terms of any composition or arrangement with any creditor of any member of the Group;
 
(C)                 the taking, variation, compromise, exchange, renewal or release of, or refusal or neglect to perfect, take up or enforce, any rights against, or security over assets of, any Obligor or other person or any non-presentation or non-observance of any formality or other requirement in respect of any instrument or any failure to realise the full value of any security;
 
(D)                any incapacity or lack of power, authority or legal personality or dissolution or change in the members or status of an Obligor or any other person;
 
(E)                  any amendment, novation, supplement, extension, restatement (however fundamental and whether or not more onerous) or replacement of any Finance Document or any other document or security including without limitation any change in the purpose of, any extension of or any increase in any facility or the addition of any new facility under any Finance Document or other document or security;
 
(F)                  any unenforceability, illegality or invalidity of any obligation of any person under any Finance Document or any other document or security; or
 
(G)                 any insolvency or similar proceedings.
 
25.5          Immediate recourse
 
Each Guarantor waives any right it may have of first requiring any Finance Party (or any trustee or agent on its behalf) to proceed against or enforce any other rights or security or claim payment from any person before claiming from that Guarantor under this clause 25. This waiver applies irrespective of any law or any provision of a Finance Document to the contrary.
 
25.6          Appropriations
 
Until all amounts which may be or become payable by the Obligors under or in connection with the Finance Documents have been irrevocably paid in full, each Finance Party (or any trustee or agent on its behalf) may:
 
(A)               refrain from applying or enforcing any other moneys, security or rights held or received by that Finance Party (or any trustee or agent on its behalf) in respect of those amounts, or apply and enforce the same in such manner and order as it sees fit (whether against those amounts or otherwise) and no Guarantor shall be entitled to the benefit of the same; and
 
(B)                 hold in an interest-bearing suspense account any moneys received from any Guarantor or on account of any Guarantor’s liability under this clause 25.
 
104

 
25.7   Deferral of Guarantors’ rights
 
(A)    Until all amounts which may be or become payable by the Obligors under or in connection with the Finance Documents have been irrevocably paid in full and unless the Facility Agent otherwise directs, no Guarantor will exercise any rights which it may have by reason of performance by it of its obligations under the Finance Documents:
 
(i)       to be indemnified by an Obligor;
 
(ii)      to claim any contribution from any other guarantor of any Obligor’s obligations under the Finance Documents; and/or
 
(iii)     to take the benefit (in whole or in part and whether by way of subrogation or otherwise) of any rights of the Finance Parties under the Finance Documents or of any other guarantee or security taken pursuant to, or in connection with, the Finance Documents by any Finance Party.
 
(B)     If a Guarantor receives any benefit, payment or distribution in relation to such rights it shall hold that benefit, payment or distribution to the extent necessary to enable all amounts which may be or become payable to the Finance Parties by the Obligors under or in connection with the Finance Documents to be repaid in full on trust for the Finance Parties and shall promptly pay or transfer the same to the Agent or as the Agent may direct for application in accordance with clause 34 ( Payment Mechanics ) of this Agreement.
 
25.8   Release of Guarantors’ right of contribution
 
If any Guarantor ceases to be a Guarantor (a “Retiring Guarantor”) in accordance with the terms of the Finance Documents for the purpose of any sale or other disposal of that Retiring Guarantor then on the date such Retiring Guarantor ceases to be a Guarantor:
 
(A)    that Retiring Guarantor is released by each other Guarantor from any liability (whether past, present or future and whether actual or contingent) to make a contribution to any other Guarantor arising by reason of the performance by any other Guarantor of its obligations under the Finance Documents; and
 
(B)     each other Guarantor waives any rights it may have by reason of the performance of its obligations under the Finance Documents to take the benefit (in whole or in part and whether by way of subrogation or otherwise) of any rights of the Finance Parties under any Finance Document or of any other security taken pursuant to, or in connection with, any Finance Document where such rights or security are granted by or in relation to the assets of the Retiring Guarantor.
 
25.9   Additional security
 
This guarantee is in addition to and is not in any way prejudiced by any other guarantee or security now or subsequently held by any Finance Party.
 
105

 
PART 10
REPRESENTATIONS, COVENANTS, EVENTS OF DEFAULT
 
26.     REPRESENTATIONS
 
Each Obligor makes the representations and warranties set out in this clause to each Finance Party and acknowledges that each Finance Party has entered into the Finance Documents in full reliance on those representations and warranties.
 
26.1   Status
 
(A)    It is a limited liability company, duly incorporated and validly existing under the laws of its jurisdiction of incorporation.
 
(B)     It has the power to own its assets and carry on its business as it is being conducted.
 
26.2   Legal validity
 
Each Transaction Document to which it is a party constitutes, or will constitute when executed, its valid, legally binding and enforceable obligations in accordance with its terms (subject to any limitation on enforcement under law or general principles of equity or qualifications which are specifically set out in any legal opinion delivered as a Condition Precedent) and that, so far as it is aware having made all due and careful enquiries, each Transaction Document is in full force and effect.
 
26.3   Non-conflict
 
The entry into and performance by it of, and the transactions contemplated by, the Transaction Documents to which it is a party do not conflict with:
 
(A)    any applicable law or regulation;
 
(B)     its constitutional documents; or
 
(C)     any agreement binding upon it,
 
to the extent which has, or could reasonably be expected to have, a Material Adverse Effect.
 
26.4   Powers and authority
 
It has (or had at the relevant time) the power and authority to execute and deliver the Transaction Documents to which it is a party and it has the power and authority to perform its obligations under the Transaction Documents to which it is a party and the transactions contemplated thereby.
 
106

 
26.5   Authorisations
 
Except for the registration of any Security Document, all Required Approvals (except to the extent already provided as a Condition Precedent, or where required by any Authority in respect of any Security Interest granted (or to be granted) under the Security Documents) have been obtained or effected and are in full force and effect (where a failure to do so has or could reasonably be expected to have a Material Adverse Effect).
 
26.6   Stamp and registration duties
 
Except for registration fees, if any, payable in relation to the Security Documents, there is no stamp or registration duty or similar Tax or charge in respect of any Transaction Document, which has not been made or paid within applicable time periods (where a failure to do so has, or could reasonably be expected to have, a Material Adverse Effect).
 
26.7   No Default
 
No Default has occurred and is outstanding.
 
26.8   Final Information Memorandum
 
(A)    The factual information in the Final Information Memorandum (other than that referred to in paragraph (B) below) was true in all material respects on the date of the Final Information Memorandum and did not omit anything material which was known to Kosmos at the time or contain anything that was materially misleading and, except to the extent advised in writing to the Facility Agent by Kosmos on or prior to Financial Close, so far as Kosmos is aware having made due and careful enquiry, no information has been disclosed to it nor have circumstances arisen nor has any event occurred since the date of the Final Information Memorandum which renders the information contained in the Final Information Memorandum materially misleading or materially incorrect.
 
(B)     The statements of opinion, projections and forecasts in the Final Information Memorandum attributable to Kosmos were made in good faith, with due care and on what Kosmos believed to be reasonable assumptions at the relevant time and representing the views of Kosmos at the time.
 
26.9   Financial Statements and other factual information
 
(A)    The most recent audited financial statements and interim financial statements delivered to the Facility Agent in accordance with clause 24.2 ( Financial statements ) (which, at the Signing Date, is the unaudited opening balance sheet of the Borrower as at 18 March 2011):
 
(i)       have been prepared in accordance with the Approved Accounting Principles (if relevant); and
 
107

 
(ii)     (if audited) give a true and fair view of, or (if unaudited) fairly represent, its financial condition for the relevant period.
 
(B)     All factual information provided by or under the express direction of KEO and the Borrower to the Finance Parties in connection with the Facility was believed by KEO and the Borrower at the time it was so provided to be true in all material respects.
 
26.10Proceedings pending or threatened
 
Except as disclosed to the Facility Agent in writing prior to the Signing Date, no litigation, arbitration or administrative proceeding is pending or threatened which could reasonably be expected to be adversely determined against it and which, if so determined, has, or could reasonably be expected to have, a Material Adverse Effect.
 
26.11Breach of laws
 
(A)    It has not breached any law or regulation which has, or could reasonably be expected to have, a Material Adverse Effect.
 
(B)     It is in compliance with all environmental laws, a breach of which could reasonably be expected to give rise to a liability on it which has, or could reasonably be expected to have, a Material Adverse Effect and, so far as it is aware having made due and careful enquiry, there is no environmental claim outstanding against it which, if adversely determined, would give rise to a liability on it which has, or could reasonably be expected to have, a Material Adverse Effect.
 
26.12Ranking of security
 
Subject to any limitations on enforcement under law or general principles of equity or qualifications set out in any legal opinion delivered as a Condition Precedent, each Security Document when executed confers the Security Interests it purports to confer over the assets referred to in that Security Document and those assets are not subject to any other Security Interest that is not permitted pursuant to clause 28.6 ( Negative pledge ).
 
26.13Pari passu ranking
 
Its payment obligations under the Finance Documents rank at least pari passu with all its other present unsecured obligations, except for obligations mandatorily preferred by law applying to companies generally.
 
26.14Assets
 
KEG holds the legal and beneficial interest in a 30.875 per cent Participating Interest in the WCTP Block; and the legal and beneficial interest in an 18 per cent Participating Interest in the DWT Block. Kosmos Energy Cameroon HC holds the legal and beneficial interest in a 35 per cent Participating Interest in the Kombe-N’sepe Permit, Cameroon; and, the legal and beneficial interest in a 100 per cent Participating Interest
 
108

 
in the Ndian River, Cameroon. Kosmos Energy Offshore Morocco HC holds the legal and beneficial interest in a 75 per cent Participating Interest in Boujdour Offshore Permits.
 
26.15Project Agreements
 
As at the Signing Date or, if later, the date a Project Agreement is delivered to the Facility Agent, so far as it is aware having made all due and careful enquiries:
 
(A)    each copy of a Project Agreement delivered to the Facility Agent under the Facility Agreement is true and complete;
 
(B)     there is no other agreement in connection with, or arrangements which amend, supplement or affect any Project Agreement in any material respect; and
 
(C)     no Obligor has a material obligation (being an obligation or liability exceeding USD 50 million) under any agreement which is not a Project Agreement, a Finance Document, or a Material Contract.
 
26.16No Immunity
 
In any proceedings taken in any relevant jurisdiction in relation to the Transaction Documents (or any of them), it shall not be entitled to claim for itself or any of its assets immunity from suit, execution or attachment or other legal process.
 
26.17Ownership of Obligors
 
(A)    KEH beneficially owns, indirectly, all of the issued share capital of the Guarantors and the Borrower.
 
(B)     The issued share capital of the Guarantors and the Borrower is fully paid up and, to the extent beneficially owned by KEH, free of all encumbrances or other third party rights (other than pursuant to the Security Documents).
 
26.18ORGL LC
 
The amount of USD 23,000,000 is outstanding under the ORGC LC as at the date of this Agreement.
 
26.19Times for making representations
 
(A)    The representations set out in this clause 26.18 (other than the representations in clauses 26.8 (Final Information Memorandum ), 26.4 ( Powers and authority ), 26.5 ( Authorisations ) and 26.15(B) ( Project Agreements )) are made by each Obligor on the date of this Agreement. The representation in clause 26.8 ( Final Information Memorandum ) will be made on the date of the Final Information Memorandum and the representation in clause 26.4 ( Powers and authority ) will be made as at the time that the power or authority is exercised only. Each Repeating Representation is deemed to be repeated by each Obligor on the
 
109

 
date of each Utilisation Request, each Utilisation Date and on the first day of each Interest Period.
 
(B)     When a representation is repeated, it is applied to the facts and circumstances existing at the time of repetition.
 
27.     FINANCIAL COVENANTS
 
27.1   Financial Covenants
 
(A)    On any Forecast Date, Kosmos shall ensure that:
 
(i)       the Field Life Cover Ratio shall not be less than 1.30; and
 
(ii)      the Loan Life Cover Ratio shall not be less than 1.10,
 
in each case, as calculated by the Technical and Modelling Bank (acting reasonably) on the basis of all information made available to it.
 
(B)     No later than three Business Days following each Forecast Date, Kosmos shall send to the Facility Agent, a certificate signed by two authorised representatives setting out its calculation of the financial ratios referred to in this clause 27 as at such date.
 
28.     GENERAL UNDERTAKINGS
 
The undertakings in this clause shall remain in force from the date of this Agreement until the Discharge Date.
 
28.1   Corporate existence
 
Each Obligor shall maintain its corporate existence.
 
28.2   Authorisations
 
Each Obligor shall promptly obtain and comply with Required Approvals where a failure to do so would have a Material Adverse Effect.
 
28.3   Compliance with laws
 
Each Obligor shall comply with all laws and regulations (including compliance with environmental laws, permits and licences and compliance with the Equator Principles) applicable to it where failure to do so would have a Material Adverse Effect.
 
28.4   Pari passu ranking
 
Each Obligor shall ensure that at all times its payment obligations to the Finance Parties under the Finance Documents rank at least  pari passu  as to priority of payment with all its other present and future unsecured and unsubordinated Financial Indebtedness, except for claims mandatorily preferred by operation of law applying generally.
 
110

 
28.5   Security
 
Subject to clause 28.27 (Due execution of security assignments) and clause 28.30 (Security Documents: consents, ranking and perfection ), each Obligor shall undertake all actions reasonably necessary (including the making or delivery of filings and payment of fees) to maintain the Security Interests under the Security Documents to which it is a party in full force and effect (including the priority thereof).
 
28.6   Negative pledge
 
Other than Permitted Security, an Obligor shall not create or permit to exist any Security Interest over any of its assets.
 
28.7   Conduct of other business
 
Kosmos shall not conduct any business other than activities in connection with, or related, ancillary or incidental to, its interest in the Borrowing Base Assets.
 
28.8   Disposals
 
(A)    Other than Permitted Disposals, an Obligor shall not, either in a single transaction or in a series of transactions and whether related or not, dispose of all or a material part of its assets.
 
(B)     If an Obligor wishes to make a Permitted Disposal of an asset which is subject to a Security Interest in favour of the Finance Parties, then the Finance Parties shall, promptly upon request from Kosmos, absolutely and unconditionally release and discharge the relevant asset from that Security Interest and shall do all things necessary at the cost and expense of Kosmos to effect such discharge.
 
(C)     The shares in the capital of KEO or the Borrower may at any time be transferred to another holding company in which event the existing security over such shares shall be released subject to such new holding company providing substitute security over all shares in the capital of KEO or the Borrower, as the case may be, on substantially the same terms and conditions.
 
28.9   Financial Indebtedness
 
Other than Permitted Financial Indebtedness, an Obligor shall not incur any Financial Indebtedness.
 
28.10Material contracts
 
No Obligor will enter into any contract or agreement that imposes material obligations on it except:-
 
(A)    contracts or agreements entered into in the ordinary course of business and on arm’s length terms (including in relation to Approved Developments and Permitted Acquisitions);
 
111

 
(B)     the Project Agreements and the EO Participation Agreement and contracts and agreements required or contemplated therein or in respect of the development and implementation of Kosmos’s interest in the Fields and the Ghana Blocks;
 
(C)     contracts or agreements otherwise permitted or contemplated by the Finance Documents;
 
(D)     where the obligations and liabilities of the Obligor thereunder are fully funded by Permitted Financial Indebtedness or equity contributions; or
 
(E)     with the approval of the Majority Lenders (acting reasonably).
 
28.11Upstream guarantees
 
No Obligor may, without the approval of the Majority Lenders (acting reasonably), enter into upstream guarantees or indemnities in respect of obligations or liabilities of any other member of the Group (excluding Obligors).
 
28.12Mergers
 
No Obligor may enter into any amalgamation, consolidation, demerger, merger or reconstruction or winding-up without the consent of the Majority Lenders, except on a solvent basis and in circumstances where the Obligor remains the legal entity following such amalgamation, consolidation, demerger, merger or reconstruction or winding-up.
 
28.13Loans
 
(A)    Except as provided in (B) below, no Obligor may be a creditor in respect of any Financial Indebtedness.
 
(B)     Paragraph (A) does not apply to:
 
(i)       any loans made pursuant to an Intercompany Loan Agreement;
 
(ii)      any credit provided under a Project Agreement, the EO Participation Agreement or in relation to the FPSO located in the Jubilee Field;
 
(iii)     any trade credit in the ordinary course of day to day business;
 
(iv)     loans or other credit not exceeding USD 100 million in aggregate at any one time; or
 
(v)      any other credit approved by the Majority Lenders (acting reasonably).
 
28.14Operation
 
As far as it is able to do so by exercising its rights under a Project Agreement to which it is a party, each Obligor will use its reasonable endeavours to procure that the Borrowing Base Assets are developed, operated and maintained in all material respects in
 
112

 
accordance with the terms of that Project Agreement and applicable law and in accordance with good international oil industry practice.
 
28.15Compliance with Project Agreements
 
(A)    Each Obligor must comply with its obligations under the Project Agreements to which it is a party where failure to do so would have a Material Adverse Effect.
 
(B)     In the event an Obligor fails to pay any sum due under any Project Agreement it shall take such steps as shall be reasonably available to it so as to permit such payment to be made on its behalf by any Finance Party or any person acting on behalf of any Finance Party.
 
28.16Insurances
 
Each Obligor will maintain all Agreed Insurances which it maintains in its own name, promptly pay all premiums and other monies payable under all its Agreed Insurances and promptly on request produce to the Security Agent a copy of each policy and evidence (reasonably acceptable to the Security Agent) of payment of such sums (and allow the Lenders to implement such insurance at the cost of the Borrower and the event of any default in that regard) and exercise its rights under the Project Agreements to procure (as far as it is able) the maintenance of the Agreed Insurances.
 
28.17Hedging
 
(A)    The Borrower will maintain in place at all times a prudent risk management policy relating to managing its exposure to interest rates and fluctuations in the price of Crude Oil. In relation to hedging which is implemented to manage exposure to fluctuations in the price of Crude Oil, the volume which may be hedged by instruments creating contingent liabilities will be capped at 75 per cent. of 2P Developed Assets which are producing. To the extent that this 75 per cent. cap is exceeded at any time, the Borrower and the Hedging Counterparties shall, for so long as such excess subsists, negotiate in good faith with a view to agreeing a way forward which rectifies such excess.
 
(B)     The Borrower will have the right to implement any hedging by either (i) entering into Hedging Agreements with one or more Hedging Counterparties; and/or (ii) entering into Derivative Agreements with counterparties who do not accede to the terms of the Intercreditor Agreement and where the relevant payments thereunder are a Project Cost.
 
(C)     Each Underwriter will have a right to bid for its pro rata share of any hedging proposed by an Obligor.
 
28.18Borrowing Base Assets
 
Each Borrowing Base Asset will at all times be owned by a member of the Group.
 
113

 
28.19Project Agreements
 
(A)    No Obligor will agree to any amendment, waiver or termination of a Project Agreement which would have a Material Adverse Effect or approve or vote in favour of any work programme, budget or development plan which would commit an Obligor to expenditure which it would not be able to meet from funds available to it, after taking account of forecast Project Costs and Financing Costs.
 
(B)     No term or condition of any Finance Document shall prevent any Obligor from complying with its express obligations under any Project Agreement, or require an Obligor to act or omit to act in a manner which would or might reasonably be expected to result in a breach of any provision of a Project Agreement including, but without limitation, Kosmos’ obligations under the EO Participation Agreement.
 
(C)     In the event that an Obligor has an obligation under a Project Agreement to make a payment in respect of a Project Cost because of the default by another party in paying its share of the relevant Project Cost, then the Obligor shall promptly notify the Facility Agent of the additional payment obligation (including reasonable details of how it arose and any steps being taken by the parties in relation to the relevant default and such other additional information as the Facility Agent may reasonably request). In such an event, the Facility Agent will have the right (acting reasonably) to request a sources and uses test to be performed.
 
28.20Eligible offtakers
 
Kosmos will enter into agreements for the sale of its Entitlement with offtakers whom Kosmos determines, acting reasonably and in accordance with a prudent marketing policy which it shall have in place from time to time, have the financial capability and technical capacity to perform their obligations in accordance with the relevant terms and taking account of the nature and size of the transaction. Financial capability may be measured by applying suitable ratings tests, through credit support structures (including specific payment terms, guarantees, security and letters of credit), the identity of the offtaker (such as their market experience and reputation and whether they are part of a larger corporate group), course of dealings, or such other reasonable criteria as Kosmos may apply from time to time. In assessing technical capacity, Kosmos shall have regard to the experience of the offtaker, whether the offtaker is sufficiently well equipped technically and managerially to perform its obligations, and the availability of third party services and support.
 
28.21Tax affairs
 
Each Obligor must promptly file all tax returns required by law within the requisite time limits except to the extent contested in good faith and subject to adequate reserve or provision.
 
114

 
28.22   Permitted Acquisitions
 
No Obligor may, without the prior written consent of the Facility Agent (acting on the instructions of the Majority Lenders (acting reasonably)), make any acquisition of, or investment in, any assets, rights or property (but excluding for the avoidance of doubt any payment of Financing Costs or Project Costs) which is not a Permitted Acquisition.
 
28.23   Distributions
 
(A)               Each Obligor may make, declare or pay a distribution (including any payment under any subordinated loan agreement falling within the terms of sub-paragraph (C) of the definition of Permitted Financial Indebtedness and including any funding pursuant to, or payment under, any Intercompany Loan Agreement) (a “ Shareholder Distribution ”), subject to:
 
(i)                       there is no Default or Event of Default outstanding and no Default or Event of Default would be caused by such Shareholder Distribution;
 
(ii)                    the latest Sources and Uses Statement not indicating a projected shortage in funding to meet projected Project Costs;
 
(iii)                 no Shareholder Distribution being permitted during a BBA Cure Period; and
 
(iv)                such Shareholder Distribution being made, declared, or paid in compliance with the Cash Waterfall.
 
(B)                 Any distribution permitted to be paid hereunder may be paid directly to the recipient or deposited into the Distributions Reserve Account, in accordance with the terms of the Facility Agreement.
 
28.24   Constitutional documents
 
Each Obligor will not agree to any amendment to any of its constitutional documents in a manner that could adversely affect the interests of the Finance Parties.
 
28.25   Further assurance
 
Subject to clause 28.27 (Due execution of security assignments) and clause 28.30 (Security Documents: consents, ranking and perfection ) each of the Obligors shall, at its own expense, promptly do all things, take all such action and execute all such other documents and instruments as may be requested by the Facility Agent from time to time and to the extent they are reasonably required or necessary for the purpose of giving effect to the provisions of the Finance Documents and the Project Agreements and for the purpose of perfecting and protecting the Lenders’ rights with respect to the Security Interests which are required to be created or perfected by the Finance Documents when required thereunder.
 
115

 
28.26   Delivery of certain documents
 
The Borrower shall use its reasonable endeavours to procure the delivery of the final report from the Technical Consultant to the Facility Agent in form and substance satisfactory to it no later than 15 Business Days from the date of this Agreement.
 
28.27   Due execution of security Assignments
 
(A)               The Security Agent shall have safe custody and control of the Assignments (which term shall, for the avoidance of doubt for the purposes of this clause 28.27 ( Due execution of security assignments ), be deemed not to include the Assignment of Reinsurance Rights until its execution by KEG and the relevant insurers, it being agreed that Kosmos shall take all such steps as may be reasonable (taking into account all of the circumstances at the time and the steps taken previously by Kosmos) to procure its execution by KEG and the relevant insurers). The Security Agent shall execute and date such documents for and on behalf of the Finance Parties in any of the following circumstances:
 
(i)                       if a Default has occurred and is continuing and the Majority Senior Lenders have instructed the Security Agent to execute and date the Assignments for and on behalf of the Finance Parties; or
 
(ii)                    if instructed to do so at any time by the Borrower.
 
(B)                 Each party to this Agreement irrevocably authorises the Security Agent to execute the Assignments for and on behalf of the Finance Parties and to date the Assignments when it is required to do so under paragraph (A) above. The Assignments shall be of no force or effect until they are duly executed by the Security Agent and dated for and on behalf of the Finance Parties in accordance with this clause 28.27 ( Due execution of security assignments ).
 
(C)                 In the event that the Security Agent signs and dates the Assignments in accordance with this clause 28.27 (Due execution of security assignments ), then the Borrower shall (and the Facility Agent may) without the requirement for any further authorisation from any Obligor make a Utilisation under the Facility to meet the payment of any stamp duty which is payable as a consequence of the Assignments being signed and dated. The Borrower shall (and the Facility Agent shall if it effects the Utilisation under the Facility) apply the relevant funds promptly in payment of the relevant stamp duty and shall ensure that the Assignments are stamped and registered as soon as practicable (and in any event within any time period required by law). The Borrower (or the Facility Agent, as the case may be) shall in each case notify the Security Agent and each Finance Party upon making the payment of any stamp duty and the stamping and registration of the Assignments.
 
28.28   Stamp duty and other impost waiver
 
The Borrower shall use its reasonable endeavours to seek a waiver or exemption from any stamp duty, documentary taxes or any other similar tax, charge or impost which may be payable upon the execution of any of the Assignments, or to obtain confirmation
 
116

 
that no such duty, taxes, charges or impost would be payable upon execution. In the event that such waiver, exemption or confirmation is successfully obtained in relation to any Assignment, the Borrower shall promptly instruct the Security Trustee to execute and date such Assignment(s) for and on behalf of the Finance Parties in accordance with Clause 28.27(A)(ii) above.
 
28.29   Lenders’ custody of documents
 
(A)               Each Lender undertakes that it shall not deliver any Finance Document or any other document or agreement into a country that would result in such Finance Document, other document or agreement (or any party to it) becoming subject to (or liable for payment of) any stamp duty, documentary taxes or any other similar tax, charge or impost (or impose any obligation upon a member of the Group of KEH to reimburse any other person for such a payment).
 
(B)                 Paragraph (A) above shall not apply to a Lender at any time at which such Lender (i) has a right to take Enforcement Action; (ii) has the written consent of the Borrower; or (iii) is required to deliver such Finance Document or other document or agreement by any order or a court or regulatory authority or other legal or regulatory requirement.
 
28.30   Security Documents: consents, ranking and perfection
 
(A)               No Obligor shall be required to grant any assignment of rights under any contract, or Security Interest over any asset (including contracts and rights), where the consent of any Government or any governmental body, regulatory body or state-owned or controlled company or enterprise is required for the granting of such assignment or Security Interest.
 
(B)                 With the exception of those consents referred to in clause (A) above, Kosmos shall use reasonable endeavours to seek any other required third party consents required in relation to any Security Document, provided that the obtaining of such consent shall not be a condition precedent to any Utilisation of the Facility and provided that there shall be no fixed date by which such consent must be obtained.
 
(C)                 Kosmos shall use reasonable endeavours to obtain acknowledgments to any notices of assignment served in relation to any Security Document, provided that receipt of such acknowledgments shall not be a condition precedent to any Utilisation of the Facility.
 
(D)                Where required by the terms of any agreement which is binding upon any Obligor, any Security Interest granted in favour of the Lenders shall be subordinated to the interests of the parties under such agreement.
 
(E)                  With the exception of the Charges over Shares, perfection of any Security Interest shall not be a condition precedent to first Utilisation.
 
117

 
28.31   IPO Reorganisation
 
The Finance Parties agree that, notwithstanding the terms of any Finance Document which, but for this Clause, may have prevented an Obligor from participating in and/or implementing an IPO Reorganisation, each Obligor may participate in and implement such an IPO Reorganisation and no term or condition of any Finance Document which would, but for this Clause, prevent an IPO Reorganisation, shall prevent such an IPO Reorganisation or require KEH, or any Obligor or any of their respective Subsidiaries to act, or omit to act, in a manner which would or might reasonably be expected to prevent, impede, restrict or result in the obstruction of, or delay to, an IPO Reorganisation, provided that: (i) such IPO Reorganisation is for the purposes of an IPO substantially as described in the Form S-1 filed by Kosmos Energy Ltd. with the United States Securities and Exchange Commission on 14 January 2011 (including any updated filing in relation to such Form S-1); and (ii) the interests of the Finance Parties are not materially prejudiced. Without limitation (and without prejudice to Clause 28.8(C), the foregoing shall require the Finance Parties to release and discharge the Security Interests created pursuant to any Security Document, provided that immediately upon such release substantially equivalent security is granted in favour of the Finance Parties on substantially similar terms and such that the position of the Finance Parties is not materially prejudiced. Nothing in this Clause 28.31 shall prevent any Obligor from acting or omitting to act in any way (including implementing an IPO Reorganisation) which would otherwise be permitted by the terms of the Finance Documents.
 
28.32   Ghanaian security
 
(A)               The Borrower shall use reasonable endeavours to obtain a legal opinion from Ghanaian counsel confirming that the consent obtained on 18 December 2010 from the Ghana National Petroleum Corporation and the Ministry of Energy of Ghana, which was required in relation to the grant of certain Security Interests (the “ Ghana Security Interests ”) contemplated by the Security Documents (as defined in the Existing Finance Documents), would extend to the grant of such Security Interests in favour of the Finance Parties in the context of the Finance Documents.
 
(B)                 If such a legal opinion is obtained, the Borrower shall then promptly enter into security documents in the required form in order to grant to the Finance Parties equivalent Security Interests to the Ghana Security Interests in the context of the Finance Documents. Such security documents will be held by the Security Agent in accordance with Clause 28.27 ( Due execution of security Assignments ) above.
 
29.                 EVENTS OF DEFAULT
 
Each of the events or circumstances set out in this clause is an Event of Default (save for clause 29.17 (Acceleration — all Lenders ), unless otherwise stated.
 
29.1          Non-payment
 
An Obligor does not pay any amount payable by it to any Finance Party (or to the Facility Agent for its own account) under the Finance Documents in the manner and on
 
118

 
the date required under the Finance Documents within five Business Days of its due date.
 
29.2          Breach of financial covenant
 
Kosmos does not comply with the provisions of the Financial Covenants, provided that where the LLCR or FLCR has been breached, the Borrower shall have 45 days within which to remedy any breach of the relevant financial covenant by means of a prepayment and/or a cancellation of the Facility where any prepayment is funded by the provision of Additional Debt subordinated on terms acceptable to the Majority Lenders (acting reasonably), or by the contribution of equity to the capital of the Borrower or by taking such other remedial action as may be approved by the Majority Lenders provided always that the Borrower shall be entitled to remedy any such breach not more than twice in total and not more than once in any 12 month period.
 
29.3          Breach of other obligations
 
An Obligor does not comply with any other provision of the Finance Documents (other than in respect of non-payment or breach of a Financial Covenant), unless the non-compliance is:
 
(A)               capable of remedy; and
 
(B)                 remedied within 30 days of the earlier of the Facility Agent giving notice or the Obligor becoming aware of the non-compliance.
 
29.4          Misrepresentation
 
Any representation or statement made or deemed to be made by an Obligor in the Finance Documents is or proves to have been incorrect or misleading in any material respect when made or deemed to be made (or, in the case of a representation or statement that contains a materiality concept, is or proves to have been incorrect or misleading in any respect when made or deemed to be made), unless the misrepresentation is:
 
(A)               capable of remedy; and
 
(B)                 remedied within 30 days of the earlier of the Facility Agent giving notice or the relevant Obligor becoming aware of the misrepresentation.
 
29.5          Cross-default
 
(A)               Any Financial Indebtedness of any Obligor is not paid when due nor within any applicable grace period.
 
(B)                 Any Financial Indebtedness of any Obligor is declared to be or otherwise becomes due and payable prior to its specified maturity as a result of an event of default (however described) and such amount is not paid when due.
 
119

 
(C)                 Notwithstanding paragraphs (A) and (B) above, no Event of Default will occur under this clause if the aggregate amount of Financial Indebtedness or commitment for Financial Indebtedness is less than USD 100 million (or its equivalent in any other currency or currencies) or if the relevant event or default has been waived, or if such event or default is caused by a Disruption Event, provided that, in the case of a Disruption Event the requisite payment is made within five Business Days.
 
29.6          Insolvency
 
Any of the following occurs in respect of an Obligor:
 
(A)               it is, or is deemed for the purposes of any law to be, unable to, or admits its inability to, pay its debts as they fall due or is or becomes insolvent or a moratorium is declared in relation to its indebtedness generally; or
 
(B)                 it stops or suspends or threatens to suspend, or announces an intention to stop or suspend making payment of all or any class of its debts as they fall due in default of the obligation to make the relevant payment.
 
29.7          Insolvency proceedings
 
(A)               Except as provided in paragraph (B) below, any of the following occurs in respect of an Obligor:
 
(i)                       a written resolution is passed or a resolution is passed at a meeting of its shareholders, directors or other officers to petition for or to file documents with a court or any registrar for its winding-up, administration or dissolution;
 
(ii)                    any person presents a petition, or files documents with a court or any registrar for its winding-up, administration or dissolution;
 
(iii)                 an order for its winding-up, administration or dissolution is made;
 
(iv)                any liquidator, provisional liquidator, trustee in bankruptcy, judicial custodian, compulsory manager, receiver, administrative receiver, administrator or similar officer is appointed in respect of it or any material part of its assets;
 
(v)                   a moratorium is declared in relation to the indebtedness of an Obligor;
 
(vi)                its shareholders, directors or other officers request the appointment of, or give notice of their intention to appoint a liquidator, trustee in bankruptcy, judicial custodian, compulsory manager, provisional liquidator, receiver, administrative receiver, administrator or similar officer;
 
(vii)             any composition, compromise, assignment or arrangement is made with any of its creditors; or
 
120

 
(viii)          any other analogous step or procedure is taken in any jurisdiction.
 
(B)                 Paragraph (A) does not apply to:
 
(i)                       any step or procedure which is part of a re-organisation of an Obligor on a solvent basis with the consent of the Majority Lenders (acting reasonably); or
 
(ii)                    an IPO Reorganisation; or
 
(iii)                 in the case of sub-paragraph (ii) or (iv) (or any step or procedure under sub-paragraph (vi) that is analogous to sub-paragraph (ii) or (iv)), if the relevant step, petition or filing is made by a person other than an Obligor, shareholder or their respective officers or directors and the relevant Obligor is taking steps in good faith and with due diligence for such proceedings or action to be stayed, discontinued, revoked or set aside and the same is stayed, discontinued, revoked or set aside within a period of 60 days; or
 
(iv)                any enforcement action that applies to assets having an aggregate value of less than USD 100 million.
 
29.8          Creditors’ process
 
Any attachment, sequestration, distress, execution or analogous event affects any asset(s) of an Obligor, having an aggregate value of at least USD 15 million, and is not discharged within 45 days.
 
29.9          Unlawfulness and Invalidity of the Finance Documents and Project Agreements
 
If:
 
(A)               all or any part of a Finance Document is not, or ceases to be, a legal, valid, binding and enforceable obligation of an Obligor;
 
(B)                 following its execution, all or any part of a Project Agreement is not or ceases to be, a legal, valid, binding and enforceable obligation of an Obligor in circumstances which would have a Material Adverse Effect; or
 
(C)                 following its execution, all or any part of a Project Agreement is suspended, terminated or revoked in circumstances which would have a Material Adverse Effect,
 
and:
 
(i)                       Kosmos fails, within 60 days (or, in the case of a Finance Document, 30 days) of becoming aware of the matter, to procure the execution of a substitute agreement or agreements on substantially the same terms and with a commercially qualified party or parties acceptable to the Majority Lenders (acting reasonably); or
 
121

 
(ii)                    the matter is not otherwise remedied within 60 days (or, in the case of a Finance Document, 30 days) of an Obligor becoming aware of the matter.
 
29.10   Cessation of Business
 
An Obligor ceases, or threatens to cease, all or a substantial part of its business (as carried on the date of the Facility Agreement).
 
29.11   Abandonment
 
(A)               A Borrowing Base Asset is abandoned (other than as a consequence of unsuccessful exploration activities) in whole or in part and where such abandonment has or could reasonably be expected to have a Material Adverse Effect.
 
(B)                 Without limiting the above paragraph, Kosmos will be deemed to have abandoned a Borrowing Base Asset if, after the relevant Completion, no petroleum is produced at a commercial level for a continuous period of 180 days and all necessary steps are not being diligently pursued with a view to recommencing production as soon as practically possible.
 
29.12   Expropriation
 
The Government (or any other official central or local government body with due authority) states officially that it will take any step with a view to the seizure, expropriation, nationalisation, requisition or compulsory acquisition of any member of the Group or all or a material part of the Borrowing Base Assets or all or a material part of the rights of any member of the Group in relation thereto and such act has, or could reasonably be expected to have, a Material Adverse Effect.
 
29.13   Repudiation of Finance Documents
 
Any Finance Document is repudiated or rescinded by an Obligor.
 
29.14   Material Litigation
 
Any material litigation, arbitration or administrative proceedings are commenced, threatened or pending against any Obligor which could reasonably be expected to be adversely determined against it and which, if so determined, has, or would have, a Material Adverse Effect.
 
29.15   Breach or Termination of Project Agreements
 
Any party to a Project Agreement, following its execution, defaults under that Project Agreement or terminates a Project Agreement in circumstances which has, or would have, a Material Adverse Effect.
 
122

 
29.16   Material Adverse Effect
 
Any event which, in the opinion of the Majority Lenders (acting reasonably), has a Material Adverse Effect but only following consultation between the Facility Agent and Kosmos over a period of not less than 30 days with a view to agreeing steps of mitigation (each Party acting reasonably with a view to appropriate remedial action being taken).
 
29.17   Acceleration — all Lenders
 
Subject to the terms of the Intercreditor Agreement, on and at any time after the occurrence of an Event of Default which is continuing, the Facility Agent may, and shall if so directed by the Majority Lenders, by notice to the Borrower:
 
(A)               cancel the Total Commitments whereupon they shall immediately be cancelled;
 
(B)                 declare that all or part of the Loans, together with accrued interest, and all other amounts accrued or outstanding under the Finance Documents be immediately due and payable, whereupon they shall become immediately due and payable; and/or
 
(C)                 declare that all or part of the Loans be payable on demand, whereupon they shall immediately become payable on demand by the Facility Agent on the instructions of the Majority Lenders; and/or
 
(D)                exercise or direct the Security Agent to exercise any or all of its rights, remedies, powers or discretions under any of the Finance Documents.
 
123

 
PART 11
CHANGES TO LENDERS AND OBLIGORS AND ROLES
 
30.                 CHANGES TO THE LENDERS
 
30.1          Assignments and transfers and changes in Facility Office by the Lenders
 
Subject to this clause, a Lender (the “Existing Lender”) may:
 
(A)               (i)                       assign any of its rights; or
 
(ii)                    transfer by novation any of its rights and obligations,
 
to an Affiliate, another Lender, an Affiliate of another Lender or, with the prior consent of the Borrower (other than where an Event of Default is continuing), to an internationally recognised Qualifying Bank (which will not be unreasonably withheld or delayed and which will be deemed to have been given five Business Days after the date upon which the Existing Lender has requested it unless consent is expressly refused by the Borrower within that time), or such other institution as the Borrower may agree (the “ New Lender ”), or
 
(B)                 change its Facility Office.
 
30.2          Conditions of assignment and transfer or change in Facility Office
 
(A)               The consent of Kosmos is required for an assignment or transfer by an Existing Lender, unless the assignment or transfer is (i) to, or in favour of, another Lender or an Affiliate of a Lender, or (ii) made at a time when an Event of Default is continuing.
 
(B)                 The consent of Kosmos is required for a change in Facility Office to a different jurisdiction. In the case of a change of Facility Office for which Kosmos’s consent is not required, the Lender must notify Kosmos of the new Facility Office promptly on the change taking effect.
 
(C)                 The consent of Kosmos to an assignment or transfer or change in Facility Office must not be unreasonably withheld or delayed (and will be deemed to have been given five Business Days after the relevant Lender has requested it unless consent is expressly refused by Kosmos within that time).
 
(D)                In the event a Letter of Credit is outstanding, transfer or assignment of a Commitment shall require the prior consent of each LC Issuing Bank.
 
(E)                  An assignment will only be effective on:
 
(i)                      receipt by the Facility Agent of written confirmation from the New Lender (in form and substance satisfactory to the Facility Agent) that the New Lender will assume the same obligations to the other Finance Parties as it would have been under if it was an Original Lender; and
 
124

 
(ii)                   the New Lender entering into the documentation required for it to accede as a party to the relevant Finance Documents (including, but not limited to, the Intercreditor Agreement).
 
(F)                  A transfer will only be effective if the procedure set out in clause 30.5 (Procedure for transfer) is complied with.
 
(G)                 If:
 
(i)                      a Lender assigns or transfers any of its rights or obligations under the Finance Documents or changes its Facility Office; and
 
(ii)                   as a result of circumstances existing at the date the assignment, transfer or change occurs, an Obligor would be obliged to make a payment to the New Lender or Lender acting through its new Facility Office under clause 15 ( Tax Gross Up and Indemnities ) or clause 16 ( Increased Costs ),
 
then the New Lender or Lender acting through its new Facility Office is only entitled to receive payment under those clauses to the same extent as the Existing Lender or Lender acting through its previous Facility Office would have been if the assignment, transfer or change had not occurred.
 
(H)                Each New Lender, by executing the relevant Transfer Certificate confirms, for the avoidance of doubt, that the Facility Agent has authority to execute on its behalf any amendment or waiver that has been approved by or on behalf of the requisite Lender or Lenders in accordance with the Finance Documents on or prior to the date on which the transfer or assignment becomes effective in accordance with this Agreement.
 
(I)                     Any assignment or transfer of part of the Existing Lender’s rights and/or obligations must be a minimum of USD 5 million and must not result in the Existing Lender retaining less than USD 5 million.
 
30.3          Assignment or transfer fee
 
The New Lender shall, on the date upon which an assignment or transfer takes effect, pay to the Facility Agent (for its own account) a fee of USD 2,500.
 
30.4          Limitation of responsibility of Existing Lenders
 
(A)               Unless expressly agreed to the contrary, an Existing Lender makes no representation or warranty and assumes no responsibility to a New Lender for:
 
(i)                       the legality, validity, effectiveness, adequacy or enforceability of the Finance Documents or any other documents;
 
(ii)                    the financial condition of any Obligor;
 
125

 
(iii)                the performance and observance by any Obligor of its obligations under the Finance Documents or any other documents; or
 
(iv)               the accuracy of any statements (whether written or oral) made in or in connection with any Finance Document or any other document,
 
and any representations or warranties implied by law are excluded.
 
(B)                 Each New Lender confirms to the Existing Lender and the other Finance Parties that it:
 
(i)                      has made (and shall continue to make) its own independent investigation and assessment of the financial condition and affairs of each Obligor and its related entities in connection with its participation in the Facility and has not relied exclusively on any information provided to it by the Existing Lender in connection with any Finance Document; and
 
(ii)                   will continue to make its own independent appraisal of the creditworthiness of each Obligor and its related entities whilst any amount is or may be outstanding under the Finance Documents or any Commitment is in force.
 
(C)                 Nothing in any Finance Document obliges an Existing Lender to:
 
(i)                      accept a re-transfer or re-assignment from a New Lender of any of the rights and obligations assigned or transferred under this clause; or
 
(ii)                   support any losses directly or indirectly incurred by the New Lender by reason of the non-performance by any Obligor of its obligations under the Finance Documents or otherwise.
 
30.5          Procedure for transfer
 
(A)               Subject to the conditions set out in clause 30.2 (Conditions of assignment and transfer or change in Facility Office) a transfer is effected in accordance with paragraph (B) below when the Facility Agent executes an otherwise duly completed Transfer Certificate delivered to it by the Existing Lender and the New Lender. The Facility Agent shall, as soon as reasonably practicable after receipt by it of a duly completed Transfer Certificate appearing on its face to comply with the terms of this Agreement and delivered in accordance with the terms of this Agreement, execute that Transfer Certificate on behalf of the other Finance Parties and the Obligors as well as itself, and notify Kosmos of the date of the transfer and name of the New Lender. Each Finance Party and each Obligor irrevocably authorises the Facility Agent to sign such a Transfer Certificate on its behalf.
 
(B)                 On the Transfer Date:
 
(i)                      to the extent that in the Transfer Certificate the Existing Lender seeks to transfer by novation its rights and obligations under the Finance
 
126

 
Documents, each of the Obligors and the Existing Lender shall be released from further obligations towards one another under the Finance Documents and their respective rights against one another under the Finance Documents shall be cancelled (being the “ Discharged Rights and Obligations ”);
 
(ii)                   each of the Obligors and the New Lender shall assume obligations towards one another and/or acquire rights against one another which differ from the Discharged Rights and Obligations only insofar as that Obligor and the New Lender have assumed and/or acquired the same in place of that Obligor and the Existing Lender;
 
(iii)                the Facility Agent, each Mandated Lead Arranger, the New Lender and the other Finance Parties shall acquire the same rights and assume the same obligations between themselves as they would have acquired and assumed had the New Lender been an Original Lender with the rights and/or obligations acquired or assumed by it as a result of the transfer and to that extent such Finance Parties and the Existing Lender shall each be released from further obligations to each other under the Finance Documents; and
 
(iv)               the New Lender shall become a Party as a “Lender”.
 
30.6          Copy of Transfer Certificate to Borrower
 
The Facility Agent shall, as soon as reasonably practicable after it has executed a Transfer Certificate, send to Kosmos a copy of that Transfer Certificate.
 
30.7          Disclosure of information
 
Any Lender, its officers and agents may disclose to any of its Affiliates (including its head office, representative and branch offices in any jurisdiction) (each a “ Permitted Party ”) and:
 
(A)               to any person (or through) whom that Lender assigns or transfers (or may potentially assign or transfer) all or any of its rights and obligations under this Agreement (or any adviser on a need to know basis advising such person on any of the foregoing);
 
(B)                 to a professional adviser or a service provider of the Permitted Parties on a need to know basis advising such person on the rights and obligations under the Finance Documents or to an auditor of any Permitted Party on a need to know basis;
 
(C)                 with (or through) whom that Lender enters into (or may potentially enter into) any sub-participation in relation to, or any other transaction under which payments are to be made by reference to, this Agreement or any Obligor (or any adviser of any of the foregoing on a need to know basis advising such person on the rights and obligations under the Finance Documents);
 
127

 
(D)                to any rating agency (provided only general terms are disclosed in relation to the rating of a portfolio of assets), insurer or insurance broker, a direct or indirect provider of credit protection in respect of the Lender’s participation in the Facility only on a need to know basis;
 
(E)                  to any court or tribunal or regulatory, supervisory, governmental or quasi-governmental authority with jurisdiction over the Permitted Parties who requires disclosure of that information (where the Permitted Party has a legal obligation to provide that information or, if not, is customarily obligated or required to comply with such requirement); or
 
(F)                  to whom, and to the extent that, information is required to be disclosed by any applicable law or regulation,
 
any information about any Obligor, the Group and the Finance Documents as that Lender shall consider appropriate if, in relation to paragraphs (A) to (C) above, the person to whom the information is to be given has entered into a Confidentiality Undertaking (unless such person is already subject to professional confidentiality requirements which are no less stringent than those which are set out in a Confidentiality Undertaking) and provided that it shall itself ensure that all such information is kept confidential and is protected with security measures and a degree of care that would apply to its own confidential information.
 
31.                 CHANGES TO THE OBLIGORS
 
31.1          Assignments and transfers by Obligors
 
No Obligor may assign any of its rights or transfer any of its rights or obligations under the Finance Documents.
 
31.2          Additional Borrowers
 
(A)               Subject to compliance with the provisions of paragraphs (C) and (D) of clause 24.12 (“Know your customer” and “customer due diligence” requirements ), Kosmos may request that any of its subsidiaries becomes an Additional Borrower. That subsidiary shall become an Additional Borrower if:
 
(i)                      the Majority Lenders (or, if that Additional Borrower is incorporated in a jurisdiction in which no other Borrower is incorporated, all the Lenders) approve the addition of that subsidiary;
 
(ii)                   the Additional Borrower is, or simultaneously becomes, a Guarantor;
 
(iii)                Kosmos delivers to the Facility Agent a duly completed and executed Accession Letter;
 
(iv)               Kosmos confirms that no Default is continuing or would occur as a result of that subsidiary becoming an Additional Borrower; and
 
128

 
(v)                  the Facility Agent has received all of the documents and other evidence listed in Part II of Schedule 3 ( Conditions Precedent ) in relation to that Additional Borrower, each in form and substance satisfactory to the Facility Agent.
 
(B)                 The Facility Agent shall notify Kosmos and the Lenders promptly upon being satisfied that it has received (in form and substance satisfactory to it) all the documents and other evidence listed in Part II of Schedule 3 ( Conditions Precedent ).
 
(C)                 In the event that an Additional Borrower becomes a party to this Agreement:
 
(i)                      Kosmos, on behalf of all Obligors; and
 
(ii)                   the Facility Agent on behalf of all Finance Parties,
 
are hereby authorised to effect all amendments required to be made to the Finance Documents to which they are party to reflect the fact that there may be multiple borrowers of the Facility.
 
31.3          Resignation of a Borrower
 
(A)               Kosmos may request that a Borrower (other than Kosmos) ceases to be a Borrower by delivering to the Facility Agent a Resignation Letter.
 
(B)                 The Facility Agent shall accept a Resignation Letter and notify Kosmos and the Lenders of its acceptance if:
 
(i)                      no Default is continuing or would result from the acceptance of the Resignation Letter (and Kosmos has confirmed this is the case); and
 
(ii)                   the Borrower is under no actual or contingent obligations as a Borrower under any Finance Documents,
 
whereupon that company shall cease to be a Borrower and shall have no further rights or obligations under the Finance Documents.
 
31.4          Additional Guarantor
 
(A)               Subject to compliance with the provisions of paragraphs (C) and (D) of clause 24.12 (“Know your customer” and “customer due diligence” requirements ), the Borrower may request that any of its subsidiaries becomes an Additional Guarantor. That subsidiary shall become an Additional Guarantor if:
 
(i)                      Kosmos delivers to the Facility Agent an Accession Letter duly completed and executed by that Additional Guarantor and Kosmos; and
 
(ii)                   the Facility Agent have received all of the documents and other evidence listed in Part II of Schedule 3 ( Conditions Precedent ) in
 
129

 
relation to that Additional Guarantor, each in form and substance satisfactory to the Facility Agent.
 
(B)                 The Facility Agent shall notify Kosmos and the Lenders promptly upon being satisfied that it has received (in form and substance satisfactory to it) all the documents and other evidence listed in Part II of Schedule 3 ( Conditions Precedent ).
 
31.5          Repetition of Representations
 
Delivery of an Accession Letter constitutes confirmation by the relevant subsidiary that the Repeating Representations are true and correct in relation to it as at the date of delivery as if made by reference to the facts and circumstances then existing.
 
32.                 ROLE OF THE AGENTS AND THE ARRANGER
 
32.1          Appointment of the Agents
 
(A)               Each other Finance Party (other than the relevant Agent) appoints each Agent to act in that capacity under and in connection with the Finance Documents.
 
(B)                 Each other Finance Party authorises each Agent to exercise the rights, powers, authorities and discretions specifically given to that Agent under or in connection with the Finance Documents together with any other incidental rights, powers, authorities and discretions.
 
32.2          Duties of the Facility Agent
 
(A)               The Facility Agent shall promptly forward to a Party the original or a copy of any document which is delivered to the Facility Agent for that Party by any other Party.
 
(B)                 Except where a Finance Document specifically provides otherwise, the Facility Agent is not obliged to review or check the adequacy, accuracy or completeness of any document it forwards to another Party.
 
(C)                 If the Facility Agent receives notice from a Party referring to this Agreement, describing a Default and stating that the circumstance described is a Default, it shall promptly notify the Finance Parties.
 
(D)                If the Facility Agent is aware of the non-payment of any principal, interest, commitment fee or other fee payable to a Finance Party (other than to an Agent or a Mandated Lead Arranger) under this Agreement it shall promptly notify the other Finance Parties.
 
(E)                  The Facility Agent’s duties under the Finance Documents are solely mechanical and administrative in nature.
 
130

 
32.3          Role of the Mandated Lead Arrangers
 
Except as specifically provided in the Finance Documents, no Mandated Lead Arranger has obligations of any kind to any other Party under or in connection with any Finance Document.
 
32.4          No fiduciary duties
 
(A)               Except as specifically provided in the Finance Documents, nothing in this Agreement constitutes an Agent or a Mandated Lead Arranger as a trustee or fiduciary of any other person.
 
(B)                 No Agent nor any Mandated Lead Arranger shall be bound to account to any Lender for any sum or the profit element of any sum received by it for its own account.
 
32.5          Business with the Group
 
Each Agent and each Mandate Lead Arranger may accept deposits from, lend money to and generally engage in any kind of banking or other business with any member of the Group.
 
32.6          Rights and discretions of Agents
 
(A)               Each Agent may rely on:
 
(i)                      any representation, notice or document believed by it to be genuine, correct and appropriately authorised; and
 
(ii)                   any statement made by a director, Authorised Signatory or employee of any person regarding any matters which may reasonably be assumed to be within his knowledge or within his power to verify.
 
(B)                 Each Agent may assume (unless it has received notice to the contrary in its capacity as agent for the Lenders) that:
 
(i)                      no Default has occurred (unless it has actual knowledge of a Default arising under clause 29.1 ( Non-payment ));
 
(ii)                   any right, power, authority or discretion vested in any Party or the Lenders (or any consistent majority of Lenders) has not been exercised; and
 
(iii)                any notice or request made by Kosmos (other than a Utilisation Request) is made on behalf of and with the consent and knowledge of all the Obligors.
 
(C)                 Each Agent may engage, pay for and rely on the advice or services of any lawyers, accountants, surveyors or other experts.
 
131

 
(D)                Each Agent may act in relation to the Finance Documents through its personnel and agents.
 
(E)                  Each Agent may disclose to any other Party any information it reasonably believes it has received as agent under this Agreement.
 
(F)                  Notwithstanding any other provision of any Finance Document to the contrary, no Agent nor any Mandated Lead Arranger is obliged to do or omit to do anything if it would or might in its reasonable opinion constitute a breach of any law or regulation or a breach of a fiduciary duty or duty of confidentiality.
 
32.7          Lenders’ instructions
 
(A)               Unless a contrary indication appears in a Finance Document, each Agent shall (i) exercise any right, power, authority or discretion vested in it as Agent in accordance with any instructions given to it by the Lenders in accordance with this Agreement and the Intercreditor Agreement (or, if so instructed, refrain from exercising any right, power, authority or discretion vested in it as Agent) and (ii) not be liable for any act (or omission) if it acts (or refrains from taking any action) in accordance with such instructions.
 
(B)                 Each Agent may refrain from acting in accordance with instructions given to it by the Lenders in accordance with this Agreement and the Intercreditor Agreement until it has received such security as it may require for any cost, loss or liability (together with any associated VAT) which it may incur in complying with the instructions.
 
(C)                 In the absence of instructions in accordance with this Agreement and the Intercreditor Agreement each Agent may act (or refrain from taking action) as it considers to be in the best interest of the Lenders.
 
(D)                Neither Agent is authorised to act on behalf of a Lender (without first obtaining that Lender’s consent) in any legal or arbitration proceedings relating to any Finance Document.
 
32.8          Responsibility for documentation
 
No Agent nor any Mandated Lead Arranger:
 
(A)               is responsible for the adequacy, accuracy and/or completeness of any information (whether oral or written) supplied by an Agent, a Mandated Lead Arranger, an Obligor or any other person given in or in connection with any Finance Document or the Final Information Memorandum; or
 
(B)                 is responsible for the legality, validity, effectiveness, adequacy or enforceability of any Finance Document or any other agreement, arrangement or document entered into, made or executed in anticipation of or in connection with any Finance Document.
 
132

 
32.9          Exclusion of liability
 
(A)               Without limiting paragraph (B) below (and without prejudice to the provisions of paragraph (E) of clause 34.9 ( Disruption to Payment Systems etc. ), no Agent shall be liable (including, without limitation, for negligence or any other category of liability whatsoever) for any action taken by it under or in connection with any Finance Document, unless directly caused by its gross negligence or wilful misconduct.
 
(B)                 No Party (other than the relevant Agent) may take any proceedings against any officer, employee or agent of that Agent in respect of any claim it might have against it or in respect of any act or omission of any kind by that officer, employee or agent in relation to any Finance Document and any officer, employee or agent of the relevant Agent may rely on this clause.
 
(C)                 An Agent will not be liable for any delay (or any related consequences) in crediting an account with an amount required under the Finance Documents to be paid by it if that Agent has taken all necessary steps as soon as reasonably practicable to comply with the regulations or operating procedures of any recognised clearing or settlement system used by it for that purpose.
 
32.10   Lenders’ indemnity to the Agents
 
Each Lender shall (in proportion to its share of the Total Commitments or, if the Total Commitments are then zero, to its share of the Total Commitments immediately prior to their reduction to zero) indemnify each Agent and the Technical and Modelling Bank, within three Business Days of demand, against any cost, loss or liability (including, without limitation, for negligence or any other category of liability whatsoever) incurred by it (otherwise than by reason of the relevant Agent’s or Technical and Modelling Bank’s gross negligence or wilful misconduct) (or, in the case of any cost, loss or liability pursuant to clause 34.9 ( Disruption to Payment Systems etc. ) notwithstanding the relevant Agent’s or Technical and Modelling Bank’s negligence, gross negligence or any other category of liability whatsoever but not including any claim based on the fraud of the relevant Agent) in acting as an Agent or the Technical and Modelling Bank under the Finance Documents (unless the relevant Agent or the Technical and Modelling Bank has been reimbursed by an Obligor pursuant to a Finance Document).
 
32.11   Resignation of the Agent
 
(A)               An Agent may resign and appoint one of its Affiliates acting through an office in the United Kingdom as successor by giving notice to the other Finance Parties and Kosmos.
 
(B)                 Alternatively, an Agent may resign by giving notice to the other Finance Parties and Kosmos, in which case the Majority Lenders may appoint a successor Agent.
 
(C)                 If the Majority Lenders have not appointed a successor Agent in accordance with paragraph (B) above within 30 days after notice of resignation was given,
 
133

 
the relevant Agent may (with the prior written consent of Kosmos) appoint a successor Agent (acting through an office in the United Kingdom).
 
(D)                A retiring Agent shall, at its own cost, make available to the successor Agent such documents and records and provide such assistance as the successor Agent may reasonably request for the purposes of performing its functions as Agent under the Finance Documents. This obligation shall not apply in the event the Agent is required to resign pursuant to clause 32.11(G) below.
 
(E)                  An Agent’s resignation notice shall only take effect upon the appointment of a successor.
 
(F)                  Upon the appointment of a successor, a retiring Agent shall be discharged from any further obligation in respect of the Finance Documents but shall remain entitled to the benefit of this clause 32.11. Its successor and each of the other Parties shall have the same rights and obligations amongst themselves as they would have had if such successor had been an original Party.
 
(G)                 After consultation with Kosmos, the Majority Lenders may, by notice to an Agent, require it to resign in accordance with paragraph (B) above.
 
32.12 Replacement of Administrative Parties
 
(A)               If:
 
(i)                       in relation to the Facility Agent, the Security Agent or an LC Issuing Bank (or their respective holding companies), clause 29.6 ( Insolvency ) or clause 29.7 ( Insolvency proceedings ) (disregarding paragraph (B) of that clause) applies or has occurred; or
 
(ii)                    if the Facility Agent, the Security Agent or an LC Issuing Bank or any of their Affiliates repudiates its obligations under the Facility or (in its capacity as Lender) becomes a Non-Funding Lender,
 
Kosmos shall be entitled to request that Majority Lenders appoint within 10 Business Days either a co-Agent or additional LC Issuing Bank or a replacement Agent or LC Issuing Bank from one of their number or (subject to reasonable consultation with the Parent), from outside the Lender group.
 
(B)                 The Facility Agent, Security Agent or LC Issuing Bank to which either of the circumstances described in (A)(i) or (A)(ii) above applies (an “ Affected Administrative Party ”) shall cease to be entitled to fees in respect of its role upon becoming an Affected Administrative Party.
 
(C)                 Each Affected Administrative Party shall provide all assistance and documentation reasonably required to Kosmos and the other Lenders to enable the uninterrupted administration of the Facility. This shall include, where the Affected Administrative Party is the Facility Agent, the provision to Kosmos on request and in any event, within five Business Days, of an up to date list of participants in the Facility including names and contact details.
 
134

 
32.13 Confidentiality
 
(A)               In acting as agent for the Finance Parties, an Agent shall be regarded as acting through its agency division or, in the case of the Technical and Modelling Bank, through the relevant division performing the role which shall be treated as a separate entity from any other of its divisions or departments.
 
(B)                 If information is received by another division or department of an Agent, it may be treated as confidential to that division or department and the relevant Agent shall not be deemed to have notice of it.
 
32.14 Facility Agent relationship with the Lenders
 
(A)               The Facility Agent may treat each Lender as a Lender, entitled to payments under this Agreement and acting through its Facility Office unless it has received not less than five Business Days’ prior notice from that Lender to the contrary in accordance with the terms of this Agreement.
 
(B)                 Each Lender shall supply the Facility Agent with any information required by that Facility Agent in order to calculate the Mandatory Cost in accordance with Schedule 6 ( Mandatory Cost Formulae ).
 
32.15 Credit appraisal by the Lenders
 
Without affecting the responsibility of any Obligor for information supplied by it or on its behalf in connection with any Finance Document, each Lender confirms to the Agents and each Mandated Lead Arranger that it has been, and will continue to be, solely responsible for making its own independent appraisal and investigation of all risks arising under or in connection with any Finance Document including but not limited to:
 
(A)               the financial condition, status and nature of the Guarantor and each member of the Group;
 
(B)                 the legality, validity, effectiveness, adequacy or enforceability of any Finance Document and any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document;
 
(C)                 whether that Lender has recourse, and the nature and extent of that recourse, against any Party or any of its respective assets under or in connection with any Finance Document, the transactions contemplated by the Finance Documents or any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document; and
 
(D)                the adequacy, accuracy and/or completeness of the Final Information Memorandum and any other information provided by the Agents, any Party or by any other person under or in connection with any Finance Document, the transactions contemplated by the Finance Documents or any other agreement,
 
135

 
arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document.
 
32.16 Reference Banks
 
If a Reference Bank (or, if a Reference Bank is not a Lender, the Lender of which it is an Affiliate) ceases to be a Lender, the Facility Agent shall (in consultation with Kosmos) appoint another Lender or an Affiliate of a Lender to replace that Reference Bank.
 
32.17 Deductions from amounts payable by Agents
 
If any Party owes an amount to an Agent under the Finance Documents, the Agent may, after giving notice to that Party, deduct an amount not exceeding that amount from any payment to that Party which the Agent would otherwise be obliged to make under the Finance Documents and apply the amount deducted in or towards satisfaction of the amount owed. For the purposes of the Finance Documents, that Party shall be regarded as having received any amounts so deducted.
 
33.     CONSULTANTS
 
33.1   Insurance Consultant
 
Kosmos and the Finance Parties hereby confirm the appointment of Moore-McNeil, LLC as Insurance Consultant, upon the terms and subject to the conditions set out in the Insurance Consultant Appointment Letter.
 
33.2   Technical Consultant
 
Kosmos and the Finance Parties hereby confirm the appointment of Shaw Consultants, Inc. as Technical Consultant upon the terms and conditions set out in the Technical and Environmental Consultant Appointment Letter.
 
33.3   Environmental Consultant
 
Kosmos and the Finance Parties hereby confirm the appointment of Shaw Consultants, Inc. as Environmental Consultant upon the terms and conditions set out in the Technical and Environmental Consultant Appointment Letter.
 
33.4   Reserves Consultant
 
Kosmos and the Finance Parties hereby confirm the appointment of Netherland Sewell & Associates, Inc. as Reserves Consultant upon the terms and conditions set out in the Reserves Consultant Appointment Letter.
 
33.5   Terms of appointment of Consultants
 
Each Party acknowledges that each of the Consultants has been appointed to act as consultant and adviser to the Finance Parties in relation to technical matters relating to the Project within its own sphere of competence. Each Finance Party acknowledges that each of the Consultants (and each replacement Consultant appointed pursuant to
 
136

 
clause 33.6 (Termination and replacement)) may also act as consultant and adviser to other Parties in relation to the Project. The fees and other terms of those appointments are set out in the appointment letters between the Consultants and Kosmos, copies of which have been given to, and consented to by, the Lenders. The Facility Agent may, acting reasonably and consistently with the agreed scope of work for the relevant Consultant, request it to provide advice or services in relation to the Project.
 
33.6   Termination and replacement
 
The Facility Agent may, if it has reasonable grounds to do so and (unless an Event of Default has occurred and is continuing) has first consulted with Kosmos, at any time terminate the appointment of a Consultant if it considers it necessary or appropriate to do so, and shall promptly give notice of any such termination to Kosmos. If the Facility Agent terminate the appointment of any Consultant it may appoint as a replacement Consultant any person approved (which approval shall include the identity of the replacement, the terms of appointment and approval of the fees and expenses to be payable to that person) for this purpose by Kosmos (which approval may not be unreasonably withheld or delayed or required while an Event of Default is continuing). The terms of any such appointment shall be set out in an appointment letter between such replacement Consultant (or additional consultant as appropriate) and Kosmos.
 
137

 
PART 12
ADMINISTRATION, COSTS AND EXPENSES
 
34.     PAYMENT MECHANICS
 
34.1   Payments to the Facility Agent
 
(A)               On each date on which an Obligor or a Lender is required to make a payment under a Finance Document (other than any Hedging Agreement), that Obligor or Lender shall make the same available to the Facility Agent (unless a contrary indication appears in a Finance Document) for value on the due date at the time and in such funds specified by the Facility Agent as being customary at the time for settlement of transactions in the relevant currency in the place of payment.
 
(B)                 Payment shall be made to such account in London (or, as the case may be, Paris or New York) as the Facility Agent specifies.
 
34.2   Distributions by the Facility Agent
 
Subject to the terms of the Intercreditor Agreement, each payment received by either of the Facility Agent under the Finance Documents for another Party shall be made available by the Facility Agent as soon as practicable after receipt to the Party entitled to receive payment (in the case of a Lender, for the account of its Facility Office), to such account as that Party may notify to the Facility Agent by not less than five Business Days’ notice with a bank in London (or, as the case may be, Paris or New York).
 
34.3   Clawback
 
(A)               Where a sum is to be paid to the Facility Agent under the Finance Documents for another Party, the Facility Agent is not obliged to pay that sum to that other Party (or enter into or perform any related exchange contract) until it has been able to establish to its satisfaction that it has actually received that sum.
 
(B)                 If the Facility Agent pays an amount to another Party and it proves to be the case that the Facility Agent had not actually received that amount, then the Party to whom that amount (or the proceeds of any related exchange contract) was paid by the Facility Agent shall on demand refund the same to the Facility Agent together with interest on that amount from the date of payment to the date of receipt by the Facility Agent, calculated by the Facility Agent to reflect its cost of funds.
 
34.4   Partial Payments
 
If the Facility Agent receives a payment for application against amounts due in respect of any Finance Documents that is insufficient to discharge all the amounts then due and payable by an Obligor under those Finance Documents, the Facility Agent shall apply that payment towards the obligations of that Obligor under those Finance Documents in accordance with the Cash Waterfall. This clause will override any appropriation made by an Obligor.
 
138

 
34.5   No set-off by Obligors
 
All payments to be made by an Obligor under the Finance Documents shall be calculated and be made without (and free and clear of any deduction for) set-off or counterclaim.
 
34.6   Business Days
 
(A)               Any payment which is due to be made on a day that is not a Business Day shall be made on the next Business Day in the same calendar month (if there is one) or the preceding Business Day (if there is not).
 
(B)                 During any extension of the due date for payment of any principal or Unpaid Sum under the Finance Documents, interest is payable on the principal or Unpaid Sum at the rate payable on the original due date.
 
34.7   Currency of account
 
(A)               Subject to paragraphs (B) to (E) below, the base currency is the currency of account and payment for any sum due from an Obligor under any Finance Document and is the US Dollar (“ Base Currency ”).
 
(B)                 A repayment of a Utilisation or Unpaid Sum or a part of a Utilisation or Unpaid Sum shall be made in the currency in which that Utilisation or Unpaid Sum is denominated on its due date.
 
(C)                 Each payment of interest shall be made in the currency in which the sum in respect of which the interest is payable was denominated when that interest accrued.
 
(D)                Each payment in respect of costs, expenses or Taxes shall be made in the currency in which the costs, expenses or Taxes are incurred.
 
(E)                  Any amount expressed to be payable in a currency other than the Base Currency shall be paid in that other currency.
 
34.8   Change of currency
 
(A)               Unless otherwise prohibited by law, if more than one currency or currency unit are at the same time recognised by the central bank of any country as the lawful currency of that country, then:
 
(i)                       any reference in the Finance Documents to, and any obligations arising under the Finance Documents in, the currency of that country shall be translated into, or paid in, the currency or currency unit of that country designated by the Facility Agent acting reasonably (after consultation with Kosmos); and
 
(ii)                    any translation from one currency or currency unit to another shall be at the official rate of exchange recognised by the central bank for the
 
139

 
conversion of that currency or currency unit into the other, rounded up or down by the Facility Agent (acting reasonably).
 
(B)                 If a change in any currency of a country occurs, the Parties will enter negotiations in good faith with a view to agreeing any amendments which may be necessary to this Agreement to comply with any generally accepted conventions and market practice in the London interbank market and otherwise to reflect the change in currency.
 
34.9   Disruption to Payment Systems etc.
 
If either of the Facility Agent determine (acting reasonably) that a Disruption Event has occurred or either of the Facility Agent is notified by Kosmos that a Disruption Event has occurred:
 
(A)               the Facility Agent may, and shall if requested to do so by Kosmos, consult with Kosmos with a view to agreeing with Kosmos such changes to the operation or administration of the Facility (including, without limitation, changes to the timing and mechanics of payments due under the Finance Documents) as the Facility Agent may deem necessary in the circumstances;
 
(B)                 the Facility Agent shall not be obliged to consult with Kosmos in relation to any changes mentioned in paragraph (A) above if, in its reasonable opinion, it is not practicable to do so in the circumstances and, in any event, shall have no obligation to agree to such changes;
 
(C)                 the Facility Agent may consult with the Finance Parties in relation to any changes mentioned in paragraph (A) above but shall not be obliged to do so if, in its opinion, it is not practicable to do so in the circumstances;
 
(D)                any such changes agreed upon by the Facility Agent and Kosmos shall (whether or not it is finally determined that a Disruption Event has occurred) be binding upon the Parties as an amendment to (or, as the case may be, waiver of) the terms of the Finance Documents notwithstanding the provisions of clause 41 ( Amendments and Waivers );
 
(E)                  the Facility Agent shall not be liable for any damages, costs or losses whatsoever (including, without limitation for negligence, gross negligence or any other category of liability whatsoever but not including any claim based on the fraud of the Facility Agent) arising as a result of its taking, or failing to take, any actions pursuant to or in connection with this clause; and
 
(F)                  the Facility Agent shall notify the Finance Parties of all changes agreed pursuant to paragraph (D) above.
 
35.     SET-OFF
 
Subject to the terms of the Intercreditor Agreement and without prejudice to the rights of the Finance Parties at law, at any time after an Event of Default has occurred which is continuing, a Finance Party (other than a Non-Funding Lender) may, on giving notice to
 
140

 
the Obligor, set off any matured obligation due from an Obligor under the Finance Documents (to the extent beneficially owned by that Finance Party) against any matured obligation owed by that Finance Party to that Obligor, regardless of the place of payment, booking branch or currency of either obligation. If the obligations are in different currencies, the Finance Party may convert either obligation at a market rate of exchange in its usual course of business for the purpose of the set-off.
 
36.     COSTS AND EXPENSES
 
36.1   Transaction expenses
 
Kosmos shall within fifteen Business Days of demand, pay the Facility Agent and each Mandated Lead Arranger the amount of all costs and expenses (including legal fees) reasonably incurred by any of them in connection with:
 
(A)               the negotiation, preparation, printing, and execution of:
 
(i)                       this Agreement and any other documents referred to in this Agreement; and
 
(ii)                    any other Finance Documents executed after the date of this Agreement;
 
(B)                 the appointments of the Consultants.
 
36.2   Amendment costs
 
If:
 
(A)               an Obligor requests an amendment, waiver or consent; or
 
(B)                 an amendment is required pursuant to clause 34.8 (Change of currency),
 
Kosmos shall, within fifteen Business Days of demand, reimburse the Facility Agent for the amount of all costs and expenses (including legal fees) reasonably incurred by the Facility Agent in responding to, evaluating, negotiating or complying with that request or requirement.
 
36.3   Enforcement costs
 
Kosmos shall, within five Business Days of demand, pay to each Finance Party the amount of all costs and expenses (including legal fees) incurred by that Finance Party in connection with the enforcement or attempted enforcement of, or the preservation of any rights under, any Finance Document.
 
141

 
37.     NOTICES
 
37.1   Communications in writing
 
Any communication to be made under or in connection with the Finance Documents shall be made in writing and, unless otherwise stated, may be made by fax or letter.
 
37.2   Addresses
 
The address and fax number (and the department or officer, if any, for whose attention the communication is to be made) of each Party for any communication or document to be made or delivered under or in connection with the Finance Documents is:
 
(A)               in the case of the Obligors, that identified with its name below;
 
(B)                 in the case of each Lender or any other Initial Obligor, that notified in writing to the Facility Agent on or prior to the date on which it becomes a Party; and
 
(C)                 in the case of an Agent, that identified with its name below,
 
or any substitute address or fax number or department or officer as the Party may notify to the Facility Agent (or the Facility Agent may notify to the other Parties, if a change is made by the Facility Agent) by not less than five Business Days’ notice.
 
Contact details of the Obligors:
 
To:	Copy:	
 	 	
P.O. Box 32322	 	
4th Floor Century Yard	c/o Kosmos Energy LLC	
Cricket Square	8176 Park Lane	
Elgin Avenue	Suite 500	
Georgetown	Dallas	
Grand Cayman	Texas 75231	
KY1 – 1209	USA	
Cayman Islands	 	
 	 	
Fax:	+1 345 946 4090	Fax: +1 214 445 9709	
 	 	 	
Attention:	W. Greg Dunlevy	Attention:	William S. Hayes	
 
142

 
Contact details of the Facility Agent:
 
Name: Phoi-Van Phuong
 
Email: phoi-van.phuong@bnpparibas.com
 
Address: BNP Paribas S.A., Paris
 
16, rue de Hanovre
 
75002 Paris (France)
 
Tel: + 33 1 42 98 10 95
 
Fax: + 33 1 42 98 49 25
 
37.3   Delivery
 
(A)               Subject to clause 37.5 (Electronic communication), any communication or document made or delivered by one person to another under or in connection with the Finance Documents will only be effective:
 
(i)                       if by way of fax, when received in legible form; or
 
(ii)                    if by way of letter, when it has been left at the relevant address or five Business Days after being deposited in the post with postage prepaid in an envelope addressed to it at that address;
 
and, if a particular department or officer is specified as part of its address details provided under clause 37.2 ( Addresses ), if addressed to that department or officer.
 
(B)                 Any communication or document to be made or delivered to either of the Facility Agent will be effective only when actually received by the Facility Agent and then only if it is expressly marked for the attention of the department or officer identified with the Facility Agent’s signature below (or any substitute department or officer as the Facility Agent shall specify for this purpose).
 
(C)                 All notices from or to an Obligor shall be sent through the Facility Agent.
 
(D)                Any communication or document made or delivered to Kosmos in accordance with this clause will be deemed to have been made or delivered to each of the Obligors.
 
143

 
37.4   Notification of address and fax number
 
Promptly upon receipt of notification of an address or fax number or change of address or fax number pursuant to clause 37.2 ( Addresses ) or changing its own address or fax number, the Facility Agent shall notify the other Parties.
 
37.5   Electronic communication
 
(A)               Any communication to be made between the Facility Agent and a Lender under or in connection with the Finance Documents may be made by electronic mail or other electronic means, if the Facility Agent and the relevant Lender:
 
(i)                       agree that, unless and until notified to the contrary, this is to be an accepted form of communication;
 
(ii)                    notify each other in writing of their electronic mail address and/or any other information required to enable the sending and receipt of information by that means; and
 
(iii)                 notify each other of any change to their address or any other such information supplied by them.
 
(B)                 Any electronic communication made between the Facility Agent and a Lender will be effective only when actually received in readable form and in the case of any electronic communication made by a Lender to the Facility Agent only if it is addressed in such a manner as the Facility Agent shall specify for this purpose.
 
37.6   English language
 
(A)               Any notice given under or in connection with any Finance Document must be in English.
 
(B)                 All other documents provided under or in connection with any Finance Document must be:
 
(i)                       in English; or
 
(ii)                    if not in English, and if so required by either of the Facility Agent, accompanied by a certified English translation and, in this case, the English translation will prevail unless the document is a constitutional, statutory or other official document.
 
38.     CALCULATIONS AND CERTIFICATES
 
38.1   Accounts
 
In any litigation or arbitration proceedings arising out of or in connection with a Finance Document, the entries made in the accounts maintained by a Finance Party are prima facie evidence of the matters to which they relate.
 
144

 
38.2   Certificates and determinations
 
Any certification or determination by a Finance Party of a rate or amount under any Finance Document is, in the absence of manifest or proven error, prima facie evidence of the matters to which it relates.
 
38.3   Day count convention
 
Any interest, commission or fee accruing under a Finance Document will accrue from day to day and is calculated on the basis of the actual number of days elapsed and a year of 360 days.
 
39.     PARTIAL INVALIDITY
 
If, at any time, any provision of the Finance Documents is or becomes illegal, invalid or unenforceable in any respect under any law of any jurisdiction, neither the legality, validity or enforceability of the remaining provisions nor the legality, validity or enforceability of such provision under the law of any other jurisdiction will in any way be affected or impaired.
 
40.     REMEDIES AND WAIVERS
 
No failure to exercise, nor any delay in exercising, on the part of any Finance Party, any right or remedy under the Finance Documents shall operate as a waiver, nor shall any single or partial exercise of any right or remedy prevent any further or other exercise or the exercise of any other right or remedy. The rights and remedies provided in this Agreement are cumulative and not exclusive of any rights or remedies provided by law.
 
41.     AMENDMENTS AND WAIVERS
 
41.1   Required consents
 
(A)               Subject to clause 41.2 (Exceptions) and to paragraph (C) below, any term of the Finance Documents (other than a waiver of a Condition Precedent or a Condition Subsequent, which shall be made pursuant to clause 2.3 ( Waivers of Conditions Precedent ) may be amended or waived only with the consent of the Majority Lenders and the Obligors and any such amendment or waiver will be binding on all Parties.
 
(B)                 The Facility Agent may effect, on behalf of any Finance Party, any amendment or waiver permitted by this clause.
 
(C)                 Notwithstanding the terms of this clause 41, in relation to an amendment, variation or waiver of the terms of the Intercreditor Agreement or the Security Documents, the terms of the Intercreditor Agreement shall prevail.
 
41.2   Exceptions
 
(A)               The following may not be effected without the consent of all the Lenders.
 
145

 
(i)                       amending the definition of “Majority Lenders””;
 
(ii)                    amending, varying or waiving clause 4 (Finance Parties’ Rights and Obligations) of this Agreement and/or any other term of any Finance Document which relates to the rights and/or obligations of each Finance Party being several;
 
(iii)                 varying the date for, or altering the amount or currency of, any payment to Lenders under the Finance Documents;
 
(iv)                increasing or extending the Commitment of a Lender;
 
(v)                   amending varying or waiving a term of any Finance Document which expressly requires the consent of all the Lenders; ;
 
(vi)                amending, varying or waiving this clause; or
 
(vii)             any release of Security Interests granted pursuant to any Security Document or amendment, waiver or variation of the obligations of any Obligor pursuant to Clause 25.1 ( Guarantee and Indemnity ). Nothing in this Clause (vii) shall require any consent to be obtained for any release of Security Interests, Security Documents (including but not limited to under releases made pursuant to Clause 28.8(C)) or obligations of any Obligor pursuant to Clause 25.1 ( Guarantee and Indemnity ), which are permitted by Clause 28.31 ( IPO Reorganisation ).
 
(B)                 An amendment of clause 19.6 (Calculation of Borrowing Base Amount) to reduce the figure of 1.5 or the figure of 1.3 may not be effected without the consent of the Majority Lenders.
 
(C)                 An amendment or waiver which relates to the rights or obligations of an Agent, an LC Issuing Bank or an Account Bank may not be effected without the consent of that Agent, LC Issuing Bank or an Account Bank.
 
(D)                An amendment or waiver which relates to clause 21.2 (Withdrawals — No Default Outstanding) or clause 25 ( Guarantee and Indemnity ) and the rights or obligations of a Hedging Counterparty may not be effected without the consent of each Hedging Counterparty.
 
(E)                  If a Lender (i) becomes a Non-Funding Lender or (ii) does not accept or reject a request for an amendment, waiver, consent or approval within fifteen Business Days (or such longer period as Kosmos may specify) of such request being made, that Lender’s Commitment shall not be included for the purposes of calculating Total Commitments under the Facility when ascertaining whether a certain percentage of Total Commitments has been obtained to approve the amendment, waiver, consent or approval, provided that (other than in the case of (i) above) no more than 25 per cent. of Lender votes (by Commitment) may be disregarded in such a way.
 
146

 
41.3   Exclusions
 
Subject to clause 41.2 (Exceptions), if a Lender does not accept or reject a request for an amendment or waiver within ten Business Days of receipt of such request (or such longer period as Kosmos and the Facility Agent may agree), or abstains from accepting or rejecting a request for an amendment or waiver, or if the Lender is a Non Funding Lender, its Commitments shall not be included for the purpose of calculating the Total Commitments when ascertaining whether the consent of a Lender or Lenders whose Commitments aggregate more than the required percentage of the Total Commitments has been obtained in respect of such request.
 
41.4   Disenfranchisement of Shareholder Affiliates
 
Notwithstanding any other provisions of this Agreement, for so long as a Shareholder Affiliate is a Lender and/or to the extent that a Shareholder Affiliate beneficially owns a Commitment or has entered into a sub-participation agreement relating to a Commitment or other agreement or arrangement having a substantially similar economic effect and such agreement or arrangement has not been terminated, such Shareholder Affiliate shall not be entitled to exercise any rights to vote as Lender in respect of any matters requiring decision by the Lenders under the terms of this Agreement or any of the Finance Documents. Each such Shareholder Affiliate acknowledges and agrees that:
 
(A)               in the event that a matter requires decision by one or more Lenders under this Agreement or any of the Finance Documents,
 
(i)                       the Commitment of such Shareholder Affiliate and any associated participation of such Shareholder Affiliate in a Loan shall be deemed to be zero; and
 
(ii)                    such Shareholder Affiliate shall be deemed not to be a Lender;
 
(B)                 in relation to any meeting or conference call to which all or any number of Lenders are invited to attend or participate, it shall not attend or participate in the same if so requested by the Facility Agent or, unless the Facility Agent otherwise agree, be entitled to receive the agenda or any minutes of the same; and
 
(C)                 it shall not, unless the Facility Agent otherwise agree, be entitled to receive any report or other document prepared at the behest of, or on the instructions of, the Facility Agent or one or more of the Lenders.
 
42.     COUNTERPARTS
 
(A)               This Agreement may be executed in any number of counterparts, and by the parties on separate counterparts, but shall not be effective until each Party has executed at least one counterpart.
 
(B)                 Each counterpart shall constitute an original of this Agreement, but all the counterparts shall together constitute one and the same instrument.
 
147

 
PART 13
GOVERNING LAW AND ENFORCEMENT
 
43.     GOVERNING LAW
 
This Agreement shall be governed by and construed in accordance with English law.
 
44.     JURISDICTION
 
44.1   Submission
 
The parties hereby irrevocably agree for the exclusive benefit of the Secured Parties that the courts of England shall have exclusive jurisdiction to settle any dispute arising out of or in connection with this Agreement (including a dispute regarding the existence, validity or termination of this Agreement) (a “ Dispute ”).
 
44.2   Forum convenience
 
The parties hereby irrevocably agree that the courts of England are the most appropriate and convenient courts to settle Disputes and accordingly irrevocably agree not to argue to the contrary.
 
44.3   Concurrent jurisdiction
 
This clause 44 is for the benefit of the Secured Parties only. As a result, no Secured Party shall be prevented from taking proceedings relating to a Dispute in any other courts with jurisdiction. To the extent allowed by law, the Secured Parties may take concurrent proceedings in any number of jurisdictions.
 
45.     SERVICE OF PROCESS
 
(A)               Without prejudice to any other mode of service allowed under any relevant law, each of the Obligors:
 
(i)                       irrevocably appoints Trusec Limited of 2 Lambs Passage, London EC1Y 8BB (the “Process Agent ”) as its agent for service of process in relation to any Dispute before the English courts in connection with any Finance Document;
 
(ii)                    irrevocably agrees that any Service Document may be sufficiently and effectively served on it in connection with any Dispute in England and Wales by service on the Process Agent (or any replacement agent appointed pursuant to paragraph (B) of this clause 45 ( Service of Process ); and
 
(iii)                 irrevocably agrees that failure by a process agent to notify the relevant Obligor of the process will not invalidate the proceedings concerned.
 
(B)                 If the agent referred to in paragraph (A) of this clause 45 (or any replacement agent appointed pursuant to this paragraph (B)) at any time ceases for any
 
148

 
reason to act as such, as the case may be, each Obligor shall as soon as reasonably practicable appoint a replacement agent to accept service having an address for service in England or Wales and shall notify the Facility Agent of the name and address of the replacement agent; failing such appointment and notification, the agent referred to in paragraph (A) of this clause 45 (or any replacement agent appointed pursuant to this paragraph (B)) shall continue to be authorised to act as agent for service of process in relation to any proceedings before the English courts on behalf of the relevant party and shall constitute good service.
 
(C)                 Any document addressed in accordance with clause 45 paragraph (A) shall be deemed to have been duly served if:
 
(i)                       left at the specified address, when it is left; or
 
(ii)                    sent by first class post, two clear Business Days after posting.
 
(D)                For the purposes of this clause 45, “Service Document” means a writ, summons, order, judgment or other document relating to or in connection with any Dispute. Nothing contained herein shall affect the right to serve process in any other manner permitted by law.
 
This Agreement has been entered into on the date stated at the beginning of this Agreement.
 
149

 
Schedule 1
The Initial Obligors
 
The Original Borrowers
 
Name	 	Jurisdiction of Incorporation	 	Registered Number	
 	 	 	 	 	
Kosmos Energy Finance International	 	Cayman Islands	 	253656	
 
The Original Guarantors
 
Name	 	Jurisdiction of Incorporation	 	Registered Number	
 	 	 	 	 	
Kosmos Energy Operating	 	Cayman Islands	 	231417	
 	 	 	 	 	
Kosmos Energy International	 	Cayman Islands	 	218274	
 	 	 	 	 	
Kosmos Energy Development	 	Cayman Islands	 	225879	
 	 	 	 	 	
Kosmos Energy Ghana HC	 	Cayman Islands	 	135710	

 
Schedule 2
The Original Lenders
 
Original Lender	 	Commitment (USD)	
ABSA CAPITAL (A DIVISION OF ABSA BANK LIMITED)	 	307,333,333.33	
BARCLAYS BANK PLC	 	26,000,000	
BNP PARIBAS	 	333,333,333.33	
CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANK	 	333,333,333.33	
HSBC BANK PLC	 	333,333,333.33	
SOCIÉTÉ GÉNÉRALE LONDON BRANCH	 	333,333,333.35	
STANDARD CHARTERED BANK	 	333,333,333.33	

 
Schedule 3
Conditions Precedent
 
Part I
 
Conditions Precedent To first Utilisation
 
1.                         Provision of each of the following Finance Documents, duly executed by each of the parties to them (subject, in the case of the relevant Security Document, to the Lenders having agreed to the requirements of subordination in relation to any Security created in respect of a Project Agreement):
 
(i)                      this Agreement;
 
(ii)                   any Intercompany Loan Agreement;
 
(iii)                the KEG Offshore Project Accounts Agreement;
 
(iv)               the Borrower Offshore Project Accounts Agreement;
 
(v)                  the KEG Onshore Project Accounts Agreement;
 
(vi)               the Intercreditor Agreement;
 
(vii)            the Charge over Shares in the Original Borrower;
 
(viii)         the Charge over Shares in KEO;
 
(ix)                 the Charge over Shares in KEG;
 
(x)                    the Charge over Shares in KED;
 
(xi)                 the Charge over Shares in KEI;
 
(xii)              the Borrower Offshore Security Assignment;
 
(xiii)           the KEO Offshore Security Assignment;
 
(xiv)          the KEI Offshore Security Assignment;
 
(xv)             the KED Offshore Security Assignment;
 
(xvi)          the KEG Offshore Security Assignment;
 
(xii)              the KEG Onshore Security Assignment;
 
(xiii)           the KEI and KEO Offshore Security Assignment;
 
(xix)            the Facility Agent Fee Letter;

 
(xx)               the front end and underwriting Fee Letter;
 
(xxi)            the Technical Bank Fee Letters;
 
(xxii)         the Modelling Bank Fee Letters;
 
(xxiii)      the Security Agent Fee Letter;
 
(xxiv)     the Documentation Bank Fee Letter; and
 
(xxv)        the BNP Paribas LC Issuing Fee Letter.
 
2.                         Provision of certified copies of each Obligor’s constitutional documents and corporate resolutions authorising entry into and performance of the Finance Documents to which they are a party and certification as to solvency.
 
3.                         Receipt by the Facility Agent of appropriate legal opinions from Clifford Chance LLP, Walkers, Fugar & Company, Maples & Calder, Thompson & Knight and Bentsi-Enchill, Letsa & Ankomah.
 
4.                         Final Reports and/or letters issued by the Consultants (provided that there is only an obligation to provide an executive summary of the Final Report from the Technical Consultant as a condition precedent to first Utilisation).
 
5.                         Provision of a certificate from the Borrower that all Required Approvals on the date of the proposed utilisation have been obtained (including a schedule of all such Required Approvals).
 
6.                         Provision of a certificate in the agreed form certifying that complete copies of the following Project Agreements, including all amendments in relation thereto, have been delivered to the Agents under the Existing Finance Documents pursuant to the terms of the CTA (as defined in the Definitions Agreement):
 
(i) the DWT PA;
 
(ii)                the DWT JOA;
 
(iii)               the WCTP PA; and
 
(iv)              the WCTP JOA,
 
together with certified copies of all other Project Agreements not referred to in paragraphs (i) to (iv) (inclusive) above (including, for the avoidance of doubt and without limitation, those documents listed under paragraphs (C), (D) and (E) of the definition of Project Agreements).
 
7.                         An audit of the Model prepared by the Model Auditor.
 
8.                         All share charges are entered into pursuant to condition precedent 1 above are perfected and fully valid and, where applicable (by adopting a consistent approach as
 
153

 
was adopted for the Existing Finance Documents): (a) share certificates and blank stock transfer forms are delivered to the Security Agent; (b) certified copy registers of members are delivered to the Security Agent in relation to companies whose shares have been pledged; and (c) letter of undertaking from the Company whose shares are being charged.
 
9.        Each Obligor (save for the Original Borrower and KEO) shall provide a certified copy of its most recent audited accounts, if any, and KEO shall provide a copy of the Form S-1 filed by Kosmos Energy Ltd. with the United States Securities and Exchange Commission on 23 March 2011, which includes the most recent audited consolidated accounts of the Group.
 
10.      The Schedule of Insurances.
 
11.      The following documents for release of the Security Interests (as defined in the Existing Finance Documents ) created by under the Existing Finance Documents, in the form agreed by the Security Trustee (as defined in the Existing Finance Documents):
 
·        deed of release between KEH, KEO, KEI, KED and BNP PARIBAS, as security trustee, releasing the security created by the existing charges over shares;
 
·        deed of release between KED, Kosmos Energy Finance, KEG and KEO and BNP Paribas, as security trustee, releasing the security created by the existing debentures;
 
·        deed of release between KEI, KEO and BNP Paribas, as security trustee, releasing the secured property under the existing security assignment;
 
154

 
·        Part II
 
Conditions Precedent Required to be Delivered by an Additional Obligor
 
1.        Provision of an Accession Letter, duly executed by the Additional Obligor and the Borrower.
 
2.        Provision of a Deed of Subordination in respect of any Financial Indebtedness of such Additional Obligor and a deed, duly signed on behalf of the Additional Obligor and each other Obligor and KEH, substantially in the form of the Deed of Acknowledgment and Release.
 
3.        Provision of certified copies of the Additional Obligor’s constitutional documents and certificates of incorporation (or equivalent).
 
4.        A copy of a resolution of the board of directors of the Additional Obligor approving the terms of, and the transactions contemplated by, the Accession Letter and the Finance Documents and resolving that one or more specified persons execute the Accession Letter and any other documents and notices in connection with the Finance Documents.
 
5.        A specimen signature of each person authorised to execute the Accession Letter and any other documents and notices in connection with the Finance Documents.
 
6.        A certificate of the Additional Obligor (signed by a director) confirming that borrowing or guaranteeing or securing, as appropriate, the Total Commitments would not cause any borrowing, guarantee, security or similar limit binding on it to be exceeded.
 
7.        A certificate of an Authorised Signatory of the Additional Obligor certifying that each copy document listed in this Part II of Schedule 3 is correct, complete and in full force and effect as at a date no earlier than the date of the Accession Letter.
 
8.        A copy of any other Authorisation or other document, opinion or assurance which the Facility Agent considers to be necessary or desirable in connection with the entry into and performance of the transactions contemplated by the Accession Letter or for the validity and enforceability of any Finance Document.
 
9.        If available, the latest audited financial statements of the Additional Obligor.
 
10.      Receipt by the Facility Agent of any appropriate legal opinions.
 
11.      If the proposed Additional Obligor is incorporated in a jurisdiction other than England and Wales, evidence that the process agent specified in clause 45 ( Service of Process ), if not an Obligor, has accepted its appointment in relation to the proposed Additional Obligor.
 
155

 
Schedule 4
Utilisation Requests
 
Part I
Loans
 
From:	Kosmos Energy Finance International (the “Borrower”)	
 	 	
To:	BNP PARIBAS(the “Facility Agent”)	
 
Dated:
 
Dear Sirs
 
Kosmos Energy Finance International — Facility Agreement
dated [              ] (the “Agreement”)
 
1.        We refer to the Agreement. This is a Utilisation Request in respect of a Utilisation under the Facility. Terms defined in the Agreement have the same meaning in this Utilisation Request unless given a different meaning in this Utilisation Request.
 
2.        We wish to borrow a Loan under the Facility on the following terms:
 
Proposed Utilisation Date:	 	[             ] (or, if that is not a Business Day, the next Business Day)	
 	 	 	
Amount:	 	[             ] under or, if less, the Total Available Commitment	
 	 	 	
Amount attributable to Interest payments	 	[             ]	
 	 	 	
Interest Period:	 	[             ]	
 
3.        We hereby certify that:
 
(a)	 	no Default or Event of Default is continuing or will result from the proposed Loan;	
 	 	 	
(b)	 	the Loan is expected to be applied in payment of amounts subject to and in accordance with the Cash Waterfall within 90 days of the Utilisation Date or are otherwise required for Kosmos to comply with clause 20.1 ( Project Accounts ) of this Agreement;	
 	 	 	
(d)	 	the making of the Utilisation would not result in the aggregate principal amount outstanding under the Facility exceeding the Borrowing Base Amount; and	
 	 	 	
(e)	 	the Repeating Representations are, in the light of the facts and circumstances then existing, true and correct in all material respects (or, in the case of a	

 
Repeating Representation that contains a materiality concept, true and correct in all respects).
 
4.        The proceeds of this Loan should be credited to the [Borrower/other] Offshore Proceeds Account and to the extent an amount has been attributed to Interest payments above, such amount shall be applied towards the payment of Interest on the Facility.
 
5.        This Utilisation Request is irrevocable and is a Finance Document.
 
 	Yours faithfully	 	

 	 	 	
 	Authorised Signatory for
Kosmos Energy Finance International	 	
 
157

 
Part II
Letters of Credit
 
From:	[·] (the “Borrower”)	
 	 	
To:	BNP PARIBAS(the “Facility Agent”)	
 	 	
 	[·] (the “LC Issuing Bank”)	
 
Dated:
 
Dear Sirs
 
Kosmos Energy Finance International — Facility Agreement
dated [                   ]
(the “Agreement”)
 
1.        We wish to arrange for a Letter of Credit to be issued by the LC Issuing Bank on the following terms:
 
Proposed Utilisation Date:	 	[             ] (or, if that is not a Business Day, the next Business Day)	
 	 	 	
Total Amount:	 	[             ] or, if less, the Total Commitments	
 	 	 	
Beneficiary:	 	[             ]	
 	 	 	
Term or Expiry Date:	 	[             ]	
 
2.        We hereby certify that each condition specified in clause 7.6 (Issue of Letters of Credit) is satisfied on the date of this Utilisation Request.
 
3.        We attach a copy of the proposed Letter of Credit.
 
4.        This Utilisation Request is irrevocable and is a Finance Document.
 
Delivery Instructions:
 
[specify delivery instructions]
 
 	Yours faithfully	 	

 	 	 	
 	Authorised Signatory for
Kosmos Energy Finance International	 	
 
158

 
Schedule 5
Amortisation Schedule
 
 	 	Amortisation Amount	 	Revised Total Facility Amount	
Repayment Date	 	(USD)	 	(USD)	
 	 	 	 	 	
15/06/11	 	0	 	2,000,000,000	
 	 	 	 	 	
15/12/11	 	0	 	2,000,000,000	
 	 	 	 	 	
15/06/12	 	0	 	2,000,000,000	
 	 	 	 	 	
15/12/12	 	0	 	2,000,000,000	
 	 	 	 	 	
15/06/13	 	0	 	2,000,000,000	
 	 	 	 	 	
15/12/13	 	0	 	2,000,000,000	
 	 	 	 	 	
15/06/14	 	333,333,333	 	1,666,666,667	
 	 	 	 	 	
15/12/14	 	222,222,222	 	1,444,444,445	
 	 	 	 	 	
15/06/15	 	222,222,222	 	1,222,222,223	
 	 	 	 	 	
15/12/15	 	222,222,222	 	1,000,000,001	
 	 	 	 	 	
15/06/16	 	222,222,222	 	777,777,779	
 	 	 	 	 	
15/12/16	 	222,222,222	 	555,555,557	
 	 	 	 	 	
15/06/17	 	222,222,222	 	333,333,335	
 	 	 	 	 	
15/12/17	 	222,222,222	 	111,111,113	
 	 	 	 	 	
15/03/18	 	111,111,113	 	—	
 
159

 
Schedule 6
Mandatory Cost Formulae
 
1.        The Mandatory Cost is an addition to the interest rate to compensate Lenders for the cost of compliance with (a) the requirements of the Bank of England (and/or the Financial Services Authority (or, in either case, any other Authority which replaces all or any of its functions) or (b) the requirements of the European Central Bank.
 
2.        On the first day of each Interest Period (or as soon as possible thereafter) the Facility Agent shall calculate, as a percentage rate, a rate (the “ Additional Cost Rate ”) for each Lender, in accordance with the paragraphs set out below. The Mandatory Cost will be calculated by the Facility Agent as a weighted average of the Lenders’ Additional Cost Rates (weighted in proportion to the percentage participation of each Lender in the relevant Loan) and will be expressed as a percentage rate per annum.
 
3.        The Additional Cost Rate for any Lender lending from a Facility Office in a Participating Member State will be the percentage notified by that Lender to the Facility Agent. This percentage will be certified by that Lender in its notice to that Facility Agent to be its reasonable determination of the cost (expressed as a percentage of that Lender’s participation in all Loans made from that Facility Office) of complying with the minimum reserve requirements of the European Central Bank in respect of loans made from that Facility Office.
 
4.        The Additional Cost Rate for any Lender lending from a Facility Office in the United Kingdom will be calculated by the Facility Agent as follows:
 
(a)      in relation to a sterling Loan:
 
AB + C ( B–D )[ +E ]x0.01	  per cent. per annum	 	 	
100–(A+C)	 	 	 	
 
(b)     in relation to a Loan in any currency other than sterling:
 
Ex0.01	  per cent. per annum	 	 	
300	 	 	 	
 
Where:
 
A       is the percentage of Eligible Liabilities (assuming these to be in excess of any stated minimum) which that Lender is from time to time required to maintain as an interest-free cash ratio deposit with the Bank of England to comply with cash ratio requirements.
 
B        is the percentage rate of interest (excluding the Margin and the Mandatory Cost and, if the Loan is an Unpaid Sum, the additional rate of interest specified in paragraph (A) of clause 11.4 ( Default interest )) payable for the relevant Interest Period on the Loan.

 
C        is the percentage (if any) of Eligible Liabilities which that Lender is required from time to time to maintain as interest-bearing Special Deposits with the Bank of England.
 
D       is the percentage rate per annum payable by the Bank of England to the Facility Agent on interest-bearing Special Deposits.
 
E        is designed to compensate Lenders for amounts payable under the Fees Rules and is calculated by the Facility Agent as being the average of the most recent rates of charge supplied by the Reference Banks to that Facility Agent pursuant to paragraph 7 below and expressed in pounds per £1,000,000.
 
5.        For the purposes of this Schedule:
 
(A)    “Eligible Liabilities” and “Special Deposits” have the meanings given to them from time to time under or pursuant to the Bank of England Act 1998 or (as may be appropriate) by the Bank of England.
 
(B)     “Fees Rules” means the rules on periodic fees contained in the FSA Supervision Manual or such other law or regulation as may be in force from time to time in respect of the payment of fees for the acceptance of deposits.
 
(C)     “Fee Tariffs” means the fee tariffs specified in the Fees Rules under activity group A.1 Deposit acceptors (ignoring any minimum fee or zero-rated fee required pursuant to the Fees Rules but taking into account any applicable discount rate); and
 
(D)     “Tariff Base” has the meaning given to it in, and will be calculated in accordance with, the Fees Rules.
 
6.        In application of the above formulae, A, B, C and D will be included in the formulae as percentages (i.e. 5 per cent. will be included in the formula as 5 and not as 0.05). A negative result obtained by subtracting D from B shall be taken as zero. The resulting figures shall be rounded to four decimal places.
 
7.        If requested by the Facility Agent, each Reference Bank shall, as soon as practicable after publication by the Financial Services Authority, supply to that Facility Agent, the rate of charge payable by that Reference Bank to the Financial Services Authority pursuant to the Fees Rules in respect of the relevant financial year of the Financial Services Authority (calculated for this purpose by that Reference Bank as being the average of the Fee Tariffs applicable to that Reference Bank for that financial year) and expressed in pounds per £1,000,000 of the Tariff Base of that Reference Bank.
 
8.        Each Lender shall supply any information required by the Facility Agent for the purpose of calculating its Additional Cost Rate. In particular, but without limitation, each Lender shall supply the following information on or prior to the date on which it becomes a Lender:
 
161

 
(A)    the jurisdiction of its Facility Office; and
 
(B)     any other information that the Facility Agent may reasonably require for such purpose.
 
Each Lender shall promptly notify the Facility Agent of any change to the information provided by it pursuant to this paragraph.
 
9.        The percentages of each Lender for the purpose of A and C above and the rates of charge of each Reference Bank for the purpose of E above shall be determined by the Facility Agent based upon the information supplied to it pursuant to paragraphs 7 and 8 above and on the assumption that, unless a Lender notifies the Facility Agent to the contrary, each Lender’s obligations in relation to cash ratio deposits and Special Deposits are the same as those of a typical bank from its jurisdiction of incorporation with a Facility Office in the same jurisdiction as its Facility Office.
 
10.      The Facility Agent shall have no liability to any person if such determination results in an Additional Cost Rate which over or under compensates any Lender and shall be entitled to assume that the information provided by any Lender or Reference Bank pursuant to paragraphs 3, 7 and 8 above is true and correct in all respects.
 
11.      The Facility Agent shall distribute the additional amounts received as a result of the Mandatory Cost to the Lenders on the basis of the Additional Cost Rate for each Lender based on the information provided by each Lender and each Reference Bank pursuant to paragraphs 3, 7 and 8 above.
 
12.      Any determination by the Facility Agent pursuant to this Schedule in relation to a formula, the Mandatory Cost, an Additional Cost Rate or any amount payable to a Lender shall, in the absence of manifest or proven error, be conclusive and binding on all Parties.
 
13.      The Facility Agent may from time to time, after consultation with Kosmos and the Lenders, determine and notify to all Parties any amendments which are required to be made to this Schedule in order to comply with any change in law, regulation or any requirements from time to time imposed by the Bank of England or the Financial Services Authority or the European Central Bank (or, in any case, any other Authority which replaces all or any of its functions) and any such determination shall, in the absence of manifest or proven error, be conclusive and binding on all Parties.
 
162

 
Schedule 7
Form of Transfer Certificate
 
To:	BNP PARIBASas (the “ Facility Agent”)	
 	 	
From:	[The Existing Lender] (the “Existing Lender”) and [The New Lender] (the “New Lender”)	
 
Dated:
 
Dear Sirs
 
Kosmos Energy Finance International — Facility Agreement
dated [                ] (the “Agreement”)
 
1.        We refer to the Agreement. This is a Transfer Certificate. Terms defined in the Agreement have the same meaning in this Transfer Certificate unless given a different meaning in this Transfer Certificate.
 
2.        We refer to clause 30.5 (Procedure for transfer):
 
(A)    The Existing Lender and the New Lender agree to the Existing Lender transferring to the New Lender by novation all or part of the Existing Lender’s Commitment, rights and obligations referred to in the Schedule in accordance with clause 30.5 ( Procedure for transfer ).
 
(B)     The proposed Transfer Date is [                               ].
 
(C)     The Facility Office and address, fax number and attention details for notices of the New Lender for the purposes of clause 37.2 ( Addresses ) are set out in the Schedule.
 
3.        The New Lender expressly acknowledges the limitations on the Existing Lender’s obligations set out in paragraph (C) of clause 30.4 ( Limitation of responsibility of Existing Lenders ).
 
4.        The New Lender confirms that it is a Qualifying Lender.
 
5.        This Transfer Certificate may be executed in any number of counterparts and this has the same effect as if the signatures on the counterparts were on a single copy of this Transfer Certificate.
 
6.        This Transfer Certificate is governed by English law.
 
163

 
THE SCHEDULE
 
Commitments/rights and obligations to be transferred
 
[Insert relevant details]
 
[Facility Office address, fax number and attention details for notices and account details for payments]
 
[Existing Lender]	 	[New Lender]	
 	 	 	
By:	 	 	By:	 	

This Transfer Certificate is accepted by the Facility Agent and the Transfer Date is confirmed as [            ].
 
BNP PARIBAS	 	 	
 	 	 	
By: 	 	 	 	

164

 
Schedule 8
Form of Lender Accession Notice

To:	BNP PARIBASas Facility Agent	
 	 	
From:	[Additional Lender]	
 
Dated:

Dear Sirs,
 
Kosmos Energy Finance International - Facility Agreement
dated                  (the “Agreement”)
 
1.                         We refer to the Agreement and the Facility Agreement. This is a Lender Accession Notice. Terms defined in the Facility Agreement relating to the Agreement have the same meaning in this Lender Accession Notice unless given a different meaning in this Lender Accession Notice.
 
2.                         [Additional Lender] agrees:
 
(a)                   to be bound by the terms of the Agreement as a Lender pursuant to clause [3.3] (Additional Commitment) of the Agreement; and
 
(b)                  to be bound by the terms of the Intercreditor Agreement as a [Lender/ Creditor].
 
3.                         [Additional Lender]’s Additional Commitment is USD [                  ].
 
4.                         [Additional Lender’s] administrative details are as follows:
 
Account details:	 	[                                   ]	
 	 	 	
Facility Office Address:	 	[                                   ]	
 	 	 	
Telephone No.:	 	[                                   ]	
 	 	 	
Fax No.:	 	[                                   ]	
 	 	 	
Attention:	 	[                                   ]	
 
5.                         This Lender Accession Notice is governed by English law.
 
6.                         This Lender Accession Notice has been delivered as a deed on the date stated at the beginning of this Lender Accession Notice.
 
165

 
[Additional Lender]
 
By:

This Lender Accession Notice is accepted by the Facility Agent and the Commitment Commencement Date is confirmed as [                       ].
 
BNP PARIBAS	 	
 	 	
By:	 	 	

166

 
Schedule 9
Form of Accession Letter
 
From:	[name of subsidiary] (the “Company”) and Kosmos Energy Finance International (the “ Borrower ”)	
 	 	
To:	BNP PARIBAS(the “Facility Agent”)	
 
Dated:
 
Dear Sirs
 
Kosmos Energy Finance International — Facility Agreement
dated [               ] (the “Agreement”)
 
1.                         We refer to the Agreement. This is an Accession Letter. Terms defined in the Agreement have the same meaning in this Accession Letter unless given a different meaning in this Accession Letter.
 
2.                         The Company agrees to become an Additional [Borrower]/[Guarantor] and to be bound by the terms of the Agreement as an Additional [Borrower]/[Guarantor] pursuant to clause [31.2 ( Additional Borrowers )]/[31.4 ( Additional Guarantor )] of the Agreement. The Company is a company duly incorporated under the laws of [ name of relevant jurisdiction ].
 
3.                         The Company’s administrative details are as follows:
 
Address:	
 	
Fax No:	
 	
Attention:	
 
4.                         This Accession Letter is governed by English law.
 
This Accession Letter is entered into by deed.

 	 	 	
[Borrower]	 	Kosmos Energy Finance International	

 
Schedule 10
Form of Resignation Letter
 
From:	[resigning Obligor] and Kosmos Energy Finance International	
 	 	
To:	BNP PARIBAS(the “Facility Agent”)	
 
Dated:
 
Dear Sirs
 
Kosmos Energy Finance International — Facility Agreement
dated [               ] (the “Agreement”)
 
1.                         We refer to the Agreement. This is a Resignation Letter. Terms defined in the Agreement have the same meaning in this Resignation Letter unless given a different meaning in this Resignation Letter.
 
2.                         Pursuant to clause [31.3 (Resignation of a Borrower)] of the Agreement, we request that [resigning Obligor] be released from its obligations as a Borrower under the Agreement.
 
3.                         We confirm that:
 
(a)                   no Default is continuing or would result from the acceptance of this request; and
 
(b)                  [                     ].
 
4.                         This Resignation Letter is governed by English law.

 	 	 	
[resigning Obligor]	 	Kosmos Energy Finance International	
 
168

 
Schedule 11
Form of Compliance Certificate
 
To:	BNP PARIBASas (the “Facility Agent”)	
 	 	
From:	Kosmos Energy Finance International (the “Borrower”)	
 
Date:
 
Dear Sirs
 
Kosmos Energy Finance International — Facility Agreement
dated [               ] (the “Agreement”)
 
1.                         We refer to the Agreement. This is Compliance Certificate. Terms defined in the Agreement have the same meaning in this Compliance Certificate unless given a different meaning in this Compliance Certificate.
 
2.                         We confirm that as at [               ], being the last occurring Forecast Date:
 
(A)               the Field Life Cover Ratio was [                ]; and
 
(B)                 the Loan Life Cover Ratio was [                ],
 
 in each case, as demonstrated by the current Forecast Assumptions.
 
3.                         We set out below the calculations establishing the figures in paragraph 2 above:
 
                                  [                       ]
 
4.                         We confirm that as at [               ], so far as we are aware having made diligent enquiries, no Default has occurred or is continuing. (1)
 
5.                         The balance of each Debt Service Reserve Account is as follows:
 
                                  [                       ]

(1)                   Note — If this statement cannot be made, the certificate should identify any Default that has occurred or is continuing and the action taken, or proposed to be taken, to remedy it.
 
169

 
 	 	Yours faithfully	 	 	

 	 	 	 	 	
Authorised Signatory for	 	 	 	Authorised Signatory for	
Kosmos Energy Finance International	 	 	 	Kosmos Energy Finance International	
 
170

 
Schedule 12
Form of Letter of Credit
 
To:	[Beneficiary] (the “Beneficiary”)	
 
Date:
 
Irrevocable Standby Letter of Credit no.[            ]
 
At the request and for the account of [                                ], [LC Issuing Bank] (the “LC Issuing Bank”) hereby establishes in your favour this irrevocable standby letter of credit (“ Letter of Credit ”) not exceeding the Total L/C Amount on the following terms and conditions:
 
1.                        Definitions
 
In this Letter of Credit:
 
“Business Day” means a day (other than a Saturday or a Sunday) on which banks are open for general business in London.
 
“Demand” means a demand for a payment under this Letter of Credit in the form of the schedule to this Letter of Credit.
 
“Expiry Date” means [                                   ].
 
“Total L/C Amount” means an aggregate amount not to exceed $[·] (USD [insert amount in words] only).
 
2.                        LC Issuing Bank’s agreement
 
(A)               The Beneficiary may request a drawing or drawings under this Letter of Credit by giving to the LC Issuing Bank a duly completed Demand. A Demand must be received by the LC Issuing Bank by [        ] p.m. (London time) on the Expiry Date. Multiple drawings are permitted.
 
(B)                 Subject to the terms of this Letter of Credit, the LC Issuing Bank unconditionally and irrevocably undertakes to the Beneficiary that, within [ten] Business Days of receipt by it of a Demand, it shall pay to the Beneficiary the amount demanded in that Demand.
 
(C)                 The LC Issuing Bank will not be obliged to make a payment under this Letter of Credit if as a result the aggregate of all payments made by it under this Letter of Credit would exceed the Total L/C Amount.
 
3.                        Expiry
 
(A)               The LC Issuing Bank will be released from its obligations under this Letter of Credit on the date (if any) notified by the Beneficiary to the LC Issuing Bank as
 
171

 
the date upon which the obligations of the LC Issuing Bank under this Letter of Credit are released.
 
(B)                 Unless previously released under paragraph (a) above, on [                     ] p.m. ([London] time) on the Expiry Date the obligations of the LC Issuing Bank under this Letter of Credit will cease with no further liability on the part of the LC Issuing Bank except for any Demand validly presented under the Letter of Credit that remains unpaid.
 
(C)                 When the LC Issuing Bank is no longer under any further obligations under this Letter of Credit, the Beneficiary must return the original of this Letter of Credit to the LC Issuing Bank.
 
4.                        Payments
 
All payments under this Letter of Credit shall be made in [                  ] and for value on the due date to the account of the Beneficiary specified in the Demand.
 
5.                        Delivery of Demand
 
Each Demand shall be in writing, and, unless otherwise stated, may be made by letter, by registered mail or by courier on your letterhead, with the blanks appropriately completed, purportedly signed by your authorised officers bearing original handwritten signatures and must be received in legible form by the LC Issuing Bank at its address and by the particular department or officer (if any) as follows:
 
[ ]
 
6.                        Assignment
 
The Beneficiary’s rights under this Letter of Credit may not be assigned or transferred.
 
7.                        Amendment
 
The Letter of Credit may be amended only by written instrument signed by the LC Issuing Bank and the Beneficiary.
 
8.                        ISP 98
 
Except to the extent it is inconsistent with the express terms of this Letter of Credit, this Letter of Credit is subject to the International Standby Practices (ISP 98), International Chamber of Commerce Publication No. 590.
 
9.                        Governing Law
 
This Letter of Credit is governed by English law.
 
172

 
10.                 Jurisdiction
 
The courts of England have exclusive jurisdiction to settle any dispute arising out of or in connection with this Letter of Credit.
 
 	Yours faithfully,	 	

 	[LC Issuing Bank]	 	
 	 	 	
 	 	By:	 	

 	 	 	 	 	
 
SCHEDULE
 
FORM OF DEMAND
 
To:	[LC Issuing Bank]	
 
Date:
 
Dear Sirs
 
Standby Letter of Credit no. [             ] issued in favour of [BENEFICIARY] (the “Letter of Credit”)
 
We refer to the Letter of Credit. Terms defined in the Letter of Credit have the same meaning when used in this Demand.
 
1.                         We certify that the sum of [             ] is due [and has remained unpaid for at least [             ] Business Days] [under [set out underlying contract or agreement]]. We therefore demand payment of the sum of [               ].
 
2.                         The amount specified in paragraph 1 is not in excess of the Total L/C Amount.
 
3.                         Payment should be made to the following account:
 
Name:
 
Account Number:
 
Bank:
 
173

 
4.        The date of this Demand is not later than the Expiry Date.

Yours faithfully	 	 	

(Authorised Signatory)	 	(Authorised Signatory)	
 	 	 	
For	 	 	
 	 	 	
[BENEFICIARY]	 	 	
 
174

 
Schedule 13
Form of Confidentiality Undertaking
 
To:         [insert details of lender]

Re:
 
Kosmos Energy Finance International (the “Company”) and its USD 2 billion reserves based loan facility dated [                 ] 2011 (the “ Facility ”)
 
[insert date]
 
Dear Sirs
 
We understand that you are considering participating in the Facility. In consideration of us agreeing to make available to you certain information, by your signature of a copy of this letter you agree as follows:
 
1.        Confidentiality Undertaking:You undertake:
 
(A)    to keep the Confidential Information confidential and not to disclose it to anyone except as provided for by paragraph 2 below and to ensure that the Confidential Information is protected with security measures with a degree of care not less than that which you would apply to your own confidential information;
 
(B)     to keep confidential and not disclose to anyone except as provided for by paragraph 2 below the fact that the Confidential Information has been made available or that discussions or negotiations are taking place or have taken place between us;
 
(C)     to use the Confidential Information only for the Permitted Purpose;
 
(D)     to ensure that any person to whom you pass any Confidential Information in accordance with paragraph 2 (unless disclosed under paragraph 2(B) below) acknowledges and complies with the provisions of this letter as if that person were also a party to it; and
 
(E)     not to make enquiries in relation to the Confidential Information of any other person, whether a third party or any member of the Group or any of their officers, directors, employees or professional advisers, save for such officers, directors, employees or professional advisers as may be expressly nominated by us for this purpose, provided that this paragraph shall not prevent or restrict you from conducting and completing all necessary and appropriate due diligence in accordance with your normal credit and underwriting approval processes and as required to be performed in order to obtain any requisite credit or underwriting approvals in relation to your possible participation in the Facility.
 
175

 
2.        Permitted Disclosure:We agree that you may disclose Confidential Information:
 
(A)    to members of the Participant Group and their officers, directors, employees, consultants and professional advisers but only to the extent necessary for the proper fulfilment of the Permitted Purpose, provided that:
 
(i)       such information is disclosed strictly on a need to know basis and provided that the Confidential Information may not be disclosed to any person in the Participant Group who is not working directly on matters concerning your participation in the Facility; and
 
(ii)      appropriate information barriers or other procedures as may be necessary are in place to ensure there can be no unauthorised disclosure of, or access to, the Confidential Information to any such person referred to in subparagraph (i) above;
 
(B)     (i) where required by any court of competent jurisdiction or any competent judicial, governmental, supervisory or regulatory body, (ii) where required by the rules of any stock exchange on which the shares or other securities of any member of the Participant Group are listed or (iii) where required by the laws or regulations of any country with jurisdiction over the affairs of any member of the Participant Group; or
 
(C)     with our prior written consent.
 
3.        Notification of Required or Unauthorised Disclosure:You agree (to the extent permitted by law) to inform us of the full circumstances of any disclosure under paragraph 2(b) (in advance where reasonable and practicable) or immediately upon becoming aware that Confidential Information has been disclosed in breach of this letter.
 
4.        Return of Copies:If we so request in writing, you shall return all Confidential Information supplied to you by us or any member of the Group and destroy or permanently erase all copies of Confidential Information made by you and use all reasonable endeavours to ensure that anyone to whom you have supplied any Confidential Information destroys or permanently erases such Confidential Information and any copies made by them, in each case save to the extent that you or the recipients are required to retain any such Confidential Information by any applicable law, rule or regulation or by any competent judicial, governmental, supervisory or regulatory body, or where the Confidential Information has been disclosed in accordance with paragraph 2(B) above.
 
5.        Continuing Obligations:The obligations in the preceding paragraphs of this letter are continuing and, in particular, shall survive the termination of any discussions or negotiations between you and us, irrespective of their outcome. Notwithstanding the previous sentence, the obligations in this letter shall cease twelve months after you have returned all Confidential Information and destroyed or permanently erased all copies of Confidential Information made by you to the extent required pursuant to paragraph 4 above.
 
176

 
6.        No Representation; Consequences of Breach, etc: You acknowledge and agree that:
 
(A)    neither we nor any of our officers, employees or advisers, and no other member of the Group and none of the officers, employees or advisers of any member of the Group (each a “ Relevant Person ”), (i) make any representation or warranty, express or implied, as to, or assume any responsibility for, the accuracy, reliability or completeness of any of the Confidential Information or any other information supplied by us or any member of the Group or the assumptions on which it is based or (ii) shall be under any obligation to update or correct any inaccuracy in the Confidential Information or any other information supplied by us or any other member of the Group or be otherwise liable to you or any other person in respect of the Confidential Information or any such information; and
 
(B)     we and other members of the Group may be irreparably harmed by the breach of the terms of this letter and damages may not be an adequate remedy; each Relevant Person may be granted an injunction or specific performance for any threatened or actual breach of the provisions of this letter by you or any other person.
 
7.        Inside Information:You acknowledge that some or all of the Confidential Information is or may be price-sensitive information and that the use of such information may be regulated or prohibited by applicable legislation relating to insider dealing and you undertake not to use any Confidential Information for any unlawful purpose. As a result of being given the Confidential Information you may well become insiders and, therefore, be unable to take certain actions which you would otherwise be able to take.
 
8.        No Waiver; Amendments, etc:This letter shall not affect any other obligation owed by you to any member of the Group. No failure or delay in exercising any right, power or privilege under this letter will operate as a waiver thereof nor will any single or partial exercise of any right, power or privilege preclude any further exercise thereof or the exercise of any other right, power or privileges under this letter. The terms of this letter and your obligations under this letter may only be amended or modified by written agreement between us and you.
 
9.        Nature of Undertakings:The undertakings and acknowledgements given by you under this letter are given to us and (without implying any fiduciary obligations on our part) are also given for the benefit of each other member of the Group.
 
10.      Third party rights:
 
(A)    Each other member of the Group and each Relevant Person (each a “Third Party”) may enforce the terms of this letter by virtue of the Contracts (Rights of Third Parties) Act 1999 (the “ Third Parties Act ”). This paragraph 10(A) confers a benefit on each Third Party, and, subject to the remaining provisions of this paragraph 10, is intended to be enforceable by each Third Party by virtue of the Third Parties Act.
 
177

 
(B)     Subject to paragraph 10(a), a person who is not a party to this letter has no right under the Third Parties Act to enforce or enjoy the benefit of any term of this letter.
 
(C)     Notwithstanding any provisions of this letter, the parties to this letter do not require the consent of any person to rescind or vary this letter at any time.
 
11.      Counterparts: This letter may be executed in any number of counterparts, and by the parties on separate counterparts, but shall not be effective until each party has executed at least one counterpart. Each counterpart shall constitute an original of this letter, but all the counterparts shall together constitute one and the same instrument.
 
12.      Governing Law and Jurisdiction:Any matter, claim or dispute, whether contractual or non-contractual, arising out of or in connection with this letter (including the agreement constituted by your acknowledgement of its terms), is to be governed by and determined in accordance with English law, and the parties submit to the non-exclusive jurisdiction of the English courts.
 
13.      Definitions and Construction:In this letter (including the acknowledgement set out below):
 
“Confidential Information” means any and all information relating to the Company, the Group and the Facility, provided to you by us or any member of the Group or any of our affiliates or advisers, in whatever form, and includes information given orally and any document, electronic file or any other way of representing or recording information which contains or is derived or copied from such information and information regarding all discussions and negotiations between us (including information regarding the outcome of such discussions or negotiations), but excludes information that (a) is or becomes public knowledge other than as a direct or indirect result of any breach of this letter or (b) is known by you before the date the information is disclosed to you by us or any member of the Group or any of our affiliates or advisers or is lawfully obtained by you after that date, other than from a source which is connected with the Group and which, in either case, as far as you are aware, has not been obtained in violation of, and is not otherwise subject to, any obligation of confidentiality;
 
“Group” means, in respect of a person, that person and that person’s Holding Companies and each of their respective Subsidiaries;
 
“Holding Company” means, in relation to a company, any other company in respect of which it is a Subsidiary;
 
“Participant Group” means you, and each of your Holding Companies and Subsidiaries;
 
“Permitted Purpose” means considering and evaluating whether to enter into contracts with us in relation to your participation in the Facility; and
 
“Subsidiary” means a subsidiary within the meaning of section 1159 of the Companies Act 2006.
 
178

 
Please acknowledge your agreement to the above by signing and returning the enclosed copy.
 
Yours faithfully	 	

For and on behalf of Kosmos Energy Finance International	 	

To:	Kosmos Energy Finance International and each other member of the Group	

We acknowledge and agree to the above:	

For and on behalf of [insert details of lender]	

179

 
Schedule 14
Form of Deed of Subordination
 
THIS DEEDis dated [                                              ] and made between:
 
(1)      [·] (the “Obligor”);
 
(2)      BNP PARIBAS in its capacity as Security Agent for the Secured Parties on the terms and conditions set out in the Intercreditor Agreement (the “ Security Agent ”) which expression includes its successors in title and assigns or any person appointed as an additional trustee for the purpose of and in accordance with the Intercreditor Agreement; and
 
(3)      [·] (the “Subordinated Party”).
 
BACKGROUND:
 
(1)      Under the Facility, the Lenders have agreed to make available $[·] billion loan facility to the Borrower.
 
(2)      The Subordinated Party has agreed to make, or may in the future make, loans available to the Obligor.
 
(3)      The Obligor and the Subordinated Party have agreed that the Subordinated Debt (as defined below) shall be subordinated to the claims of the Secured Parties on the terms of this Deed.
 
IT IS AGREEDas follows:
 
1.       DEFINITIONS AND INTERPRETATION
 
1.1     Definitions
 
In this Deed:
 
“Permitted Payment” means any payment or receipt expressly permitted by clause 4 (Permitted Payments) so long as it is so permitted.
 
“Subordinated Debt” means all present and future moneys, debts, obligations and liabilities which are, or are expressed to be, or may become due, owing or payable by the Obligor to the Subordinated Party (in each case, whether alone or jointly, or jointly and severally, with any other person, whether actually or contingently, and whether as principal, surety or otherwise) together with any related Additional Debt.
 
“Subordinated Documents” means any document evidencing or recording the terms of any Subordinated Debt.
 
180

 
“Subordination Period” means the period beginning on the date of this Deed and ending on the date on which all the Secured Liabilities have been unconditionally and irrevocably paid or discharged or satisfied in full and all commitments of the Secured Parties have expired or been cancelled.
 
1.2     Incorporation of defined terms
 
Terms defined in clause 1 (Definitions) of the facility agreement made on or about the date of this Deed (the “ Agreement ”) by, inter alios, the parties to this Deed shall have the same meaning and construction when used herein.
 
1.3     Construction of particular terms
 
The rules of construction and interpretation set out in clause 2 (Interpretation and Construction) of the Agreement shall apply to this Deed as if expressly set out herein.
 
1.4     Third Party Rights
 
(a)      Subject to clause 1.4(b), the parties to this Deed do not intend that any term of this Deed should be enforceable by virtue of the Contracts (Rights of Third Parties) Act 1999, by any person who is not a party to this Deed.
 
(b)     Each of the Secured Parties shall have the right to enforce the terms of this Deed.
 
2.       RANKING
 
(a)      The Secured Liabilities shall rank senior in priority to the Subordinated Debt.
 
(b)     Except as provided in this Deed, any payment in respect of the Subordinated Debt is conditional upon the expiry of the Subordination Period.
 
(c)      As between the Secured Parties, nothing in this Deed shall prejudice the ranking of the Secured Liabilities as set forth in the Intercreditor Agreement.
 
3.       UNDERTAKINGS
 
3.1     Undertakings of the Obligor
 
(a)      During the Subordination Period the Obligor shall not, and the Subordinated Party shall not require the Obligor to:
 
(i)       pay, repay or prepay any principal, interest or other amount on or in respect of, or make any distribution in respect of, or redeem, purchase, acquire or defease, any of the Subordinated Debt whether in cash or in kind;
 
(ii)      exercise any set-off against any Subordinated Debt;
 
181

 
(iii)     create or permit to subsist any Security over any of its assets, or give any guarantee, for, or in respect of, any Subordinated Debt;
 
(iv)     amend, terminate or give any waiver or consent under the Subordinated Documents, other than any amendment, termination, waiver or consent purely of a technical or administrative nature; or
 
(v)      take or omit to take any action whereby the ranking and/or subordination contemplated by this Deed might be impaired or terminated.
 
(b)     Notwithstanding paragraph (a) above, the Obligor may:
 
(i)       do anything prohibited by paragraph (a) above with the prior written consent of the Security Agent; and
 
(ii)      make any Permitted Payment.
 
3.2     Undertakings of the Subordinated Party
 
(a)      During the Subordination Period, the Subordinated Party shall not:
 
(i)       demand or receive payment, repayment or prepayment of any principal, interest or other amount on or in respect of, or any distribution in respect of, the Subordinated Debt in cash or in kind or apply any money or property in or towards discharge of the Subordinated Debt;
 
(ii)      exercise any set-off against the Subordinated Debt;
 
(iii)     permit to subsist or receive any Security, or any guarantee, for, or in respect of, the Subordinated Debt;
 
(iv)     amend, terminate or give any waiver or consent under any Subordinated Document, other than any amendment, termination, waiver or consent purely of a technical or administrative nature; or
 
(v)      take or omit to take any action whereby the ranking and/or subordination contemplated by this Deed might be impaired;
 
(vi)     take any Enforcement Action in relation to the Subordinated Debt; or
 
(vii)    assign, transfer or otherwise dispose of any of its rights, benefit, title or interest in or to the Subordinated Debt.
 
(b)     Notwithstanding paragraph (a) above, the Subordinated Party may:
 
(i)       do anything prohibited by paragraph (a) above with the prior written consent of the Security Agent; and
 
182

 
(ii)      receive and retain a Permitted Payment.
 
4.       PERMITTED PAYMENTS
 
Subject to clause 6 (Turnover) and clause 7 (Subordination on Insolvency), unless:
 
(a)      a Default is continuing; or
 
(b)     an Insolvency Event or Insolvency Proceedings have occurred in which case clause 7 (Subordination on Insolvency) applies; or
 
(c)      the aggregate of the outstandings under the Facility on the most recent Forecast Date exceeds the Borrowing Base Amount pursuant to clause 10.3 ( Aggregate outstandings exceed the Borrowing Base Amount ) of the Agreement and the earlier of the date of the mandatory prepayment to cure the deficiency or the date which is 90 days following that Forecast Date has not occurred, (in which case the provisions of clause 7 ( Subordination on Insolvency ) shall apply),
 
the Obligor may pay and the Subordinated Party may receive and retain payments of [of interest and principal] on the Subordinated Debt in accordance with clause 21.2 ( Withdrawals — No Default Outstanding ) of the Agreement, such payment or receipt to include payment or receipt by way of set-off.
 
5.       REPRESENTATIONS
 
5.1     Representations of the Subordinated Party
 
The Subordinated Party makes the representations and warranties set out in this clause 5.1 on the date of this Deed:
 
(a)      It is duly incorporated (if a corporate person) or duly established (in any other case except for a natural person) and validly existing under the law of its jurisdiction of incorporation or formation.
 
(b)     It has the power to own its assets and carry on its business as it is being and is proposed to be, conducted, and it has the power to enter into and perform all its obligations under this Deed and the transactions contemplated by this Deed.
 
(c)      The obligations expressed to be assumed by it under this Deed are legal, valid, binding and enforceable obligations.
 
(d)     The entry into and performance by it of, and the transactions contemplated by, this Deed does not and will not conflict with:
 
(i)    any law applicable to it;
 
(ii)   its constitutional documents; or
 
183

 
(iii)   any agreement or instrument binding upon it or any of its assets.
 
(e)                   It has (or had at the relevant time) the power and authority to execute and deliver this Deed and it has the power and authority to perform its obligations under this Deed and the transactions contemplated thereby.
 
(f)                     All Required Approvals have been obtained or effected and are in full force and effect where a failure to do so has or could reasonably be expected to have a Material Adverse Effect.
 
(g)                  It is the sole beneficial owner of the Subordinated Debt owed to it.
 
5.2     Repetition
 
Each of the representations and warranties in clause 5.1 (representations of the subordinated party) will be repeated on the date of each utilisation date and on the first day of each interest period. Where a representation is repeated, it is applied to the facts and circumstances existing at the time of repetition.
 
6.       TURNOVER
 
During the Subordination Period, if the Subordination Party received or recovers:
 
(a)                   a payment (other than a Permitted Payment) in cash or in kind or distribution in respect of any of the Subordinated Debt from the Obligor or any other source; or
 
(b)                  the proceeds of any enforcement of any Security or any guarantee or other assurance against financial loss for any Subordinated Debt, in each case, in contravention of clause 2 ( Ranking ) or 3 ( Undertakings ), the Subordinated Party shall:
 
(i)                       within three (3) Business Days notify details of the receipt or recovery to the Security Agent;
 
(ii)                    hold any such assets and moneys received or recovered by it (up to a maximum of an amount equal to the Secured Liabilities on trust for the Security Agent for application against the Secured Liabilities in accordance with the order and priority set forth in the Intercreditor Agreement; and
 
(iii)                 within three (3) Business Days of demand by the Security Agent, pay an amount equal to such receipt or recovery (up to a maximum of an amount equal to the Secured Liabilities) to the Security Agent for application against the Secured Liabilities in accordance with the order and priority set forth in the Intercreditor Agreement.
 
184

 
7.       SUBORDINATION ON INSOLVENCY
 
7.1     Subordination
 
If an Insolvency Event or Insolvency Proceedings occur, the Subordinated Debt will be subordinate to the Secured Liabilities.
 
7.2     Filing of Claims
 
(a)                   If an Insolvency Event or Insolvency Proceedings occur or any Event of Default is continuing, the Security Agent may, and is hereby irrevocably authorised on behalf of the Obligor and the Subordinated Party to:
 
(i)                       take any Subordinated Debt Enforcement Action;
 
(ii)                    demand, claim, enforce and prove for the Subordinated Debt;
 
(iii)                 file claims and proofs, give receipts and take any proceedings in respect of filing such claims or proofs and do anything which the Security Agent reasonably considers necessary or desirable to recover the Subordinated Debt; and
 
(iv)                receive all distributions of the Subordinated Debt for application first against the Secured Liabilities in accordance with the order and priority set forth in the Intercreditor Agreement.
 
(b)                  If and to the extent that the Security Agent is not entitled, or elects not, to take any of the action mentioned in paragraph (a) above, the Subordinated Party will do so promptly on request by the Security Agent.
 
7.3     Distributions
 
If an Insolvency Event or Insolvency Proceedings occur, the Subordinated Party will:
 
(a)                   hold all payments and distributions in cash or in kind received or receivable by it in respect of the Subordinated Debt on trust for the Security Agent and promptly pay the same for application first against the Secured Liabilities in accordance with the order and priority set forth in the Intercreditor Agreement;
 
(b)                  within three Business Days of demand by Security Agent, pay an amount equal to any Subordinated Debt owing to it and discharged by set-off or otherwise to the Security Agent for application in accordance first against the Secured Liabilities in accordance with the order and priority set fourth in the Intercreditor Agreement;
 
185

 
(c)                   promptly direct the trustee in bankruptcy, liquidator, assignee or other person distributing the assets of the Obligor or their proceeds to pay any and all distributions in respect of the Subordinated Debt directly to the Security Agent; and
 
(d)      promptly undertake any action requested by the Security Agent to give effect to this clause 7.3.
 
7.4     Voting
 
(a)                   If an Insolvency Event or Insolvency Proceedings occur:
 
(i)                       the Security Agent may, and is hereby irrevocably so authorised on behalf of the Subordinated Party, to exercise all powers of convening meetings, voting and representation in respect of the Subordinated Debt; and
 
(ii)                    the Subordinated Party shall promptly execute and/or deliver to the Security Agent such forms of proxy and representation as it may require to facilitate any such action.
 
(b)                  If and to the extent that the Security Agent is not entitled, or elects not, to exercise a power under paragraph (a) above, the Subordinated Party will:
 
(i)                       exercise that power in such manner as the Security Agent directs; and
 
(ii)                    exercise that power so as not to impair the ranking and/or subordination contemplated by this Deed.
 
8.       PROTECTION OF SUBORDINATION
 
8.1     Continuing subordination
 
The subordination provisions in this Deed shall remain in full force and effect by way of continuing subordination and shall not be affected in any way by any intermediate payment or discharge in whole or in part of the Secured Liabilities.
 
8.2     Waiver of defences
 
Neither the subordination in this Deed nor the obligations of the Obligor or the Subordinated Party shall be affected in any way by an act, omission, matter or thing which, but for this clause 8, would reduce, release or prejudice the subordination or any of those obligations in whole or in part, including, without limitation, the following:
 
(a)                   any time, waiver or consent granted to, or composition with, any person;
 
(b)                  the release of any person under the terms of any composition or arrangement with any creditor of any person;
 
186

 
(c)                   the taking, variation, compromise, exchange, renewal or release of, or refusal or neglect to perfect, take up or enforce, any rights against, or security over assets of, any person or any non-presentation or non-observance of any formality or other requirement in respect of any instrument or any failure to realise the full value of any security;
 
(d)                  any incapacity or lack of power, authority or legal personality of or dissolution or change in the members or status of any person;
 
(e)                   any amendment, novation, supplement, extension (whether of maturity or otherwise) or restatement (in each case, however fundamental and of whatever nature) or replacement of any Finance Document or any other document or security;
 
(f)                     any unenforceability, illegality or invalidity of any obligation of any person under any Finance Document or any other document or security;
 
(g)                  any insolvency or similar proceedings; or
 
(h)                  any postponement, discharge, reduction, non-provability or other similar circumstance affecting any obligation of any person under any Finance Document resulting from any insolvency, liquidation or dissolution proceedings or from any law, regulation or order.
 
8.3     Immediate recourse
 
The Subordinated Party waives any right it may have of first requiring the Security Agent (or any other trustee or agent on its behalf) to proceed against or enforce any other rights or security or claim payment from any person claiming the benefit of this Deed. The Security Agent may refrain from applying or enforcing any money, rights or security.
 
8.4     Appropriations
 
The Security Agent (or any trustee or agent on its behalf) may, subject to its obligations under this Deed:
 
(a)                   apply any moneys or other assets received or recovered by it under this Deed or from any person against the Secured Liabilities, in accordance with the order and priority set forth in the Intercreditor Agreement;
 
(b)                  apply any moneys or other assets received or recovered by it from any person (other than any moneys or other assets received or recovered under the applicable Finance Documents or under this Deed) against any liability of the relevant person to it other than the Secured Liabilities owed to it; and
 
187

 
(c)                   unless or until such moneys or other assets received or recovered by it under the applicable Finance Documents or under this Deed in aggregate are sufficient to end the Subordination Period if otherwise applied in accordance with the provisions of this Deed, hold in an interest-bearing suspense account any moneys or other assets received from any person.
 
9.       PRESERVATION OF DEBT
 
9.1     Preservation of Subordinated Debt
 
Notwithstanding any term of this Deed postponing, subordinating or preventing the payment of all or any part of the Subordinated Debt, the Subordinated Party shall, as between the Obligor and the Subordinated Party, be deemed to remain owing or due and payable (and interest, default interest or indemnity payments shall continue to accrue) in accordance with the Subordinated Documents.
 
9.2     No liability
 
The Security Agent will have no liability to the Obligor or to the Subordinated Party for any act, default, or omission in relation to the manner of exercise or any non-exercise of its rights, remedies, powers, authorities or discretions under this Deed or any failure to collect or preserve any Subordinated Debt or delay in doing so.
 
10.     SUBROGATION
 
If any of the Secured Liabilities are wholly or partially paid out of any proceeds received in respect of or on account of the Subordinated Debt, the Subordinated Party will to that extent be subrogated to the Secured Liabilities so paid (and all securities and guarantees for those Secured Liabilities), but not before the expiry of the Subordination Period.
 
11.     NO OBJECTION BY SUBORDINATED PARTY
 
The Subordinated Party is deemed to consent to, and the Subordinated Party shall not have any claim or remedy against the Obligor or any Secured Party by reason of:
 
(a)                   the entry by any of them into any Finance Document or any other agreement between any Secured Party and the Obligor;
 
(b)                  any waiver or consent given by any Secured Party under any Finance Document or any such other agreement; or
 
(c)                   any requirement or condition imposed by or on behalf of any Secured Party under any Finance Document or any such other agreement,
 
from time to time which breaches or causes an event of default or potential event of default (however described) under any Subordinated Document.
 
188

 
12.     POWER OF ATTORNEY
 
(a)                   During the Subordination Period, the Subordinated Party, by way of security for the obligations of the Subordinated Party under this Deed, irrevocably appoints Security Agent as its attorney (with full power of substitution and delegation), on its behalf and in its name or otherwise as its act and deed, and in such manner as the attorney thinks fit to do anything which the Subordinated Party is obliged to do under this Deed but has not done, and the taking of action by the attorney shall (as between it and any third party) be conclusive evidence of its right to take such action.
 
(b)                  The Subordinated Party ratifies and confirms and agrees to ratify and confirm everything that such attorney does or purports to do in the exercise or purported exercise of the power of attorney granted by it in this clause 12.
 
13.     NEW MONEY
 
The Subordinated Party agrees and acknowledges that the Secured Parties may, at their discretion, increase any amounts payable or make further advances under the Finance Documents and/or make further facilities available to the Borrower. Any such increased payments, further advances and/or additional facilities will be deemed to be made under the terms of the Finance Documents.
 
14.     FAILURE OF TRUSTS
 
If any trust intended to arise pursuant to any provision of this Deed fails or for any reason (including the laws of any jurisdiction in which any assets, moneys, payments or distributions may be situated) cannot be given effect to, the Subordinated Party will pay to the Security Agent for application against the Secured Liabilities an amount equal to the amount (or the value of the relevant assets) intended to be so held on trust for the Security Agent.
 
15.     TRUSTS
 
(a)                   The Security Agent shall hold the benefit of this Deed upon trust for itself and the other relevant Secured Parties.
 
(b)                  The perpetuity period of the trusts created under this Deed shall be 80 years.
 
16.     NON-CREATION OF CHARGE
 
No provision of this Deed is intended to or shall create a charge or other security.
 
17.     CERTIFICATES AND DETERMINATIONS
 
Any certification or determination by the Security Agent of a rate or amount under this Deed will be, in the absence of manifest error, conclusive evidence of the matters to which it relates.
 
189

 
18.     CHANGES TO THE PARTIES
 
18.1  The Obligor and the Subordinated Party
 
Neither the Obligor nor the Subordinated Party may assign or transfer any of its rights or obligations under this Deed without prior written consent of the Security Agent.
 
18.2  The Security Agent
 
(a)                   The Security Agent may assign or otherwise dispose of all or any of its rights under this Deed as permitted under the Finance Documents.
 
(b)                  References in this Deed to the Security Agent include any successor in title and assigns or any person appointed as an additional trustee for the purposes of and in accordance with the Intercreditor Agreement.
 
19.     INFORMATION
 
19.1  Defaults
 
Any Subordinated Creditor will notify the Security Agent, of the occurrence of an event of default or potential event of default (however described) under or breach of any Subordinated Document, promptly upon becoming aware of it.
 
19.2  Amounts of Subordinated Debt
 
Any Subordinated Creditor will, on request by the Security Agent from time to time notify it of details of the amount of outstanding Subordinated Debt.
 
20.     NOTICES
 
20.1  Communications in writing
 
Any communication or document to be made or delivered under or in connection with this Deed shall be made in writing and, unless otherwise stated, may be made or delivered by fax or letter.
 
20.2  Addresses
 
The address and fax number (and the department or officer, if any, for whose attention the communication is to be made) of each party for any communication or document to be made or delivered under or in connection with this Deed is that identified in accordance with the terms of this Agreement (or in the case of the Subordinated Party, the Finance Documents to which it is a party) or otherwise as notified to the other parties on the date of this Deed, or any substitute address, fax number or department or officer as the party notifies to the other parties by not less than five Business Days’ notice.
 
190

 
20.3  Delivery
 
Any communication or document made or delivered by one person to another under or in connection with this Deed will only be effective:
 
(a)                   if by way of fax, when received in legible form; or
 
(b)                  if by way of letter, when it has been left at the relevant address or five Business Days after being deposited in the post postage prepaid in an envelope addressed to it at that address,
 
and, if a particular department or officer is specified as part of its address details provided under clause 20.2 (Addresses), if addressed to that department or officer.
 
20.4  English language
 
Any notice given under or in connection with this Deed must be in English.
 
21.     REMEDIES AND WAIVERS
 
No delay or omission by the Security Agent in exercising any right provided by law or under this Deed shall impair, affect, or operate as a waiver of, that or any other right. The single or partial exercise by the Security Agent of any right shall not, unless otherwise expressly stated, preclude or prejudice any other or further exercise of that, or the exercise of any other, right. The rights of the parties under this Deed are in addition to and do not affect any other rights available to them by law.
 
22.     PARTIAL INVALIDITY
 
(a)                   If, at any time, any provision of this Deed is or becomes illegal, invalid or unenforceable in any respect under any law of any jurisdiction, neither the legality, validity or enforceability of the remaining provisions under the law of that jurisdiction or any other jurisdiction will in any way be affected or impaired.
 
(b)                  The parties shall enter into good faith negotiations, but without any liability whatsoever in the event of no agreement being reached, to replace any illegal, invalid or unenforceable provision with a view to obtaining the same commercial effect as this Deed would have had if such provision had been legal, valid and enforceable.
 
23.     AMENDMENTS
 
No amendment may be made to this Deed (whether in writing or otherwise) without the prior written consent of the parties to this Deed.
 
191

 
24.     COUNTERPARTS
 
This Deed may be executed in any number of counterparts, and by the parties on separate counterparts, but will not be effective until each party has executed at least one counterpart. Each counterpart shall constitute an original of this Deed, but all the counterparts will together constitute one and the same instrument.
 
25.     EXECUTION AS A DEED
 
Each of the parties to this Deed intends it to be a deed and confirms that it is executed and delivered as a deed, in each case notwithstanding the fact that any one or more of the parties may only execute it under hand.
 
26.     ENFORCEMENT
 
26.1  Jurisdiction
 
(a)                   The courts of England have exclusive jurisdiction to settle any dispute arising out of or in connection with this Deed (including a dispute regarding the existence, validity or termination of this Deed) (a “ Dispute ”).
 
(b)                  The parties agree that the courts of England are the most appropriate and convenient courts to settle Disputes and accordingly no party will argue to the contrary.
 
(c)                   This clause 26.1 is for the benefit of the Security Agent only. As a result but subject to paragraph (d) below, the Security Agent shall not be prevented from taking proceedings relating to a Dispute in any other courts with jurisdiction. To the extent allowed by law, the Security Agent may take concurrent proceedings in any number of jurisdictions.
 
(d)                  The Subordinated Party agrees that it will not take proceedings relating to a Dispute in relation to the Subordinated Debt in any other courts with jurisdiction.
 
26.2  Service of process
 
(a)                   Without prejudice to any other mode of service allowed under any relevant law the Subordinated Party (which is not incorporated in England and Wales) irrevocably appoints [ name ] of [ address ] as its agent for service of process in relation to any proceedings before the English courts in connection with this Deed.
 
(b)                  The Subordinated Party agrees that failure by a process agent to notify the relevant party of the process will not invalidate the proceedings concerned.
 
192

 
27.     FURTHER ASSURANCE
 
Each of the Obligor and the Subordinated Party agrees that it will promptly, at the direction of the Security Agent (acting reasonably), execute and deliver at its own expense any document (to be executed as a deed or under hand) and do any act or thing in order to confirm or establish the validity and enforceability of the subordination effected by, and the obligations of the Obligor and the Subordinated Party under, this Deed.
 
28.     GOVERNING LAW
 
This Deed is governed by and is to be construed in accordance with English law. Any matter, claim or dispute arising out of or in connection with this Deed, whether contractual or non-contractual, is to be governed by and construed in accordance with English law.
 
IN WITNESSof which this document has been executed as a deed and delivered on the date stated at the beginning of this Deed.
 
193

 
Executed and Delivered as a Deed by	)	 	 	
[name of Obligor] in the presence of:	)	 	 	
 	)	Per:	 	
 	 	Title:	Director/Attorney-in-Fact	
 	 	Name:	 	

 	 	 	 	
Witness’s Signature	 	 	 	
 
(Name)	 	 	 	
 	 	 	 	
(Address)	 	 	 	
 	 	 	 	
(Occupation)	 	 	 	

Executed as a deed BNP PARIBAS	 	 	
acting by [a director and its	 	Director	
[secretary/two directors]]	 	 	

 	 	 	
 	 	[Secretary/Director]	
 	 	 	
[Address:	 	 	
 	 	 	
Fax Number:	 	 	
 	 	 	
Department:	 	 	
 	 	 	
Attention:]	 	 	

Executed as a deed [name of Subordinated	 	 	
Party] acting by [a director and its	 	Director	
[secretary/two directors]]	 	 	

 	 	 	
 	 	[Secretary/Director]	
 	 	 	
[Address:	 	 	
 
194

 
Fax Number:
 
Department:
 
Attention:]
 
195

 
Schedule 15
Form of Sources and Uses Statement
 
“A” is the aggregate of:	 	$ 000’s	 	“B” is the aggregate of:	 	$ 000’s	
 	 	 	 	 	 	 	
Net Cash Flow minus Facility debt service (ds) for next 12 months as derived from latest Forecast	 	 	 	committed exploration and appraisal costs for next 12 month period, not included in Net Cash Flow calculation, for Obligor group	 	 	
 	 	 	 	 	 	 	
Net free cash-flows after ds for next 12 month period from KEO assets other than the Borrowing Base Assets from Obligor group corporate cash-flow model using same economic assumptions as in Forecast	 	 	 	committed development costs, not included in Net Cash Flow calculation, for the next 12 months for Obligor group	 	 	
 	 	 	 	 	 	 	
Cash balance of KEO excluding balances of accounts used as collateral for Secured LCs or other specific purposes (other than such balances securing amounts taken into account in “B”)	 	 	 	payment obligations under rigs contracts or other similar operational contracts, for the next 12 months, not included in the Net Cash Flow, for Obligor group	 	 	
 	 	 	 	 	 	 	
Total Available Facility Amount less Relevant Capital Expenditures	 	 	 	payment obligations under a sale and purchase agreement in the context of an acquisition or otherwise, not included in the Net Cash Flow, for Obligor group for the next 12 months	 	 	
 	 	 	 	 	 	 	
 	 	 	 	any off balance sheet or contingent liability as per the capital commitments noted in the latest consolidated financials for KEO which could reasonably be expected to entail a cash outflow for the next 12 months	 	 	
 	 	 	 	 	 	 	
Any other committed undrawn and uncancelled amount available under any other external finance source of KEO	 	 	 	approximate dividends or other shareholder payments projected to be paid by KEO for the next 12 months  (or in case of Borrower level, by Borrower)	 	 	
 
196

 
Amount provided by a person/persons to KEO or Obligors made available for the purpose of meeting projected liabilities unrelated to the Borrowing Base Assets that the Facility Agent is satisfied will be available	 	 	 	any other material committed liability for the next 12 months period including any guarantee, indemnity or other contingent liability, which could be reasonably be expected to entail a cash outflow for the next 12 month period	 	 	
 	 	 	 	 	 	 	
TOTAL OBLIGOR GROUP	 	 	 	TOTAL OBLIGOR GROUP	 	 	
 
197

 
Schedule 16
(Copy of ORGL LC)
 
198

 
SIGNATURES
 
Original Borrower	 	
 	 	
KOSMOS ENERGY FINANCE INTERNATIONAL	 	
 	 	 	
By:	/s/ Ryan Turner	 	

Name:	Ryan Turner	 	
Title:	Attorney In Fact	 	

 
Original Guarantors	 	
 	 	
KOSMOS ENERGY OPERATING	 	
 	 	
By:	/s/ Ryan Turner	 	

Name:	Ryan Turner	 	
Title:	Attorney In Fact	 	

KOSMOS ENERGY GHANA HC	 	
 	 	 	
By:	/s/ Ryan Turner	 	

Name:	Ryan Turner	 	
Title:	Attorney In Fact	 	

 
KOSMOS ENERGY DEVELOPMENT	 	
 	 	 	
By:	/s/ Ryan Turner	 	

Name:	Ryan Turner	 	
Title:	Attorney In Fact	 	

 
KOSMOS ENERGY INTERNATIONAL	 	
 	 	 	
By:	/s/ Ryan Turner	 	

Name:	Ryan Turner	 	
Title:	Attorney In Fact	 	

 
SIGNATURES
 
Mandated Lead Arrangers	 	
 	 	
ABSA CAPITAL, A DIVISION OF ABSA BANK LIMITED	
 	 	 	 	
By:	/s/ Narisa Balgobind	By:	/s/ David Pilling	

Name:	Narisa Balgobind	Name:	David Pilling	
Title:	Principal	Title:	Associate Principal	

BNP PARIBAS	 	
 	 	 	 	
By:	/s/ Xavier Venereau	By:	/s/ Olivier Warnan	

Name:	Xavier Venereau	Name:	Olivier Warnan	
Title:	Managing Director	Title:	Director-BNP Paribas	

CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANK	
 	 	 	
By:	/s/ L. Renard	By:	

Name:	L. Renard	Name:	
Title:	Associate Director	Title:	

HSBC BANK PLC	 	
 	 	 	
By:	/s/ William Stevens	By:	

Name:	William Stevens	Name:	
Title:	Managing Director	Title:	

 
SOCIÉTÉ GÉNÉRALE, LONDON BRANCH	 	
 	 	 	
By:	/s/ Marie-Aimée Bowy	By:	

Name:	Marie-Aimée Bowy	Name:	
Title:	Managing Director	Title:	

STANDARD CHARTERED BANK	 	
 	 	 	
By:	/s/ Andrew Bartlett	By:	

Name:	Andrew Bartlett	Name:	
Title:	Managing Director	Title:	

 
Original Lenders	 	
 	 	
ABSA CAPITAL, A DIVISION OF ABSA BANK LIMITED	
 	 	 	 	
By:	/s/ Narisa Balgobind	By:	/s/ David Pilling	

Name:	Narisa Balgobind	Name:	David Pilling	
Title:	Principal	Title:	Associate Principal	

BARCLAYS BANK PLC	 	
 	 	 	
By:	/s/ C.J. Morphett	By:	

Name:	C.J. Morphett	Name:	
Title:	Director	Title:	

BNP PARIBAS	 	
 	 	 	 	
By:	/s/ Xavier Venereau	By:	/s/ Olivier Warnan	

Name:	Xavier Venereau	Name:	Olivier Warnan	
Title:	Managing Director	Title:	Director - BNP Paribas	

CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANK	
 	 	 	
By:	/s/ L. Renard	By:	

Name:	L. Renard	Name:	
Title:	Associate Director	Title:	

 
HSBC BANK PLC	 	
 	 	
By:	/s/ William Stevens	 	By:	

Name:	William Stevens	 	Name:	
Title:	Managing Director	 	Title:	

SOCIÉTÉ GÉNÉRALE, LONDON BRANCH	 	
 	 	
By:	/s/ Marie-Aimée Bowy	 	By:	

Name:	Marie-Aimée Bowy	 	Name:	
Title:	Managing Director	 	Title:	

STANDARD CHARTERED BANK	 	
 	 	
By:	/s/ Andrew Bartlett	 	By:	

Name:	Andrew Bartlett	 	Name:	
Title:	Managing Director	 	Title:	

 
Underwriters	 	
 	 	
ABSA CAPITAL, A DIVISION OF ABSA BANK LIMITED	
 	 	
By:	/s/ Narisa Balgobind	 	By:	/s/ David Pilling	

Name:	Narisa Balgobind	 	Name:	David Pilling	
Title:	Principal	 	Title:	Associate Principal	

BNP PARIBAS	 	
 	 	 	 	
By:	/s/ Xavier Venereau	 	By:	/s/ O. Warnan	

Name:	Xavier Venereau	 	Name:	Olivier Warnan	
Title:	Managing Director	 	Title:	Director-BNP Paribas	

CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANK	
 	 	
By:	/s/ L. Renard	 	By:	

Name:	L. Renard	 	Name:	
Title:	Associate Director	 	Title:	

HSBC BANK PLC	
 	 	
By:	/s/ William Stevens	 	By:	

Name:	William Stevens	 	Name:	
Title:	Managing Director	 	Title:	

 
SOCIÉTÉ GÉNÉRALE, LONDON BRANCH	
 	 	
By:	/s/ Marie-Aimée Bowy	 	By:	

Name:	Marie-Aimée Bowy	 	Name:	
Title:	Managing Director	 	Title:	

STANDARD CHARTERED BANK	
 	 	
By:	/s/ Andrew Bartlett	 	By:	

Name:	Andrew Bartlett	 	Name:	
Title:	Managing Director	 	Title:	

 
SIGNATURES
 
Technical Bank:	 	
 	 	
SOCIÉTÉ GÉNÉRALE, LONDON BRANCHas lead technical bank	
 	 	 	
By:	/s/ Marie-Aimée Bowy	 	By:	

Name:	Marie-Aimée Bowy	 	Name:	
Title:	Managing Director	 	Title:	

CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANKas co-technical bank	
 	 	 	 	
By:	/s/ L. Renard	 	By:	

Name:	L. Renard	 	Name:	
Title:	Associate Director	 	Title:	

HSBC BANK PLCas co-technical bank	 	
 	 	 	
By:	/s/ William Stevens	 	By:	

Name:	William Stevens	 	Name:	
Title:	Managing Director	 	Title:	

 
SIGNATURES
 
Modelling Bank	 	
 	 	
SOCIÉTÉ GÉNÉRALE, LONDON BRANCHas lead modelling bank	
 	 	 	
By:	/s/ Marie-Aimée Bowy	 	By:	

Name:	Marie-Aimée Bowy	 	Name:	
Title:	Managing Director	 	Title:	

CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANKas co-modelling bank	
 	 	 	
By:	/s/ L. Renard	 	By:	

Name:	L. Renard	 	Name:	
Title:	Associate Director	 	Title:	

 
SIGNATURES
 
Onshore Account Bank	 	
 	 	
STANDARD CHARTERED BANK	 	
 	 	 	
By:	/s/ Andrew Bartlett	 	By:	

Name:	Andrew Bartlett	 	Name:	
Title:	Managing Director	 	Title:	

 
SIGNATURES
 
Offshore Account Bank	 	
 	 	
HSBC BANK PLC	 	
 	 	 	 	
By:	/s/ William Stevens	 	By:	

Name:	William Stevens	 	Name:	
Title:	Managing Director	 	Title:	

 
SIGNATURES
 
Facility Agent	 	
 	 	
BNP PARIBAS	 	
 	 	 	
By:	/s/ Xavier Venereau	 	By:	/s/ Olivier Warnan	

Name:	Xavier Venereau	 	Name:	Olivier Warnan	
Title:	Managing Director	 	Title:	Director-BNP Paribas	

 
SIGNATURES
 
Documentation Bank	 	
 	 	
HSBC BANK PLC	 	
 	 	 	
By:	/s/ William Stevens	 	By:	

Name:	William Stevens	 	Name:	
Title:	Managing Director	 	Title:	

 
SIGNATURES
 
Security Agent	 	
 	 	
BNP PARIBAS	 	 	
 	 	 	 	
By:	/s/ Xavier Venereau	 	By:	/s/ Olivier Warnan	

Name:	Xavier Venereau	 	Name:	Olivier Warnan	
Title:	Managing Director	 	Title:	Director-BNP Paribas	

 
SIGNATURES
 
Intercreditor Agent	 	
 	 	
BNP PARIBAS	 	
 	 	 	
By:	/s/ Xavier Venereau	 	By:	/s/ Olivier Warnan	

Name:	Xavier Venereau	 	Name:	Olivier Warnan	
Title:	Managing Director	 	Title:	Director-BNP Paribas	

Exhibit 10.20
 
EXECUTION VERSION
 
DATED 28 March 2011
 
BNP PARIBAS
as Facility Agent
 
The Lenders
 
The Hedging Counterparties
 
KOSMOS ENERGY FINANCE INTERNATIONAL
as Borrower
 
KOSMOS ENERGY FINANCE INTERNATIONAL, KOSMOS ENERGY OPERATING, KOSMOS ENERGY INTERNATIONAL, KOSMOS ENERGY DEVELOPMENT AND KOSMOS ENERGY GHANA HC
as Original Obligors
 
BNP PARIBAS
acting as Security Agent
 
and others

 
INTERCREDITOR AGREEMENT

 
Slaughter and May
One Bunhill Row
London EC1Y 8YY
 
(Ref: SRG/JKW)
 
507050046

 
CONTENTS
 
Clause	 	Page	
 	 	 	
1.	DEFINITIONS AND INTERPRETATION	1	
 	 	 	
2.	RANKING AND PRIORITY	13	
 	 	 	
3.	LENDERS AND LENDER LIABILITIES	13	
 	 	 	
4.	HEDGE COUNTERPARTIES AND HEDGING LIABILITIES	17	
 	 	 	
5.	EFFECT OF INSOLVENCY EVENT	21	
 	 	 	
6.	TURNOVER OF RECEIPTS	23	
 	 	 	
7.	REDISTRIBUTION	25	
 	 	 	
8.	ENFORCEMENT OF TRANSACTION SECURITY	26	
 	 	 	
9.	DISPOSALS	27	
 	 	 	
10.	APPLICATION OF PROCEEDS	31	
 	 	 	
11.	THE SECURITY AGENT	34	
 	 	 	
12.	CHANGE OF SECURITY AGENT AND DELEGATION	41	
 	 	 	
13.	CHANGES TO THE PARTIES	43	
 	 	 	
14.	COSTS AND EXPENSES	45	
 	 	 	
15.	INDEMNITIES	46	
 	 	 	
16.	INFORMATION	48	
 	 	 	
17.	NOTICES	49	
 	 	 	
18.	PRESERVATION	52	
 	 	 	
19.	CONSENTS, AMENDMENTS AND OVERRIDE	53	
 	 	 	
20.	COUNTERPARTS	57	
 	 	 	
21.	GOVERNING LAW	57	
 	 	 	
22.	ENFORCEMENT	57	
 	 	 	
Schedule 1 FORM OF OBLIGOR ACCESSION DEED	59	

 
Schedule 2 FORM OF CREDITOR/AGENT ACCESSION UNDERTAKING	62	

 
THIS AGREEMENT is dated 28 March 2011 and made between:
 
(1)          BNP PARIBAS as Facility Agent;
 
(2)          THE FINANCIAL INSTITUTIONS named on the signing pages as Lenders;
 
(3)          ABSA CAPITAL, A DIVISION OF ABSA BANK LIMITED, BNP PARIBAS, CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANK, HSBC BANK PLC, SOCIÉTÉ GÉNÉRALE LONDON BRANCH AND STANDARD CHARTERED BANK as mandated lead arrangers of the Facilities (in such capacity, the “ Arrangers ”);
 
(4)          THE FINANCIAL INSTITUTIONS named on the signing pages as Hedging Counterparties;
 
(5)          KOSMOS ENERGY FINANCE INTERNATIONAL(incorporated under the laws of the Cayman Islands with registered number 253656) (the “ Borrower ”);
 
(6)          KOSMOS ENERGY INTERNATIONAL(incorporated under the laws of the Cayman Islands with registered number 218274) (“ KEI ”);
 
(7)          KOSMOS ENERGY OPERATING(incorporated under the laws of the Cayman Islands with registered number 231417) (“ KEO ”);
 
(8)          KOSMOS ENERGY GHANA HC (incorporated under the laws of the Cayman Islands with registration number 135710) (“ Kosmos ”);
 
(9)          KOSMOS ENERGY DEVELOPMENT(incorporated under the laws of the Cayman Islands with registered number 225879) (“ KED ”);
 
(10)        BNP PARIBAS as security agent for the Secured Parties (the “Security Agent”).
 
IT IS AGREED as follows:
 
1.           DEFINITIONS AND INTERPRETATION
 
1.1         Definitions
 
In this Agreement, unless the context otherwise requires or as otherwise defined in this Agreement, words and expressions defined in clause 1.1 of the facility agreement (the “ Facility Agreement ”) dated the date of this Agreement made between, among others, the parties to this Agreement, have the same meanings when used herein.  In addition:
 
“1992 ISDA Master Agreement” means the Master Agreement (Multicurrency Cross Border) as published by the International Swaps and Derivatives Association, Inc.
 
“2002 ISDA Master Agreement” means the 2002 Master Agreement as published by the International Swaps and Derivatives Association, Inc.
 
“Acceleration Event” means the Facility Agent exercising any of its rights under clause 29.17 ( Acceleration - all Lenders ) of the Facility Agreement.

 
“Borrowing Liabilities” means, in relation to an Obligor, the liabilities (not being Guarantee Liabilities) it may have as a principal debtor to a Creditor, or Obligor in respect of Financial Indebtedness arising under the Finance Documents (whether incurred solely or jointly).
 
“Charged Property” means all of the assets which from time to time are, or are expressed to be, the subject of the Transaction Security.
 
“Close Out Netting” means:
 
(a)          in respect of a Hedging Agreement based on a 1992 ISDA Master Agreement, any step involved in determining the amount payable in respect of an Early Termination Date (as defined in the 1992 ISDA Master Agreement) under section 6(e) of the 1992 ISDA Master Agreement before the application of any subsequent Set off (as defined in the 1992 ISDA Master Agreement);
 
(b)          in respect of a Hedging Agreement based on a 2002 ISDA Master Agreement, any step involved in determining an Early Termination Amount (as defined in the 2002 ISDA Master Agreement) under section 6(e) of the 2002 ISDA Master Agreement; and
 
(c)          in respect of a Hedging Agreement not based on an ISDA Master Agreement, any step involved on a termination of the Hedging Transactions under that Hedging Agreement pursuant to any provision of that Hedging Agreement which has a similar effect to either provision referenced in paragraph (a) and paragraph (b) above.
 
“Common Assurance” means any guarantee, indemnity or other assurance against loss in respect of any of the Liabilities, the benefit of which (however conferred) is, to the extent legally possible, given to all the Secured Parties in respect of their Liabilities.
 
“Consent” means any consent, approval, release or waiver or agreement to any amendment.
 
“Creditor/Agent Accession Undertaking” means:
 
(a)          an undertaking substantially in the form set out in Schedule 2 (Form of Creditor/Agent Accession Undertaking); or
 
(b)          a Transfer Certificate.
 
“Creditors” means the Lenders and the Hedging Counterparties.
 
“Credit Participation” means, in relation to a Creditor, the aggregate of:
 
(a)          all amounts actually and contingently accrued to it under the Facility Agreements and the Facility Agreement, if any; and
 
(b)          in respect of any Hedging Transaction of that Creditor under any Hedging Agreement that has, as of the date the calculation is made, been terminated or
 
2

 
closed out in accordance with the terms of this Agreement, the amount, if any, payable to it under any Hedging Agreement in respect of that termination or close out as of the date of termination or close out (and before taking into account any interest accrued on that amount since the date of termination or close out) to the extent that amount is unpaid (that amount to be certified by the relevant Creditor and as calculated in accordance with the relevant Hedging Agreement); and
 
(c)          after the Lender Discharge Date or following a Distress Event only, in respect of any Hedging Transaction of that Creditor under any Hedging Agreement that has, as of the date the calculation is made, not been terminated or closed out:
 
(i)           if the relevant Hedging Agreement is based on an ISDA Master Agreement the amount, if any, which would be payable to it under that Hedging Agreement in respect of that Hedging Transaction, if the date on which the calculation is made was deemed to be an Early Termination Date (as defined in the relevant ISDA Master Agreement) for which the relevant Obligor is the Defaulting Party (as defined in the relevant ISDA Master Agreement); or
 
(ii)          if the relevant Hedging Agreement is not based on an ISDA Master Agreement, the amount, if any, which would be payable to it under that Hedging Agreement in respect of that Hedging Transaction, if the date on which the calculation is made was deemed to be the date on which an event similar in meaning and effect (under that Hedging Agreement) to an Early Termination Date (as defined in any ISDA Master Agreement) occurred under that Hedging Agreement for which the relevant Obligor is in a position similar in meaning and effect (under that Hedging Agreement) to that of a Defaulting Party (under and as defined in the same ISDA Master Agreement),
 
that amount, in each case, to be certified by the relevant Creditor and as calculated in accordance with the relevant Hedging Agreement.
 
“Debt Purchase Transaction” means, in relation to a person, a transaction where such person:
 
(a)          purchases by way of assignment or transfer;
 
(b)          enters into any sub-participation in respect of; or
 
(c)          enters into any other agreement or arrangement having an economic effect substantially similar to a sub-participation in respect of,
 
any Commitment or amount outstanding under the Facility Agreements.
 
“Delegate” means any delegate, agent, attorney or co trustee appointed by the Security Agent.
 
“Disposal Proceeds” has the meaning given to that term in Clause 9 (Disposals).
 
3

 
“Distress Event” means any of:
 
(a)          an Acceleration Event; or
 
(b)          the enforcement of any Transaction Security in accordance with the terms of the Security Documents.
 
“Distressed Disposal” means a disposal of an asset of a member of the Group or KEH which is:
 
(a)          being effected at the request of the Majority Lenders in circumstances where the Transaction Security has become enforceable in accordance with the terms of the Finance Documents;
 
(b)          being effected by enforcement of the Transaction Security in accordance with the terms of the Security Documents; or
 
(c)          being effected, after the occurrence of a Distress Event, by a member of the Group or KEH to a person or persons which is not a member of the Group.
 
“Dollar Currency Amount” means, in relation to an amount, that amount converted (to the extent not already denominated in USD) into USD at the Security Agent’s Spot Rate of Exchange on the Business Day prior to the relevant calculation.
 
“Enforcement Action” means:
 
(a)          in relation to any Liabilities:
 
(i)           the acceleration of any Liabilities or the making of any declaration that any Liabilities are prematurely due and payable (other than as a result of it becoming unlawful for a Lender to perform its obligations under, or of any voluntary or mandatory prepayment arising under, the Finance Documents);
 
(ii)          the making of any declaration that any Liabilities are payable on demand;
 
(iii)         the making of a demand in relation to a Liability that is payable on demand;
 
(iv)         the making of any demand against any member of the Group in relation to any Guarantee Liabilities of that member of the Group;
 
(v)          the exercise of any right to require any member of the Group to acquire any Liability (including exercising any put or call option against any member of the Group for the redemption or purchase of any Liability);
 
(vi)         the exercise of any right of set off, account combination or payment netting against any member of the Group in respect of any Liabilities other than the exercise of any such right:
 
4

 
(A)         as Close Out Netting by a Hedging Counterparty;
 
(B)         as Payment Netting by a Hedging Counterparty;
 
(C)         as Inter-Hedging Agreement Netting by a Hedging Counterparty; or
 
(D)         which is otherwise expressly permitted under the Facility Agreement to the extent that the exercise of that right gives effect to a Permitted Payment; and
 
(vii)        the suing for, commencing or joining of any legal or arbitration proceedings against any member of the Group to recover any Liabilities;
 
(b)          the premature termination or close-out of any Hedging Transaction under any Hedging Agreement;
 
(c)          the taking of any steps to enforce or require the enforcement of any Transaction Security (including the crystallisation of any floating charge forming part of the Transaction Security);
 
(d)          the entering into of any composition, compromise, assignment or arrangement with any member of the Group or KEH which owes any Liabilities, or has given any Security, guarantee or indemnity or other assurance against loss in respect of the Liabilities (other than any action permitted under Clause 13 ( Changes to the Parties )); or
 
(e)          the petitioning, applying or voting for, or the taking of any steps (including the appointment of any liquidator, provisional liquidator, receiver, administrator or similar officer) in relation to, the winding up, dissolution, administration, reorganisation merger or consolidation of any member of the Group which owes any Liabilities, or has given any Security, guarantee, indemnity or other assurance against loss in respect of any of the Liabilities, or any of such member of the Group’s assets or any suspension of payments or moratorium of any indebtedness of any such member of the Group, or any analogous procedure or step in any jurisdiction
 
except that the following shall not constitute Enforcement Action:
 
(i)           the taking of any action falling within paragraphs (a)(vii) or (e) above which is necessary (but only to the extent necessary) to preserve the validity, existence or priority of claims in respect of Liabilities, including the registration of such claims before any court or governmental authority and the bringing, supporting or joining of proceedings to prevent any loss of the right to bring, support or join proceedings by reason of applicable limitation periods; or
 
(ii)          a Hedging Counterparty or LC Issuing Bank bringing legal proceedings against any person solely for the purpose of:
 
5

 
(A)         obtaining injunctive relief (or any analogous remedy outside England and Wales) to restrain any actual or putative breach of any Finance Document to which it is party;
 
(B)         obtaining specific performance (other than specific performance of an obligation to make a payment) with no claim for damages; or
 
(C)         requesting judicial interpretation of any provision of any Finance Document to which it is party with no claim for damages.
 
“Facility Agent Liabilities” means all present and future liabilities and obligations, actual and contingent, of any Obligor to the Facility Agent under or in connection with the Finance Documents.
 
“Facility Agreement” has the meaning ascribed above to such term.
 
“Final Discharge Date” means the first date on which all Liabilities have been fully and finally discharged, whether or not as the result of an Enforcement Action, and the Creditors are under no further obligation to provide financial accommodation to any of the Obligors under the Finance Documents.
 
“Guarantee Liabilities” means, in relation to a member of the Group, the liabilities under the Finance Documents (present or future, actual or contingent and whether incurred solely or jointly) it may have to a Creditor or Obligor as or as a result of its being a guarantor or surety (including, without limitation, liabilities arising by way of guarantee, indemnity, contribution or subrogation and in particular any guarantee or indemnity arising under or in respect of the Finance Documents).
 
“Hedging Counterparty” means:
 
(a)          any person which is named on the signing pages as a Hedging Counterparty and;
 
(b)          any person which becomes a Party as a Hedging Counterparty pursuant to Clause 13.5 (Creditor/Agent Accession Undertaking ).
 
“Hedging Liabilities” means the Liabilities owed by any Obligor to the Hedging Counterparties under or in connection with the Hedging Agreements.
 
“Insolvency Event” means, in relation to any member of the Group:
 
(a)          any resolution is passed or order made for the winding up, dissolution or administration of that member of the Group or a moratorium is declared in relation to any indebtedness of that member of the Group;
 
(b)          any composition, compromise, assignment or arrangement is made with any of its creditors;
 
6

 
(c)          the appointment of any liquidator, provisional liquidator, receiver, administrator, administrative receiver, compulsory manager or other similar officer in respect of that member of the Group or any of its assets; or
 
(d)          any analogous procedure or step is taken in any jurisdiction.
 
“Instructing Group” means at any time the Majority Creditors;
 
“Intercreditor Amendment” means any amendment or waiver which is subject to Clause 19 (Consents, Amendments and Override ).
 
“Inter-Hedging Agreement Netting” means the exercise of any right of set-off, account combination, close-out netting or payment netting (whether arising out of a cross agreement netting agreement or otherwise) by a Hedging Counterparty against liabilities owed to an Obligor by that Hedging Counterparty under a Hedging Agreement in respect of Hedging Liabilities owed to that Hedging Counterparty by that Obligor under another Hedging Agreement.
 
“KEH” means Kosmos Energy Holdings, a company incorporated under the laws of the Cayman Islands with registered number 133483 and having its registered office at PO Box 32332, 4th Floor, Century Yard, Cricket Square, Elgin Avenue, George Town, Grand Cayman KY1-1209, Cayman Islands.
 
“KEI” means Kosmos Energy International a company incorporated under the laws of the Cayman Islands with registered number 218274 and having its registered office at P.O. Box 32322, 4th Floor, Century Yard, Cricket Square, Elgin Avenue, George Town, Grand Cayman KY1-1209, Cayman Islands.
 
“ISDA Master Agreement” means the 1992 ISDA Master Agreement or the 2002 ISDA Master Agreement, as the case may be.
 
“LC Cash Cover” has the meaning given to the term “cash collateral” in clause 7.1(B)(viii) of the Facility Agreement.
 
“Lender Discharge Date” means the first date on which all Lender Liabilities have been fully and finally discharged to the satisfaction of the Facility Agent, whether or not as the result of an enforcement, and the Lenders are under no further obligation to provide financial accommodation to any of the Obligors under any of the Finance Documents.
 
“Lender Liabilities” means the Liabilities owed by the Obligors to the Lenders under the Finance Documents (other than the Hedging Agreements).
 
“Lender Refinancing” means a refinancing (or repayment) and cancellation in full of the Lender Liabilities.
 
“Liabilities” means all present and future liabilities and obligations at any time of any Obligor to any Creditor under the Finance Documents, both actual and contingent and whether incurred solely or jointly or in any other capacity together with any of the following matters relating to or arising in respect of those liabilities and obligations:
 
7

 
(a)          any refinancing, novation, deferral or extension;
 
(b)          any claim for breach of representation, warranty or undertaking or on an event of default or under any indemnity given under or in connection with any document or agreement evidencing or constituting any other liability or obligation falling within this definition;
 
(c)          any claim for damages or restitution; and
 
(d)          any claim as a result of any recovery by any Obligor of a Payment on the grounds of preference or otherwise,
 
and any amounts which would be included in any of the above but for any discharge, non provability, unenforceability or non allowance of those amounts in any insolvency or other proceedings.
 
“Liabilities Acquisition” means, in relation to a person and to any Liabilities, a transaction where that person:
 
(a)          purchases by way of assignment or transfer;
 
(b)          enters into any sub-participation in respect of; or
 
(c)          enters into any other agreement or arrangement having an economic effect substantially similar to a sub-participation in respect of,
 
the rights and benefits in respect of those Liabilities.
 
“Majority Creditors” means, at any time, prior to a Distress Event occurring, the Majority Lenders and thereafter those Creditors whose Credit Participations at that time aggregate more than 662/3 per cent. of the total Credit Participations at that time.
 
“Mandatory Prepayment” means a mandatory prepayment of any of the Lender Liabilities pursuant to clause 10 ( Prepayment and Cancellation ) of the Facility Agreement
 
“Mandatory Prepayment Waiver” means any amendment or waiver of the requirement to make a Mandatory Prepayment.
 
“Non-Distressed Disposal” has the meaning given to such term in Clause 9.1 of this Agreement.
 
“Obligor” means each Original Obligor and any person which becomes a Party as an Obligor in accordance with the terms of Clause 13 ( Changes to the Parties ).
 
“Obligor Accession Deed” means a deed substantially in the form set out in Schedule 1 (Form of Obligor Accession Deed ).
 
8

 
“Obligor Liabilities” means, in relation to any Obligor, any liabilities owed to any Obligor (whether actual or contingent and whether incurred solely or jointly) by that Obligor.
 
“Original Obligors” means the Borrower, KEO, KEI, KED and Kosmos.
 
“Party” means a party to this Agreement.
 
“Payment” means, in respect of any Liabilities (or any other liabilities or obligations), a payment, prepayment, repayment, redemption, defeasance or discharge of those Liabilities (or other liabilities or obligations).
 
“Payment Default” means an Event of Default under clause 29.1 (Non payment) of the Facility Agreement relating to amounts payable to the Lenders under the Finance Documents.
 
“Payment Netting” means:
 
(a)          in respect of a Hedging Agreement or a Hedging Ancillary Document based on an ISDA Master Agreement, netting under section 2(c) of the relevant ISDA Master Agreement; and
 
(b)          in respect of a Hedging Agreement or a Hedging Ancillary Document not based on an ISDA Master Agreement, netting pursuant to any provision of that Hedging Agreement or a Hedging Ancillary Document which has a similar effect to the provision referenced in paragraph (a) above.
 
“Permitted Hedge Payments” means the Payments permitted by Clause 4.3 (Permitted Payments:  Hedging Liabilities ).
 
“Permitted Lender Payments” means the Payments permitted by Clause 3.1 (Payment of Lender Liabilities ).
 
“Permitted Payment” means a Permitted Hedge Payment or a Permitted Lender Payment.
 
“Receiver” means a receiver or receiver and manager or administrative receiver of the whole or any part of the Charged Property.
 
“Recoveries” has the meaning given to that term in Clause 10.1 (Order of Application).
 
“Relevant LC Issuing Bank” means, in respect of any LC Cash Cover, the LC Issuing Bank (if any) for which that LC Cash Cover is provided.
 
“Relevant Liabilities” means:
 
(a)          in the case of a Creditor:
 
9

 
 
(i)           the Liabilities owed to Creditors ranking (in accordance with the terms of this Agreement) pari passu with or in priority to that Creditor (as the case may be) together with all Facility Agent Liabilities; and
 
(ii)          all present and future liabilities and obligations, actual and contingent, of the Obligors to the Security Agent; and
 
(b)          in the case of an Obligor, the Liabilities owed to the Creditors together with the Facility Agent Liabilities and all present and future liabilities and obligations, actual and contingent, of the Obligors to the Security Agent.
 
“Retiring Security Agent” has the meaning given to that term in Clause 12 (Change of Security Agent and Delegation ).
 
“Secured Obligations” means all the Liabilities and all other present and future obligations at any time due, owing or incurred by any member of the Group to any Secured Party under the Finance Documents, both actual and contingent and whether incurred solely or jointly and as principal or surety or in any other capacity.
 
“Secured Parties” means the Security Agent, any Receiver or Delegate and each of the Agents, the Arrangers and the Creditors from time to time but, in the case of each Agent, Arranger or Creditor, only if it is a party to this Agreement or (in the case of an Agent or a Creditor) has acceded to this Agreement, in the appropriate capacity, pursuant to Clause 13.5 ( Creditor/Agent Accession Undertaking ).
 
“Security” means a mortgage, charge, pledge, lien or other security interest securing any obligation of any person or any other agreement or arrangement having a similar effect.
 
“Security Documents” means:
 
(a)          each of the Security Documents;
 
(b)          any other document entered into at any time by any of the Obligors creating any guarantee, indemnity, Security or other assurance against financial loss in favour of any of the Secured Parties as security for any of the Secured Obligations; and
 
(c)          any Security granted under any covenant for further assurance in any of the documents set out in paragraphs (a) and (b) above.
 
“Security Property” means:
 
(a)          the Transaction Security expressed to be granted in favour of the Security Agent as trustee for the Secured Parties and all proceeds of that Transaction Security;
 
(b)          all obligations expressed to be undertaken by an Obligor to pay amounts in respect of the Liabilities to the Security Agent as trustee for the Secured Parties and secured by the Transaction Security together with all representations and
 
10

 
warranties expressed to be given by an Obligor in favour of the Security Agent as trustee for the Secured Parties;
 
(c)          the Security Agent’s interest in any trust fund created pursuant to Clause 6 (Turnover of Receipts);
 
(d)          any other amounts or property, whether rights, entitlements, choses in action or otherwise, actual or contingent, which the Security Agent is required by the terms of the Finance Documents to hold as trustee on trust for the Secured Parties.
 
“Security Agent’s Spot Rate of Exchange” means, in respect of the conversion of one currency (the “ First Currency ”) into another currency (the “ Second Currency ”) the Security Agent’s spot rate of exchange for the purchase of the Second Currency with the First Currency in the London foreign exchange market at or about 11:00 am (London time) on a particular day, which shall be notified by the Security Agent in accordance with paragraph 11.6(D) ( Security Agent’s obligations ).
 
“Sponsor Affiliate” means each of Blackstone Capital Partners (Cayman) IV LP, Warburg Pincus Private Equity VIII, L.P. and Warburg Pincus International Partners, L.P. (each a “ Sponsor Management Company ”), each of their Affiliates, any trust of which a Sponsor Management Company or any of their Affiliates is a trustee, any partnership of which a Sponsor Management Company or any of their Affiliates is a partner and any trust, fund or other entity which is managed by, or is under the control of, a Sponsor Management Company or any of their Affiliates provided that any such trust, fund or other entity which has been established for at least 6 months solely for the purpose of making, purchasing or investing in loans or debt securities and which is managed or controlled independently from all other trusts, funds or other entities managed or controlled by a Sponsor Management Company or any of their Affiliates which have been established for the primary or main purpose of investing in the share capital of companies shall not constitute a Sponsor Affiliate.
 
“Transaction Security” means the Security created or evidenced or expressed to be created or evidenced under or pursuant to the Security Documents.
 
1.2         Construction
 
(A)         Unless a contrary indication appears, the rules of construction and interpretation set out in clause 1.2 ( Construction of particular terms ) and clause 1.3 ( Interpretation ) of the Facility Agreement shall apply to this Agreement.  In addition a reference in this Agreement to:
 
(i)           any “Agent”, “Arranger”, “Borrower”, “ Creditor ”, “ Hedging Counterparty ”, “ LC Issuing Bank ”, “ KEH ”, “ KEI ”, “ Obligor ”, “ Party ”, “ Security Agent ”, “ Facility Agent ”, “ Arranger ” or “ Lender ” shall, subject to paragraph (iii) below, be construed to be a reference to it in its capacity as such and not in any other capacity;
 
(ii)          any “Agent”, “Arranger”, “Creditor”, “ Obligor ”, “ Hedging Counterparty ”, “ LC Issuing Bank ”, any “ Party ”, or the “ Security
 
11

 
Agent” or any other person shall be construed so as to include its successors in title, permitted assigns and permitted transferees and, in the case of the Security Agent, any person for the time being appointed as Security Agent or Security Agents in accordance with this Agreement;
 
(iii)         any reference to a Lender includes a reference to such Lender in its capacity as LC Issuing Bank, Technical Bank or Account Bank;
 
(iv)         “assets” includes present and future properties, revenues and rights of every description;
 
(v)          a “Finance Document” or any other agreement or instrument is (other than a reference to a “ Finance Document ” or any other agreement or instrument in “ original form ”) a reference to that Finance Document, or other agreement or instrument, as amended, novated, supplemented, extended or restated as permitted by this Agreement;
 
(vi)         “enforcing” (or any derivation) the Transaction Security shall include the appointment of an administrator of an Obligor by the Security Agent;
 
(vii)        “indebtedness” includes any obligation (whether incurred as principal or as surety) for the payment or repayment of money, whether present or future, actual or contingent;
 
(viii)       the “original form” of a “Finance Document” or any other agreement or instrument is a reference to that Finance Document, agreement or instrument as originally entered into;
 
(ix)         a “person” includes any individual, firm, company, corporation, government, state or agency of a state or any association, trust, joint venture, consortium or partnership (whether or not having separate legal personality);
 
(x)          “regulation” includes any regulation, rule, official directive, request or guideline (whether or not having the force of law) of any governmental, intergovernmental or supranational body, agency, department or of any regulatory, self regulatory or other authority or organisation; and
 
(xi)         a provision of law is a reference to that provision as amended or re enacted.
 
(B)          Section, Clause and Schedule headings are for ease of reference only.
 
(C)          A Default is “continuing” if it has not been remedied or waived.
 
1.3         Third Party Rights
 
(A)         Unless expressly provided to the contrary in this Agreement, a person who is not a Party has no right under the Contracts (Rights of Third Parties) Act 1999
 
12

 
(the “Third Parties Rights Act”) to enforce or to enjoy the benefit of any term of this Agreement.
 
(B)          Notwithstanding any term of this Agreement, the consent of any person who is not a Party is not required to rescind or vary this Agreement at any time.
 
(C)          Any Receiver, Delegate or any other person described in Clause 11.9 (No Proceedings) may, subject to this Clause 1.3 ( Third Party Rights ) and the Third Parties Rights Act, rely on any Clause of this Agreement which expressly confers rights on it.
 
2.           RANKING AND PRIORITY
 
2.1         Creditor Liabilities
 
Each of the Parties agrees that the Lender Liabilities and the Hedging Liabilities owed by the Obligors to the Creditors shall rank in right and priority of payment pari passu and without any preference between them.
 
2.2         Transaction Security
 
Each of the Parties agrees that the Transaction Security shall rank and secure the Lender Liabilities and the Hedging Liabilities pari passu and without any preference between them (but only to the extent that such Transaction Security is expressed to secure those Liabilities).
 
3.           LENDERS AND LENDER LIABILITIES
 
3.1         Payment of Lender Liabilities
 
The Obligors may make Payments of the Lender Liabilities at any time in accordance with the Finance Documents.
 
3.2         Amendments and Waivers:  Lenders
 
(A)         The Majority Lenders may amend or waive the terms of the Finance Documents in accordance with the terms of the Facility Agreement at any time.
 
(B)          The Majority Lenders may not amend or waive the terms of the Finance Documents if the amendment or waiver is, in relation to the original form of the Finance Documents:
 
(i)           an amendment or waiver constituting an increase in the Margin, or the inclusion of an additional margin, relating to the Lender Liabilities other than such an increase or addition which is:
 
(a)          contemplated by the original form of the Finance Documents; or
 
(b)          not so contemplated but which is made pursuant to an agreement with the relevant Obligors prior to completion of
 
13

 
primary syndication of the Senior Facilities and is intended to enhance the prospects of a successful syndication of the Senior Facilities;
 
(ii)          an amendment or waiver constituting an increase in, or addition of, any fees or commission other than such an increase or addition which is:
 
(a)          contemplated by the original form of the Finance Documents; or
 
(b)          not so contemplated but which is made pursuant to an agreement with the relevant Obligors prior to completion of primary syndication of the Senior Facilities and is intended to enhance the prospects of a successful syndication of the Senior Facilities; or
 
(iii)         an amendment or waiver which results in any deferral of any scheduled repayment of the Lender Liabilities to a date more than 150 days after the Final Maturity Date for the Facilities.
 
(C)          Without prejudice to Clause 9.2 (Distressed Disposals), the Senior Lenders may not:
 
(i)           amend or waive the terms of the Finance Documents if the amendment or waiver:
 
(a)          would have the effect of changing, or relates to, the nature or scope of the guarantee and indemnity granted under clause 25 ( Guarantee and Indemnity ) of the Facility Agreement; or
 
(b)          relates to the release of any guarantee and indemnity granted under clause 25 (Guarantee and Indemnity ) of the Facility Agreement unless expressly envisaged by the original form of a Finance Document or relating to a sale or disposal of an asset which is a Non-Distressed Disposal; or
 
(ii)          consent to the resignation of an Obligor which has granted a guarantee and indemnity under clause 25 ( Guarantee and Indemnity ) of the Facility Agreement unless each Hedging Counterparty has notified the Security Agent that no payment is due to it from that member of the Group under clause 25 ( Guarantee and Indemnity ) of the Facility Agreement,
 
unless the prior consent of the Hedging Counterparties is obtained.
 
3.3         Designation of Finance Documents
 
The Facility Agent and Kosmos shall not designate a document a “Finance Document” without the prior consent of the Hedging Counterparties if the terms of that document effect a change which would otherwise require the consent of the Hedging Counterparties under Clause 3.2 ( Amendments and Waivers: Lenders ).
 
14

 
3.4         Security:  Lenders
 
Other than as set out in Clause 3.5 (Security: LC Issuing Banks), the Lenders may take, accept or receive the benefit of:
 
(A)         any Security in respect of the Lender Liabilities in addition to the Transaction Security if (except for any Security, permitted under Clause 3.4(B)(iii) ( Security:  LC Issuing Banks )) and to the extent legally possible, at the same time it is also offered either:
 
(i)           to the Security Agent as trustee for the other Secured Parties in respect of their Liabilities; or
 
(ii)          in the case of any jurisdiction in which effective Security cannot be granted in favour of the Security Agent as trustee for the Secured Parties:
 
(a)          to the other Secured Parties in respect of their Liabilities; or
 
(b)          to the Security Agent under a parallel debt structure for the benefit of the other Secured Parties
 
and ranks in the same order of priority as that contemplated in Clause 2.2 (Transaction Security); and
 
(B)          any guarantee, indemnity or other assurance against loss in respect of the Lender Liabilities in addition to those in:
 
(i)           the Facility Agreement;
 
(ii)          this Agreement; or
 
(iii)         any Common Assurance,
 
if (except for any guarantee, indemnity or other assurance against loss permitted under Clause 3.5 (Security: LC Issuing Banks )) and to the extent legally possible, at the same time it is also offered to the other Secured Parties in respect of their Liabilities and ranks in the same order of priority as that contemplated in Clause 2 ( Ranking and Priority ).
 
3.5         Security:  LC Issuing Banks
 
No LC Issuing Bank will, unless the prior consent of the Majority Creditors is obtained, take, accept or receive from any member of the Group or KEH the benefit of any Security, guarantee, indemnity or other assurance against loss in respect of any of the Liabilities owed to it other than:
 
(A)         the Transaction Security;
 
(B)          each guarantee, indemnity or other assurance against loss contained in:
 
15

 
(i)           the Facility Agreement;
 
(ii)          this Agreement; or
 
(iii)         any Common Assurance;
 
(C)          indemnities and assurances against loss contained in any ancillary documents no greater in extent than any of those referred to in paragraph (B) above; or
 
(D)         any LC Cash Cover or Cash Deposit permitted under the Facility Agreement for any Letter of Credit issued by an LC Issuing Bank.
 
3.6         Restriction on Enforcement:  LC Issuing Banks
 
Subject to Clause 3.7 (Permitted Enforcement: LC Issuing Banks), so long as any of the Liabilities (other than any Liabilities owed to the Issuing Banks) are or may be outstanding, none of the Issuing Banks shall be entitled to take any Enforcement Action in respect of any of the Liabilities owed to it.
 
3.7         Permitted Enforcement:  LC Issuing Banks
 
The LC Issuing Banks may take Enforcement Action if:
 
(A)         at the same time as, or prior to, that action, Enforcement Action has been taken in respect of the Lender Liabilities (excluding the Liabilities owing to the LC Issuing Banks), in which case the LC Issuing Banks may take the same Enforcement Action as has been taken in respect of those Lender Liabilities;
 
(B)          that action is contemplated by clause 8 of the Facility Agreement (Letters of Credit - General Provisions) or Clause 3.5 ( Security:  LC Issuing Banks );
 
(C)          that Enforcement Action is taken in respect of LC Cash Cover which has been provided in accordance with the Facility Agreements;
 
(D)         at the same time as or prior to, that action, the consent of the Majority Creditors to that Enforcement Action is obtained; or
 
(E)          an Insolvency Event has occurred in relation to any Obligor or KEI, in which case after the occurrence of that Insolvency Event, each LC Issuing Bank shall be entitled (if it has not already done so) to exercise any right it may otherwise have in respect of that Obligor to:
 
(i)           accelerate any of that Obligor’s Lender Liabilities or declare them prematurely due and payable on demand;
 
(ii)          make a demand under any guarantee, indemnity or other assurance against loss given by that Obligor in respect of any Lender Liabilities;
 
(iii)         exercise any right of set off or take or receive any Payment in respect of any Lender Liabilities of that Obligor; or
 
16

 
(iv)                            claim and prove in the liquidation of that Obligor for the Lender Liabilities owing to it.
 
4.                                    HEDGE COUNTERPARTIES AND HEDGING LIABILITIES
 
4.1                             Identity of Hedging Counterparties
 
No person providing hedging arrangements to any Obligor shall be entitled to share in any of the Transaction Security or in the benefit of any guarantee or indemnity in respect of any of the liabilities arising in relation to those hedging arrangements nor shall those liabilities be treated as Hedging Liabilities unless that person is or becomes a party to this Agreement as a Hedging Counterparty.
 
4.2                             Restriction on Payment:  Hedging Liabilities
 
The Obligors shall not make any Payment of the Hedging Liabilities at any time unless:
 
(A)                             that Payment is permitted under Clause 4.3 (Permitted Payments:  Hedging Liabilities); or
 
(B)                               the taking or receipt of that Payment is permitted under paragraph 4.9(C)
(Permitted Enforcement:  Hedging Counterparties ).
 
4.3                             Permitted Payments:  Hedging Liabilities
 
The Obligors may make Payments to any Hedging Counterparty in respect of the Hedging Liabilities then due to that Hedging Counterparty under any Hedging Agreement in accordance with the terms of that Hedging Agreement and clause 21.2 ( Withdrawals — No Default Outstanding ) of the Facility Agreement:
 
4.4                             Payment obligations continue
 
No Obligor shall be released from the liability to make any Payment (including of default interest, which shall continue to accrue) under any Finance Document by the operation of Clauses 4.2 ( Restriction on Payment:  Hedging Liabilities ).
 
4.5                             No acquisition of Hedging Liabilities
 
The Obligors shall not, and shall procure that no other member of the Group will:
 
(A)                             enter into any Liabilities Acquisition; or
 
(B)                               beneficially own all or any part of the share capital of a company that is party to a Liabilities Acquisition,
 
in respect of any of the Hedging Liabilities unless the prior consent of the Majority Creditors is obtained.
 
17

 
4.6                             Amendments and Waivers:  Hedging Agreements
 
(A)                             Subject to paragraph (B) below, the Hedging Counterparties may not, at any time, amend or waive any term of the Hedging Agreements.
 
(B)                               A Hedging Counterparty may amend or waive any term of a Hedging Agreement in accordance with the terms of that Hedging Agreement if:
 
(i)                                   that amendment or waiver does not breach another term of this Agreement; and
 
(ii)                                that amendment or waiver would not result in a breach of any Finance Document.
 
4.7                             Security:  Hedging Counterparties
 
The Hedging Counterparties may not take, accept or receive the benefit of any Security, guarantee, indemnity or other assurance against loss from any member of the Group or KEH in respect of the Hedging Liabilities other than:
 
(A)                             the Transaction Security;
 
(B)                               any guarantee, indemnity or other assurance against loss contained in:
 
(i)                                   the Facility Agreement;
 
(ii)                                this Agreement;
 
(iii)                             any Common Assurance; or
 
(iv)                            the relevant Hedging Agreement no greater in extent than any of those referred to in paragraphs (i) to (iii) above;
 
(C)                               as otherwise contemplated by Clause 3.3 (Security: Lenders); and
 
(D)                              the indemnities contained in the ISDA Master Agreements (in the case of a Hedging Agreement which is based on an ISDA Master Agreement) or any indemnities which are similar in meaning and effect to those indemnities (in the case of a Hedging Agreement which is not based on an ISDA Master Agreement).
 
4.8                             Restriction on Enforcement:  Hedging Counterparties
 
Subject to Clause 4.9 (Permitted Enforcement:  Hedging Counterparties) and Clause 4.10 (Required Enforcement:  Hedging Counterparties ) and without prejudice to each Hedging Counterparty’s rights under Clauses 8.2 ( Enforcement Instructions ) and 8.3 ( Manner of enforcement ), the Hedging Counterparties shall not take any Enforcement Action in respect of any of the Hedging Liabilities or any of the Hedging Transactions under any of the Hedging Agreements at any time.
 
18

 
4.9                             Permitted Enforcement:  Hedging Counterparties
 
(A)                             To the extent it is able to do so under the relevant Hedging Agreement, a Hedging Counterparty may terminate or close out in whole or in part any Hedging Transaction under that Hedging Agreement prior to its stated maturity:
 
(i)                                   if, prior to a Distress Event, Kosmos has certified to that Hedging Counterparty that that termination or close out would not result in a breach of any Finance Document;
 
(ii)                                if a Distress Event has occurred;
 
(iii)                             if:
 
(a)                                in relation to a Hedging Agreement which is based on the 1992 ISDA Master Agreement:
 
(1)                                an Illegality or Tax Event or Tax Event Upon Merger (each as defined in the 1992 ISDA Master Agreement); or
 
(2)                                an event similar in meaning and effect to a “Force Majeure Event” (as defined in paragraph (B) below),
 
has occurred in respect of that Hedging Agreement;
 
(b)                               in relation to a Hedging Agreement which is based on the 2002 ISDA Master Agreement, an Illegality or Tax Event, Tax Event Upon Merger or a Force Majeure Event (each as defined in the 2002 ISDA Master Agreement) has occurred in respect of that Hedging Agreement; or
 
(c)                                in relation to a Hedging Agreement which is not based on an ISDA Master Agreement, any event similar in meaning and effect to an event described in paragraphs (A) or (B) above has occurred under and in respect of that Hedging Agreement;
 
(iv)                            if an Event of Default has occurred under either clause 29.6 (Insolvency) or clause 29.7 (Insolvency proceedings ) of the Facility Agreement in relation to the Borrower;
 
(v)                               if the Majority Creditors give prior consent to that termination or close-out being made;
 
(vi)                            following a Lender Refinancing;
 
(vii)                         to the extent that that termination or close out is necessary to comply with any Finance Document; or
 
(viii)                      if the Final Discharge Date has occurred.
 
19

 
(B)                               If the Borrower has defaulted on any Payment due under a Hedging Agreement (after allowing any applicable notice or grace periods) and the default has continued unwaived for more than 15 Business Days after notice of that default has been given to the Security Agent pursuant to paragraph 16.3(A) ( Notification of prescribed events ), the relevant Hedging Counterparty:
 
(i)                                   may, to the extent it is able to do so under the relevant Hedging Agreement, terminate or close out in whole or in part any Hedging Transaction under that Hedging Agreement; and
 
(ii)                                until such time as the Security Agent has given notice to that Hedging Counterparty that the Transaction Security is being enforced (or that any formal steps are being taken to enforce the Transaction Security), shall be entitled to exercise any right it might otherwise have to sue for, commence or join legal or arbitration proceedings against any Obligor to recover any Hedging Liabilities due under that Hedging Agreement.
 
(C)                               After the occurrence of an Insolvency Event in relation to an Obligor or KEI, each Hedging Counterparty shall be entitled to exercise any right it may otherwise have in respect of that member of the Group to:
 
(i)                                   prematurely close out or terminate any Hedging Liabilities of that Obligor;
 
(ii)                                make a demand under any guarantee, indemnity or other assurance against loss given by that Obligor in respect of any Hedging Liabilities;
 
(iii)                             exercise any right of set off or take or receive any Payment in respect of any Hedging Liabilities of that Obligor; or
 
(iv)                            claim and prove in the liquidation of that Obligor for the Hedging Liabilities owing to it.
 
4.10                      Required Enforcement:  Hedging Counterparties
 
(A)                             Subject to paragraph (B) below, a Hedging Counterparty shall promptly terminate or close out in full any Hedging Transaction under all or any of the Hedging Agreements to which it is party prior to their stated maturity, following:
 
(i)                                   the occurrence of an Acceleration Event and delivery to it of a notice from the Security Agent that that Acceleration Event has occurred; and
 
(ii)                                delivery to it of a subsequent notice from the Security Agent (acting on the instructions of an Instructing Group) instructing it to do so.
 
(B)                               Paragraph (A) above shall not apply to the extent that that Acceleration Event occurred as a result of an arrangement made between any Obligor and any Creditor with the purpose of bringing about that Acceleration Event.
 
20

 
(C)                               If a Hedging Counterparty is entitled to terminate or close-out any Hedging Transaction under paragraph 4.9(B) ( Permitted Enforcement: Hedging Counterparties ) (or would have been able to if that Hedging Counterparty had given the notice referred to in that paragraph) but has not terminated or closed out each such Hedging Transaction, that Hedging Counterparty shall promptly terminate or close-out in full each such Hedging Transaction following a request to do so by the Security Agent (acting on the instructions of an Instructing Group).
 
4.11                      Treatment of Payments due to Obligors on termination of Hedging Transactions
 
(A)                             If, on termination of any Hedging Transaction under any Hedging Agreement occurring after a Distress Event, a settlement amount or other amount (following the application of any Close Out Netting, Payment Netting or Inter-Hedging Agreement Netting in respect of that Hedging Agreement) falls due from a Hedging Counterparty to the relevant Obligor then that amount shall be paid by that Hedging Counterparty to the Security Agent, treated as the proceeds of enforcement of the Transaction Security and applied in accordance with the terms of this Agreement.
 
(B)                               The payment of that amount by the Hedging Counterparty to the Security Agent in accordance with paragraph (A) above shall discharge the Hedging Counterparty’s obligation to pay that amount to that Obligor.
 
5.                                    EFFECT OF INSOLVENCY EVENT
 
5.1                             LC Cash Cover
 
This Clause 5 is subject to Clause 10.3 (Treatment of LC Cash Cover).
 
5.2                             Payment of distributions
 
(A)                             After the occurrence of an Insolvency Event in relation to an Obligor, KEI or KEH, any Party entitled to receive a distribution out of the assets of that Obligor, KEI or KEH in respect of Liabilities owed to that Party shall, to the extent it is able to do so, direct the person responsible for the distribution of the assets of that Obligor, KEI or KEH to pay that distribution to the Security Agent until the Liabilities owing to the Secured Parties have been paid in full.
 
(B)                               The Security Agent shall apply distributions paid to it under paragraph (A) above in accordance with Clause 10 ( Application of Proceeds ).
 
5.3                             Set Off
 
(A)                             Subject to paragraph (B) below, to the extent that any Obligor’s, KEI’s or KEH’s Liabilities are discharged by way of set off (mandatory or otherwise) after the occurrence of an Insolvency Event in relation to that Obligor, KEI or KEH, any Creditor which benefited from that set off shall pay an amount equal to the amount of the Liabilities owed to it which are discharged by that set off to the
 
21

 
Security Agent for application in accordance with Clause 10 (Application of Proceeds).
 
(B)                               Paragraph (A) above shall not apply to:
 
(i)                                   any Close Out Netting by a Hedging Counterparty;
 
(ii)                                any Payment Netting by a Hedging Counterparty; and
 
(iii)                             any Inter-Hedging Agreement Netting by a Hedging Counterparty.
 
5.4                             Non cash distributions
 
If the Security Agent or any other Secured Party receives a distribution in a form other than in cash in respect of any of the Liabilities, the Liabilities will not be reduced by that distribution until and except to the extent that the realisation proceeds are actually applied towards the Liabilities.
 
5.5                             Filing of claims
 
After the occurrence of an Insolvency Event in relation to any Obligor, KEI or KEH, each Creditor irrevocably authorises the Security Agent (acting in accordance with Clause 5.7 ( Security Agent instructions )), on its behalf, to:
 
(A)                             take any Enforcement Action (in accordance with the terms of this Agreement) against that Obligor, KEI or KEH;
 
(B)                               demand, sue, prove and give receipt for any or all of that Obligor’s, KEI’s or KEH’s Liabilities;
 
(C)                               collect and receive all distributions on, or on account of, any or all of that Obligor’s, KEI’s or KEH’s Liabilities; and
 
(D)                              file claims, take proceedings and do all other things the Security Agent considers reasonably necessary to recover that Obligor’s, KEI’s or KEH’s Liabilities.
 
5.6                             Creditors’ actions
 
Save as prohibited by any applicable law or regulation, each Creditor will:
 
(A)                             do all things that the Security Agent (acting in accordance with Clause 5.7 (Security Agent instructions)) requests in order to give effect to this Clause 5; and
 
(B)                               if the Security Agent is not entitled to take any of the actions contemplated by this Clause 5 or if the Security Agent (acting in accordance with Clause 5.7 ( Security Agent instructions )) requests that a Creditor take that action, undertake that action itself in accordance with the instructions of the Security Agent (acting in accordance with Clause 5.7 ( Security Agent instructions )) or
 
22

 
grant a power of attorney to the Security Agent (on such terms as the Security Agent (acting in accordance with Clause 5.7 ( Security Agent instructions )) may reasonably require) to enable the Security Agent to take such action.
 
5.7                             Security Agent instructions
 
For the purposes of Clause 5.5 (Filing of claims) and Clause 5.6 (Creditors’ actions) the Security Agent shall act:
 
(A)                             on the instructions of the group of Creditors entitled, at that time, to give instructions under Clause 8.2 ( Enforcement Instructions ) or Clause 8.3 ( Manner of enforcement ); or
 
(B)                               in the absence of any such instructions, as the Security Agent sees fit.
 
6.                                    TURNOVER OF RECEIPTS
 
6.1                             LC Cash Cover
 
This Clause 6 is subject to Clause 10.3 (Treatment of LC Cash Cover).
 
6.2                             Turnover by the Creditors
 
Subject to Clause 6.3 (Exclusions) and to Clause 6.4 (Permitted assurance and receipts), if at any time prior to the Final Discharge Date, any Creditor receives or recovers:
 
(A)                             any Payment or distribution of, or on account of or in relation to, any of the Liabilities which is not either:
 
(i)                                   a Permitted Payment; or
 
(ii)                                made in accordance with Clause 10 (Application of Proceeds);
 
(B)                               other than where Clause 5.3 (Set Off) applies, any amount by way of set off in respect of any of the Liabilities owed to it which does not give effect to a Permitted Payment;
 
(C)                               notwithstanding paragraphs (A) and (B) above, and other than where Clause 5.3  (Set-Off) applies, any amount:
 
(i)                                   on account of, or in relation to, any of the Liabilities:
 
(a)                                after the occurrence of a Distress Event; or
 
(b)                               as a result of any other litigation or proceedings against an Obligor (other than after the occurrence of an Insolvency Event in respect of that Obligor); or
 
23

 
(ii)                                by way of set-off in respect of any of the Liabilities owed to it after the occurrence of a Distress Event;
 
(D)                              the proceeds of any enforcement of any Transaction Security except in accordance with Clause 10 (Application of Proceeds ); or
 
(E)                                other than where Clause 5.3 (Set-Off) applies, any distribution in cash or in kind or Payment of, or on account of or in relation to, any of the Liabilities owed by any Obligor which is not in accordance with Clause 10 ( Application of Proceeds ) and which is made as a result of, or after, the occurrence of an Insolvency Event in respect of that Obligor,
 
that Creditor will:
 
(i)                                   in relation to receipts and recoveries not received or recovered by way of set-off:
 
(a)                                hold an amount of that receipt or recovery equal to the Relevant Liabilities (or if less, the amount received or recovered) on trust for the Security Agent and promptly pay that amount to the Security Agent for application in accordance with the terms of this Agreement; and
 
(b)                               promptly pay an amount equal to the amount (if any) by which the receipt or recovery exceeds the Relevant Liabilities to the Security Agent for application in accordance with the terms of this Agreement; and
 
(ii)                                in relation to receipts and recoveries received or recovered by way of set-off, promptly pay an amount equal to that recovery to the Security Agent for application in accordance with the terms of this Agreement.
 
6.3                             Exclusions
 
Clause 6.2 (Turnover by the Creditors) shall not apply to any receipt or recovery by way of:
 
(A)                             Close-Out Netting by a Hedging Counterparty;
 
(B)                               Payment Netting by a Hedging Counterparty; or
 
(C)                               Inter-Hedging Agreement Netting by a Hedging Counterparty.
 
6.4                             Permitted assurance and receipts
 
Nothing in this Agreement shall restrict the ability of any Creditor to:
 
(A)                             arrange with any person which is not a member of the Group any assurance against loss in respect of, or reduction of its credit exposure to, an Obligor (including assurance by way of credit based derivative or sub participation); or
 
24

 
(B)                               make any assignment or transfer permitted by Clause 13 (Changes to the Parties),
 
which:
 
(i)                                   is permitted by the Facility Agreement
 
(a)                                is not in breach of Clause 4.5 (No acquisition of Hedging Liabilities),
 
and that Creditor shall not be obliged to account to any other Party for any sum received by it as a result of that action.
 
6.5                             Sums received by Obligors
 
If any of the Obligors receives or recovers any sum which, under the terms of any of the Finance Documents, should have been paid to the Security Agent, that Obligor will:
 
(A)                             hold an amount of that receipt or recovery equal to the Relevant Liabilities (or if less, the amount received or recovered) on trust for the Security Agent and promptly pay that amount to the Security Agent for application in accordance with the terms of this Agreement; and
 
(B)                               promptly pay an amount equal to the amount (if any) by which the receipt or recovery exceeds the Relevant Liabilities to the Security Agent for application in accordance with the terms of this Agreement.
 
6.6                             Saving provision
 
If, for any reason, any of the trusts expressed to be created in this Clause 6 (Turnover of Receipts) should fail or be unenforceable, the affected Creditor or Obligor will promptly pay an amount equal to that receipt or recovery to the Security Agent to be held on trust by the Security Agent for application in accordance with the terms of this Agreement.
 
7.                                    REDISTRIBUTION
 
7.1                             Recovering Creditor’s rights
 
(A)                             Any amount paid by a Creditor (a “Recovering Creditor”) to the Security Agent under Clause 5 ( Effect of Insolvency Event ) or Clause 6 ( Turnover of Receipts ) shall be treated as having been paid by the relevant Obligor and distributed to the Security Agent, Agents, Arrangers and Creditors (each a “ Sharing Creditor ”) in accordance with the terms of this Agreement.
 
(B)                               On a distribution by the Security Agent under paragraph (A) above of a Payment received by a Recovering Creditor from an Obligor, as between the relevant Obligor and the Recovering Creditor an amount equal to the amount received or recovered by the Recovering Creditor and paid to the Security Agent (the “Shared Amount”) will be treated as not having been paid by that Obligor.
 
25

 
7.2                             Reversal of redistribution
 
(A)                             If any part of the Shared Amount received or recovered by a Recovering Creditor becomes repayable to an Obligor and is repaid by that Recovering Creditor to that Obligor, then:
 
(i)                                   each Sharing Creditor shall, upon request of the Security Agent, pay to the Security Agent for the account of that Recovering Creditor an amount equal to the appropriate part of its share of the Shared Amount (together with an amount as is necessary to reimburse that Recovering Creditor for its proportion of any interest on the Shared Amount which that Recovering Creditor is required to pay) (the “ Redistributed Amount ”); and
 
(ii)                                as between the relevant Obligor and each relevant Sharing Creditor, an amount equal to the relevant Redistributed Amount will be treated as not having been paid by that Obligor.
 
(B)                               The Security Agent shall not be obliged to pay any Redistributed Amount to a Recovering Creditor under paragraph (A)(i) above until it has been able to establish to its satisfaction that it has actually received that Redistributed Amount from the relevant Sharing Creditor.
 
7.3                             Deferral of Subrogation
 
(A)                             No Creditor or Obligor will exercise any rights which it may have by reason of the performance by it of its obligations under the Finance Documents to take the benefit (in whole or in part and whether by way of subrogation or otherwise) of any rights under the Finance Documents of any Creditor which ranks ahead of it in accordance with the priorities set out in Clause 2 ( Ranking and Priority ) until such time as all of the Liabilities owing to each prior ranking Creditor (or, in the case of any Obligor, owing to each Creditor) have been irrevocably paid in full.
 
(B)                               No Subordinated Creditor will exercise any rights which it may have to take the benefit (in whole or in part and whether by way of subrogation or otherwise) of any rights under the Finance Documents of any Creditor until such time as all of the Liabilities owing to each Creditor have been irrevocably paid in full.
 
8.                                    ENFORCEMENT OF TRANSACTION SECURITY
 
8.1                             LC Cash Cover
 
This Clause 8 is subject to Clause 10.3 (Treatment of LC Cash Cover).
 
8.2                             Enforcement Instructions
 
(A)                             The Security Agent may refrain from enforcing the Transaction Security unless instructed otherwise by the Instructing Group.
 
26

 
(B)          Subject to the Transaction Security having become enforceable in accordance with the terms of the Security Documents the Instructing Group may give or refrain from giving instructions to the Security Agent to enforce or refrain from enforcing the Transaction Security as they see fit.
 
(C)          The Security Agent is entitled to rely on and comply with instructions given in accordance with this Clause 8.2 ( Enforcement Instructions ).
 
8.3         Manner of enforcement
 
If the Transaction Security is being enforced in accordance with the terms of the Security Documents pursuant to Clause 8.2 ( Enforcement Instructions ), the Security Agent shall enforce the Transaction Security in such manner (including, without limitation, the selection of any administrator of any Obligor to be appointed by the Security Agent) as the Instructing Group shall instruct or, in the absence of any such instructions, as the Security Agent sees fit.
 
8.4         Exercise of voting rights
 
(A)         Each Creditor agrees with the Security Agent that it will cast its vote in any proposal put to the vote by or under the supervision of any judicial or supervisory authority in respect of any insolvency, pre insolvency or rehabilitation or similar proceedings relating to any Obligor as instructed by the Security Agent.
 
(B)          The Security Agent shall give instructions for the purposes of paragraph (A) of this Clause 8.4 (Exercise of voting rights ) as directed by an Instructing Group.
 
8.5         Waiver of rights
 
To the extent permitted under applicable law and subject to Clause 8.2 (Enforcement Instructions), Clause 8.3 (Manner of enforcement ), Clause 9.2(C) ( Distressed Disposals ) and Clause 10 ( Application of Proceeds ), each of the Secured Parties and the Obligors waives all rights it may otherwise have to require that the Transaction Security be enforced in any particular order or manner or at any particular time or that any sum received or recovered from any person, or by virtue of the enforcement of any of the Transaction Security or of any other security interest, which is capable of being applied in or towards discharge of any of the Secured Obligations is so applied.
 
9.           DISPOSALS
 
9.1         Non-Distressed Disposals
 
(A)         In this Clause 9.1:
 
“Disposal Proceeds” means the proceeds of a Non-Distressed Disposal (as defined in paragraph (B) below).
 
(B)          If, in respect of a disposal of:
 
27

 
(i)           an asset by an Obligor, KEI or KEH; or
 
(ii)          an asset which is subject to the Transaction Security
 
to a person or persons which are not members of the Group:
 
(a)          that disposal is permitted under the Facility Agreement; and
 
(b)          that disposal is not a Distressed Disposal,
 
(a “Non-Distressed Disposal”),
 
the Security Agent is irrevocably authorised (at the cost of the relevant Obligor, KEI or KEH and without any consent, sanction, authority or further confirmation from any Creditor or Obligor, KEI or KEH) but subject to paragraph (C) below:
 
(iii)         to release the Transaction Security or any other claim (relating to a Finance Document) over that asset;
 
(iv)         where that asset consists of shares in the capital of an Obligor or KEI to release the Transaction Security or any other claim (relating to a Finance Document) over that Obligor’s, KEI’s or KEH’s assets;
 
(v)          to execute and deliver or enter into any release of the Transaction Security or any claim described in paragraphs (iii) and (iv) above and issue any certificates of non crystallisation of any floating charge or any consent to dealing that may, in the discretion of the Security Agent, be considered necessary or desirable.
 
(C)          If that Non-Distressed Disposal is not made, each release of Transaction Security or any claim described in paragraph (B) above shall have no effect and the Transaction Security or claim subject to that release shall continue in such force and effect as if that release had not been effected.
 
(D)         Any Disposal Proceeds required by the Facility Agreement to be applied in mandatory prepayment of the Lender Liabilities shall be so applied in accordance with the terms of the Facility Agreement:
 
9.2         Distressed Disposals
 
(A)         Subject to paragraph (D) below, if a Distressed Disposal is being effected the Security Agent is irrevocably authorised (at the cost of the relevant Obligor, KEI or KEH and without any consent, sanction, authority or further confirmation from any Creditor, any Obligor, KEI or KEH):
 
(i)           release of Transaction Security/non crystallisation certificates:  to release the Transaction Security or any other claim over that asset and execute and deliver or enter into any release of that Transaction Security or claim and issue any letters of non crystallisation of any
 
28

 
floating charge or any consent to dealing that may, in the discretion of the Security Agent, be considered necessary or desirable;
 
(ii)          release of liabilities and Transaction Security on a share sale (Obligor):  if the asset which is disposed of consists of shares in the capital of an Obligor, to release:
 
(a)          that Obligor and any Subsidiary of that Obligor from all or any part of:
 
(1)          its Borrowing Liabilities; and
 
(2)          its Guarantee Liabilities.
 
(b)          any Transaction Security granted by that Obligor or KEH or any Subsidiary of that Obligor, over any of its assets; and
 
(c)          any other claim of another Obligor, KEI or KEH over that Obligor’s assets or over the assets of any Subsidiary of that Obligor,
 
on behalf of the relevant Creditors, Obligors, KEI and KEH;
 
(iii)         disposal of liabilities on a share sale:  if the asset which is disposed of consists of shares in the capital of an Obligor and the Security Agent (acting in accordance with paragraph (D) below) decides to dispose of all or any part of:
 
(a)          the Liabilities; or
 
(b)          the Obligor Liabilities,
 
owed by any Obligor or KEI or any Subsidiary of any Obligor or Holding Company:
 
(c)          (if the Security Agent (acting in accordance with paragraph (D) below) does not intend that any transferee of those Liabilities or Obligor Liabilities (the “ Transferee ”) will be treated as a Creditor or a Secured Party for the purposes of this Agreement) to execute and deliver or enter into any agreement to dispose of all or part of those Liabilities or Obligor Liabilities  provided that  notwithstanding any other provision of any Finance Document the Transferee shall not be treated as a Creditor or a Secured Party for the purposes of this Agreement; and
 
(d)          (if the Security Agent (acting in accordance with paragraph (D) below) does intend that any Transferee will be treated as a Creditor or a Secured Party for the purposes of this Agreement) to execute and deliver or enter into any agreement to dispose of:
 
29

 
(1)          all (and not part only) of the Liabilities owed to the Creditors; and
 
(2)          all or part of any other Liabilities and the Obligor Liabilities,
 
on behalf of, in each case, the relevant Creditors and Obligors;
 
(iv)         transfer of obligations in respect of liabilities on a share sale:  if the asset which is disposed of consists of shares in the capital of an Obligor (the “ Disposed Entity ”) and the Security Agent (acting in accordance with paragraph (D) below) decides to transfer to another Obligor, KEI or KEH (the “ Receiving Entity ”) all or any part of the Disposed Entity’s obligations or any obligations of any Subsidiary of that Disposed Entity in respect of the Obligor Liabilities to execute and deliver or enter into any agreement to:
 
(a)          agree to the transfer of all or part of the obligations in respect of those Obligor Liabilities on behalf of the relevant Obligors to which those obligations are owed and on behalf of the Obligors which owe those obligations; and
 
(b)          to accept the transfer of all or part of the obligations in respect of those Obligor Liabilities on behalf of the Receiving Entity or Receiving Entities to which the obligations in respect of those Obligor Liabilities are to be transferred.
 
(B)          The net proceeds of each Distressed Disposal (and the net proceeds of any disposal of Liabilities or Obligor Liabilities pursuant to paragraph (A)(iii) above) shall be paid to the Security Agent for application in accordance with Clause 10 ( Application of Proceeds ) as if those proceeds were the proceeds of an enforcement of the Transaction Security and, to the extent that any disposal of Liabilities or Obligor Liabilities has occurred pursuant to paragraph (A)(iii)(d) above, as if that disposal of Liabilities or Obligor Liabilities had not occurred.
 
(C)          In the case of a Distressed Disposal (or a disposal of Liabilities pursuant to paragraph (A)(iii)(d) above) effected by or at the request of the Security Agent (acting in accordance with paragraph (D) below), the Security Agent shall take reasonable care to obtain a fair market price in the prevailing market conditions (though the Security Agent shall have no obligation to postpone any such Distressed Disposal or disposal of Liabilities in order to achieve a higher price).
 
(D)         For the purposes of paragraphs (A)(i), (A)(ii), (A)(iii), (A)(iv) and (C) above, the Security Agent shall act:
 
(i)           if the relevant Distressed Disposal is being effected by way of enforcement of the Transaction Security, in accordance with Clause 8.3 ( Manner of enforcement ); and
 
(ii)          in any other case:
 
30

 
(a)          on the instructions of the Instructing Group; or
 
(b)          in the absence of any such instructions, as the Security Agent sees fit.
 
10.         APPLICATION OF PROCEEDS
 
10.1       Order of application
 
Subject to Clause 10.2 (Prospective liabilities) and Clause 10.3 (Treatment of LC Cash Cover), all amounts from time to time received or recovered by the Security Agent pursuant to the terms of any Finance Document or in connection with the realisation or enforcement of all or any part of the Transaction Security (for the purposes of this Clause 10, the “ Recoveries ”) shall be held by the Security Agent on trust to apply them at any time as the Security Agent (in its discretion) sees fit, to the extent permitted by applicable law (and subject to the provisions of this Clause 10 ( Application of Proceeds )), in the following order of priority:
 
(A)         in discharging any sums owing to the Security Agent, any Receiver or any Delegate;
 
(B)          in payment of all costs and expenses incurred by any Agent or Creditor in connection with any realisation or enforcement of the Transaction Security taken in accordance with the terms of this Agreement or any action taken at the request of the Security Agent under Clause 5.6 ( Creditors’ actions );
 
(C)          in payment to the Facility Agent on its own behalf for the Facility Agent Liabilities (to the extent such liabilities relate to the non-payment of fees due);
 
(D)         in payment to:
 
(i)           the Facility Agent on behalf of the Lenders; and
 
(ii)          the Hedging Counterparties
 
for application towards the discharge of:
 
(a)          the Lender Liabilities (on a pro rata basis between the Lender Liabilities of each Lender); and
 
(b)          the Hedging Liabilities (on a pro rata basis between the Hedging Liabilities of each Hedging Counterparty);
 
on a pro rata basis between paragraph (A) above and paragraph (B) above and provided that such payments shall be deemed to be paid firstly, towards any interest payments under the Facilities due but unpaid and any scheduled payments due but unpaid under a Hedging Agreement and secondly, towards the remaining Lender Liabilities and Hedging Liabilities:
 
31

 
(E)          if none of the Obligors is under any further actual or contingent liability under any Finance Document or Hedging Agreement, in payment to any person to whom the Security Agent is obliged to pay in priority to any Obligor; and
 
(F)          the balance, if any, in payment to the relevant Obligor.
 
10.2       Prospective liabilities
 
Following a Distress Event the Security Agent may, in its discretion, hold any amount of the Recoveries in an interest bearing suspense or impersonal account(s) in the name of the Security Agent with such financial institution (including itself) and for so long as the Security Agent shall think fit (the interest being credited to the relevant account) for later application under Clause 10.1 ( Order of Application ) in respect of:
 
(A)         any sum to any Security Agent, any Receiver or any Delegate; and
 
(B)          any part of the Liabilities or the Facility Agent Liabilities,
 
that the Security Agent reasonably considers, in each case, might become due or owing at any time in the future.
 
10.3       Treatment of LC Cash Cover
 
(A)         Nothing in this Agreement shall prevent any LC Issuing Bank taking any Enforcement Action in respect of any LC Cash Cover which has been provided for it in accordance with the Facility Agreements.
 
(B)          To the extent that any LC Cash Cover is not held with the Relevant LC Issuing Bank, all amounts from time to time received or recovered in connection with the realisation or enforcement of that LC Cash Cover shall be paid to the Security Agent and shall be held by the Security Agent on trust to apply them at any time as the Security Agent (in its discretion) sees fit, to the extent permitted by applicable law, in the following order of priority:
 
(i)           to the Relevant LC Issuing Bank towards the discharge of the Lender Liabilities for which that LC Cash Cover was provided; and
 
(ii)          the balance, if any, in accordance with Clause 10.1 (Order of Application).
 
10.4       Investment of proceeds
 
Prior to the application of the proceeds of the Security Property in accordance with Clause 10.1 (Order of Application) the Security Agent may, in its discretion, hold all or part of those proceeds in an interest bearing suspense or impersonal account(s) in the name of the Security Agent with such financial institution (including itself) and for so long as the Security Agent shall think fit (the interest being credited to the relevant account) pending the application from time to time of those monies in the Security Agent’s discretion in accordance with the provisions of this Clause 10.
 
32

 
10.5       Currency Conversion
 
(A)         For the purpose of, or pending the discharge of, any of the Secured Obligations the Security Agent may convert any moneys received or recovered by the Security Agent from one currency to another, at the Security Agent’s Spot Rate of Exchange.
 
(B)          The obligations of any Obligor to pay in the due currency shall only be satisfied to the extent of the amount of the due currency purchased after deducting the costs of conversion.
 
10.6       Permitted Deductions
 
The Security Agent shall be entitled, in its discretion, (a) to set aside by way of reserve amounts required to meet and (b) to make and pay, any deductions and withholdings (on account of taxes or otherwise) which it is or may be required by any applicable law to make from any distribution or payment made by it under this Agreement, and to pay all Taxes which may be assessed against it in respect of any of the Charged Property, or as a consequence of performing its duties, or by virtue of its capacity as Security Agent under any of the Finance Documents or otherwise (other than in connection with its remuneration for performing its duties under this Agreement).
 
10.7       Good Discharge
 
(A)         Any payment to be made in respect of the Secured Obligations by the Security Agent:
 
(i)           may be made to the relevant Agent on behalf of its Creditors;
 
(ii)          may be made to the Relevant LC Issuing Bank in accordance with paragraph 10.3(B)(i) (Treatment of LC Cash Cover ); or
 
(iii)         shall be made directly to the Hedging Counterparties,
 
and any payment made in that way shall be a good discharge, to the extent of that payment, by the Security Agent.
 
(B)          The Security Agent is under no obligation to make the payments to the Agents or the Hedging Counterparties under paragraph (A) of this Clause 10.7 in the same currency as that in which the Liabilities owing to the relevant Creditor are denominated.
 
10.8       Calculation of Amounts
 
For the purpose of calculating any person’s share of any sum payable to or by it, the Security Agent shall be entitled to:
 
(A)         notionally convert the Liabilities owed to any person into a common base currency (decided in its discretion by the Security Agent), that notional conversion to be made at the spot rate at which the Security Agent is able to
 
33

 
purchase the notional base currency with the actual currency of the Liabilities owed to that person at the time at which that calculation is to be made; and
 
(B)          assume that all moneys received or recovered as a result of the enforcement or realisation of the Security Property are applied in discharge of the Liabilities in accordance with the terms of the Finance Documents under which those Liabilities have arisen.
 
11.         THE SECURITY AGENT
 
11.1       Trust
 
(A)         The Security Agent declares that it shall hold the Security Property on trust for the Secured Parties on the terms contained in this Agreement.
 
(B)          Each of the parties to this Agreement agrees that the Security Agent shall have only those duties, obligations and responsibilities expressly specified in this Agreement or in the Security Documents to which the Security Agent is expressed to be a party (and no others shall be implied).
 
11.2       No independent power
 
Subject to Clause 10.3 (Treatment of LC Cash Cover), the Secured Parties shall not have any independent power to enforce, or have recourse to, any of the Transaction Security or to exercise any rights or powers arising under the Security Documents except through the Security Agent.
 
11.3       Instructions to Security Agent and exercise of discretion
 
(A)         Subject to paragraphs (D) and (E) below, the Security Agent shall act in accordance with any instructions given to it by an Instructing Group or, if so instructed by an Instructing Group, refrain from exercising any right, power, authority or discretion vested in it as Security Agent and shall be entitled to assume that (i) any instructions received by it from an Agent, the Creditors or a group of Creditors are duly given in accordance with the terms of the Finance Documents and (ii) unless it has received actual notice of revocation, that those instructions or directions have not been revoked.
 
(B)          The Security Agent shall be entitled to request instructions, or clarification of any direction, from an Instructing Group as to whether, and in what manner, it should exercise or refrain from exercising any rights, powers, authorities and discretions and the Security Agent may refrain from acting unless and until those instructions or clarification are received by it.
 
(C)          Save as provided in Clause 8 (Enforcement of Transaction Security), any instructions given to the Security Agent by an Instructing Group shall override any conflicting instructions given by any other Parties.
 
(D)         Paragraph (A) above shall not apply:
 
34

 
(i)           where a contrary indication appears in this Agreement;
 
(ii)          where this Agreement requires the Security Agent to act in a specified manner or to take a specified action;
 
(iii)         in respect of any provision which protects the Security Agent’s own position in its personal capacity as opposed to its role of Security Agent for the Secured Parties including, without limitation, the provisions set out in Clauses 11.5 ( Security Agent’s discretions ) to Clause 11.21 ( Disapplication );
 
(iv)         in respect of the exercise of the Security Agent’s discretion to exercise a right, power or authority under any of:
 
(a)          Clause 9.1 (Non-Distressed Disposals);
 
(b)          Clause 10.1 (Order of application);
 
(c)          Clause 10.2 (Prospective liabilities);
 
(d)          Clause 10.3 (Treatment of LC Cash Cover); and
 
(e)          Clause 10.6 (Permitted Deductions).
 
(E)          If giving effect to instructions given by an Instructing Group would (in the Security Agent’s opinion) have an effect equivalent to an Intercreditor Amendment, the Security Agent shall not act in accordance with those instructions unless consent to it so acting is obtained from each Party (other than the Security Agent) whose consent would have been required in respect of that Intercreditor Amendment.
 
(F)          In exercising any discretion to exercise a right, power or authority under this Agreement where either:
 
(i)           it has not received any instructions from an Instructing Group as to the exercise of that discretion; or
 
(ii)          the exercise of that discretion is subject to paragraph (D)(iv) above,
 
the Security Agent shall do so having regard to the interests of all the Secured Parties.
 
11.4       Security Agent’s Actions
 
Without prejudice to the provisions of Clause 8 (Enforcement of Transaction Security) and Clause 11.3 (Instructions to Security Agent and exercise of discretion ), the Security Agent may (but shall not be obliged to), in the absence of any instructions to the contrary, take such action in the exercise of any of its powers and duties under the Finance Documents as it considers in its discretion to be appropriate.
 
35

 
11.5       Security Agent’s discretions
 
The Security Agent may:
 
(A)         assume (unless it has received actual notice to the contrary from a Hedging Counterparty or from one of the Agents) that (i) no Default has occurred and no Obligor is in breach of or default under its obligations under any of the Finance Documents and (ii) any right, power, authority or discretion vested by any Finance Document in any person has not been exercised;
 
(B)          if it receives any instructions or directions under Clause 8 (Enforcement of Transaction Security) to take any action in relation to the Transaction Security, assume that all applicable conditions under the Finance Documents for taking that action have been satisfied;
 
(C)          engage, pay for and rely on the advice or services of any legal advisers, accountants, tax advisers, surveyors or other experts (whether obtained by the Security Agent or by any other Secured Party) whose advice or services may at any time seem necessary, expedient or desirable;
 
(D)         rely upon any communication or document believed by it to be genuine and, as to any matters of fact which might reasonably be expected to be within the knowledge of a Secured Party, any Creditor or an Obligor, upon a certificate signed by or on behalf of that person; and
 
(E)          refrain from acting in accordance with the instructions of any Party (including bringing any legal action or proceeding arising out of or in connection with the Finance Documents) until it has received any indemnification and/or security that it may in its discretion require (whether by way of payment in advance or otherwise) for all costs, losses and liabilities which it may incur in so acting.
 
11.6       Security Agent’s obligations
 
The Security Agent shall promptly:
 
(A)         copy to (i) each Agent and (ii) each Hedging Counterparty the contents of any notice or document received by it from any Obligor under any Finance Document;
 
(B)          forward to a Party the original or a copy of any document which is delivered to the Security Agent for that Party by any other Party  provided that , except where a Finance Document expressly provides otherwise, the Security Agent is not obliged to review or check the adequacy, accuracy or completeness of any document it forwards to another Party;
 
(C)          inform (i) each Agent and (ii) each Hedging Counterparty of the occurrence of any Default or any default by an Obligor in the due performance of or compliance with its obligations under any Finance Document of which the Security Agent has received notice from any other party to this Agreement; and
 
36

 
(D)         to the extent that a Party (other than the Security Agent) is required to calculate a Dollar Currency Amount, and upon a request by that Party, notify that Party of the relevant Security Agent’s Spot Rate of Exchange.
 
11.7       Excluded obligations
 
Notwithstanding anything to the contrary expressed or implied in the Finance Documents, the Security Agent shall not:
 
(A)         be bound to enquire as to (i) whether or not any Default has occurred or (ii) the performance, default or any breach by an Obligor of its obligations under any of the Finance Documents;
 
(B)          be bound to account to any other Party for any sum or the profit element of any sum received by it for its own account;
 
(C)          be bound to disclose to any other person (including but not limited to any Secured Party) (i) any confidential information or (ii) any other information if disclosure would, or might in its reasonable opinion, constitute a breach of any law or be a breach of fiduciary duty;
 
(D)         have or be deemed to have any relationship of trust or agency with, any Obligor.
 
11.8       Exclusion of liability
 
None of the Security Agent, any Receiver nor any Delegate shall accept responsibility or be liable for:
 
(A)         the adequacy, accuracy or completeness of any information (whether oral or written) supplied by the Security Agent or any other person in or in connection with any Finance Document or the transactions contemplated in the Finance Documents, or any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document;
 
(B)          the legality, validity, effectiveness, adequacy or enforceability of any Finance Document, the Security Property or any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document or the Security Property;
 
(C)          any losses to any person or any liability arising as a result of taking or refraining from taking any action in relation to any of the Finance Documents, the Security Property or otherwise, whether in accordance with an instruction from an Agent or otherwise unless directly caused by its gross negligence or wilful misconduct (and in the case of the Security Agent under the Onshore Security Assignment directly caused by its breach of trust or the duty of care and diligence required of it as trustee under this Agreement);
 
(D)         the exercise of, or the failure to exercise, any judgment, discretion or power given to it by or in connection with any of the Finance Documents, the Security
 
37

 
Property or any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with, the Finance Documents or the Security Property; or
 
(E)          any shortfall which arises on the enforcement or realisation of the Security Property.
 
11.9       No proceedings
 
No Party (other than the Security Agent, that Receiver or that Delegate) may take any proceedings against any officer, employee or agent of the Security Agent, a Receiver or a Delegate in respect of any claim it might have against the Security Agent, a Receiver or a Delegate or in respect of any act or omission of any kind by that officer, employee or agent in relation to any Finance Document or any Security Property and any officer, employee or agent of the Security Agent, a Receiver or a Delegate may rely on this Clause subject to Clause 1.3 ( Third Party Rights ) and the provisions of the Third Parties Rights Act.
 
11.10    Own responsibility
 
Without affecting the responsibility of any Obligor for information supplied by it or on its behalf in connection with any Finance Document, each Secured Party confirms to the Security Agent that it has been, and will continue to be, solely responsible for making its own independent appraisal and investigation of all risks arising under or in connection with any Finance Document including but not limited to:
 
(A)         the financial condition, status and nature of each Obligor;
 
(B)          the legality, validity, effectiveness, adequacy and enforceability of any Finance Document, the Security Property and any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document or the Security Property;
 
(C)          whether that Secured Party has recourse, and the nature and extent of that recourse, against any Party or any of its respective assets under or in connection with any Finance Document, the Security Property, the transactions contemplated by the Finance Documents or any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document or the Security Property;
 
(D)         the adequacy, accuracy and/or completeness of any information provided by the Security Agent or by any other person under or in connection with any Finance Document, the transactions contemplated by any Finance Document or any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document; and
 
(E)          the right or title of any person in or to, or the value or sufficiency of any part of the Charged Property, the priority of any of the Transaction Security or the existence of any Security affecting the Charged Property,
 
38

 
and each Secured Party warrants to the Security Agent that it has not relied on and will not at any time rely on the Security Agent in respect of any of these matters.
 
11.11    No responsibility to perfect Transaction Security
 
The Security Agent shall not be liable for any failure to:
 
(A)         require the deposit with it of any deed or document certifying, representing or constituting the title of any Obligor to any of the Charged Property;
 
(B)          obtain any licence, consent or other authority for the execution, delivery, legality, validity, enforceability or admissibility in evidence of any of the Finance Documents or the Transaction Security;
 
(C)          register, file or record or otherwise protect any of the Transaction Security (or the priority of any of the Transaction Security) under any applicable laws in any jurisdiction or to give notice to any person of the execution of any of the Finance Documents or of the Transaction Security;
 
(D)         take, or to require any of the Obligors to take, any steps to perfect its title to any of the Charged Property or to render the Transaction Security effective or to secure the creation of any ancillary Security under the laws of any jurisdiction; or
 
(E)          require any further assurances in relation to any of the Security Documents.
 
11.12    Insurance by Security Agent
 
(A)         The Security Agent shall not be under any obligation to insure any of the Charged Property, to require any other person to maintain any insurance or to verify any obligation to arrange or maintain insurance contained in the Finance Documents.  The Security Agent shall not be responsible for any loss which may be suffered by any person as a result of the lack of or inadequacy of any such insurance.
 
(B)          Where the Security Agent is named on any insurance policy as an insured party, it shall not be responsible for any loss which may be suffered by reason of, directly or indirectly, its failure to notify the insurers of any material fact relating to the risk assumed by such insurers or any other information of any kind, unless an Agent shall have requested it to do so in writing and the Security Agent shall have failed to do so within fourteen days after receipt of that request.
 
11.13    Custodians and nominees
 
The Security Agent may appoint and pay any person to act as a custodian or nominee on any terms in relation to any assets of the trust as the Security Agent may determine, including for the purpose of depositing with a custodian this Agreement or any document relating to the trust created under this Agreement and the Security Agent shall not be responsible for any loss, liability, expense, demand, cost, claim or
 
39

 
proceedings incurred by reason of the misconduct, omission or default on the part of any person appointed by it under this Agreement or be bound to supervise the proceedings or acts of any person.
 
11.14    Acceptance of title
 
The Security Agent shall be entitled to accept without enquiry, and shall not be obliged to investigate, any right and title that any of the Obligors, KEI or KEH may have to any of the Charged Property and shall not be liable for or bound to require any Obligor to remedy any defect in its right or title.
 
11.15    Refrain from illegality
 
Notwithstanding anything to the contrary expressed or implied in the Finance Documents, the Security Agent may refrain from doing anything which in its opinion will or may be contrary to any relevant law, directive or regulation of any jurisdiction and the Security Agent may do anything which is, in its opinion, necessary to comply with any such law, directive or regulation.
 
11.16    Business with the Obligors
 
The Security Agent may accept deposits from, lend money to, and generally engage in any kind of banking or other business with any of the Obligors.
 
11.17    Winding up of trust
 
If the Security Agent, with the approval of each of the Agents and each Hedging Counterparty, determines that (a) all of the Secured Obligations and all other obligations secured by the Security Documents have been fully and finally discharged and (b) none of the Secured Parties is under any commitment, obligation or liability (actual or contingent) to make advances or provide other financial accommodation to any Obligor pursuant to the Finance Documents:
 
(A)         the trusts set out in this Agreement shall be wound up and the Security Agent shall release, without recourse or warranty, all of the Transaction Security and the rights of the Security Agent under each of the Security Documents; and
 
(B)          any Retiring Security Agent shall release, without recourse or warranty, all of its rights under each of the Security Documents.
 
11.18    Perpetuity period
 
The perpetuity period under the rule against perpetuities, if applicable to this Agreement, shall be the period of eighty years from the date of this Agreement.
 
11.19    Powers supplemental
 
The rights, powers and discretions conferred upon the Security Agent by this Agreement shall be supplemental to the Trustee Act 1925 and the Trustee Act 2000 and in addition
 
40

 
to any which may be vested in the Security Agent by general law or otherwise.
 
11.20    Trustee division separate
 
(A)         In acting as trustee for the Secured Parties, the Security Agent shall be regarded as acting through its trustee division which shall be treated as a separate entity from any of its other divisions or departments.
 
(B)          If information is received by another division or department of the Security Agent, it may be treated as confidential to that division or department and the Security Agent shall not be deemed to have notice of it.
 
11.21    Disapplication
 
Section 1 of the Trustee Act 2000 shall not apply to the duties of the Security Agent in relation to the trusts constituted by this Agreement. Where there are any inconsistencies between the Trustee Act 1925 or the Trustee Act 2000 and the provisions of this Agreement, the provisions of this Agreement shall, to the extent allowed by law, prevail and, in the case of any inconsistency with the Trustee Act 2000, the provisions of this Agreement shall constitute a restriction or exclusion for the purposes of that Act.
 
11.22    Obligors:  Power of Attorney
 
Each Obligor by way of security for its obligations under this Agreement irrevocably appoints the Security Agent to be its attorney to do anything which that Obligor has authorised the Security Agent or any other Party to do under this Agreement or is itself required to do under this Agreement but has failed to do (and the Security Agent may delegate that power on such terms as it sees fit).
 
12.         CHANGE OF SECURITY AGENT AND DELEGATION
 
12.1       Resignation of the Security Agent
 
(A)         The Security Agent may resign and appoint one of its affiliates as successor by giving notice to Kosmos and the Creditors.
 
(B)          Alternatively the Security Agent may resign by giving notice to the other Parties in which case the Majority Creditors may appoint a successor Security Agent.
 
(C)          If the Majority Creditors have not appointed a successor Security Agent in accordance with paragraph (B) above within 30 days after the notice of resignation was given, the Security Agent (after consultation with the Agents) may appoint a successor Security Agent.
 
(D)         The retiring Security Agent (the “Retiring Security Agent”) shall, at its own cost, make available to the successor Security Agent such documents and records and provide such assistance as the successor Security Agent may reasonably request for the purposes of performing its functions as Security Agent under the Finance Documents.
 
41

 
(E)          The Security Agent’s resignation notice shall only take effect upon (i) the appointment of a successor and (ii) the transfer of all of the Security Property to that successor.
 
(F)          Upon the appointment of a successor, the Retiring Security Agent shall be discharged from any further obligation in respect of the Finance Documents (other than its obligations under paragraph 11.17(B) ( Winding up of trust ) and under paragraph (D) above) but shall, in respect of any act or omission by it whilst it was the Security Agent, remain entitled to the benefit of Clauses 11 ( The Security Agent ), 15.1 ( Obligors’ indemnity ) and 15.3 ( Creditors’ indemnity ).  Its successor and each of the other Parties shall have the same rights and obligations amongst themselves as they would have had if that successor had been an original Party.
 
(G)          The Majority Creditors may, by notice to the Security Agent, require it to resign in accordance with paragraph (B) above.  In this event, the Security Agent shall resign in accordance with paragraph (B) above but the cost referred to in paragraph (D) above shall be for the account of the Kosmos.
 
12.2       Delegation
 
(A)         Each of the Security Agent, any Receiver and any Delegate may, at any time, delegate by power of attorney or otherwise to any person for any period, all or any of the rights, powers and discretions vested in it by any of the Finance Documents.
 
(B)          That delegation may be made upon any terms and conditions (including the power to sub delegate) and subject to any restrictions that the Security Agent, that Receiver or that Delegate (as the case may be) may, in its discretion, think fit in the interests of the Secured Parties and it shall not be bound to supervise, or be in any way responsible for any loss incurred by reason of any misconduct or default on the part of any such delegate or sub delegate.
 
12.3       Additional Security Agents
 
(A)         The Security Agent may at any time appoint (and subsequently remove) any person to act as a separate trustee or as a co trustee jointly with it (i) if it considers that appointment to be in the interests of the Secured Parties or (ii) for the purposes of conforming to any legal requirements, restrictions or conditions which the Security Agent deems to be relevant or (iii) for obtaining or enforcing any judgment in any jurisdiction, and the Security Agent shall give prior notice to the Kosmos and each of the Agents of that appointment.
 
(B)          Any person so appointed shall have the rights, powers and discretions (not exceeding those conferred on the Security Agent by this Agreement) and the duties and obligations that are conferred or imposed by the instrument of appointment.
 
(C)          The remuneration that the Security Agent may pay to that person, and any costs and expenses (together with any applicable VAT) incurred by that person in
 
42

 
performing its functions pursuant to that appointment shall, for the purposes of this Agreement, be treated as costs and expenses incurred by the Security Agent.
 
13.         CHANGES TO THE PARTIES
 
13.1       Assignments and transfers
 
No Party may assign any of its rights and benefits or transfer any of its rights, benefits and obligations in respect of any Finance Documents or the Liabilities except as permitted by this Clause 13.
 
13.2       Change of Lender
 
(A)         A Lender may assign any of its rights and benefits or transfer by novation any of its rights, benefits and obligations in respect of any Finance Documents or the Liabilities if:
 
(i)           that assignment or transfer is in accordance with the terms of the Facility Agreement; and
 
(ii)          any assignee or transferee has (if not already party to this Agreement as a Lender acceded to this Agreement, as a Lender, pursuant to Clause 13.5 ( Creditor/Agent Accession Undertaking ).
 
(B)          For the avoidance of doubt, a person that is party to this Agreement as a Lender and a Hedging Counterparty, shall not cease to be a Hedging Counterparty solely by ceasing to be a Lender.
 
13.3       Change of Hedging Counterparty
 
A Hedging Counterparty may (in accordance with the terms of the relevant Hedging Agreement and subject to any consent required under that Hedging Agreement) transfer any of its rights and benefits or obligations in respect of the Hedging Agreements to which it is a party if any transferee has (if not already party to this Agreement as a Hedging Counterparty) acceded to:
 
(A)         this Agreement; and
 
(B)          the Facility Agreements,
 
as a Hedging Counterparty pursuant to Clause 13.5 (Creditor/Agent Accession Undertaking).
 
13.4       Change of Agent
 
No person shall become an Agent unless at the same time, it accedes to this Agreement as a Facility Agent, pursuant to Clause 13.5 ( Creditor/Agent Accession Undertaking ).
 
43

 
13.5       Creditor/Agent Accession Undertaking
 
With effect from the date of acceptance by the Security Agent and, in the case of a Hedging Counterparty or an Affiliate of a Lender, the Facility Agent of a Creditor/Agent Accession Undertaking duly executed and delivered to the Security Agent by the relevant acceding party or, if later, the date specified in that Creditor/Agent Accession Undertaking:
 
(A)         any Party ceasing entirely to be a Creditor or Agent shall be discharged from further obligations towards the Security Agent and other Parties under this Agreement and their respective rights against one another shall be cancelled (except in each case for those rights which arose prior to that date); and
 
(B)          as from that date, the replacement or new Creditor or Agent shall assume the same obligations, and become entitled to the same rights, as if it had been an original Party to this Agreement in that capacity; and
 
(C)          any party acceding to this Agreement as a Hedging Counterparty shall also become party to the Facility Agreement as a Hedging Counterparty (as the case may be) and shall assume the same obligations and become entitled to the same rights as if it had been an original party to the Facility Agreement as a Hedging Counterparty.
 
13.6       New Obligor
 
(A)         If any member of the Group:
 
(i)           incurs any Liabilities; or
 
(ii)          gives any security, guarantee, indemnity or other assurance against loss in respect of any of the Liabilities
 
Kosmos will procure that the person incurring those Liabilities or giving that assurance accedes to this Agreement as an Obligor, in accordance with paragraph (B) below, no later than contemporaneously with the incurrence of those Liabilities or the giving of that assurance.
 
(B)          With effect from the date of acceptance by the Security Agent of an Obligor Accession Deed duly executed and delivered to the Security Agent by the new Obligor or, if later, the date specified in the Obligor Accession Deed, the new Obligor shall assume the same obligations and become entitled to the same rights as if it had been an original Party to this Agreement as an Obligor.
 
13.7       Additional parties
 
(A)         Each of the Parties appoints the Security Agent to receive on its behalf each Obligor Accession Deed and Creditor/Agent Accession Undertaking delivered to the Security Agent and the Security Agent shall, subject to paragraph (C) below, as soon as reasonably practicable after receipt by it, sign and accept the same if it appears on its face to have been completed, executed and, where applicable, delivered in the form contemplated by this Agreement or, where applicable, by the Facility Agreement.
 
44

 
(B)          In the case of a Creditor/Agent Accession Undertaking delivered to the Security Agent by any party acceding to this Agreement as a Hedging Counterparty:
 
(i)           the Security Agent shall, as soon as practicable after signing and accepting that Creditor/Agent Accession Undertaking in accordance with paragraph (A) above, deliver that Creditor/Agent Accession Undertaking to the Facility Agent; and
 
(ii)          the Facility Agent shall, as soon as practicable after receipt by it, sign and accept that Creditor/Agent Accession Undertaking if it appears on its face to have been completed, executed and delivered in the form contemplated by this Agreement.
 
(C)          The Security Agent shall only be obliged to sign and accept an Obligor Accession Deed or Creditor/Agent Accession Undertaking received by it once it is satisfied that it has complied with all necessary “know your customer” or similar other checks under all applicable laws and regulations in relation to the accession by the prospective party to this Agreement.
 
(D)         Each Party shall promptly upon the request of the Security Agent supply, or procure the supply of, such documentation and other evidence as is reasonably requested by the Security Agent (for itself) from time to time in order for the Security Agent to carry out and be satisfied with the results of all necessary “know your customer” or other similar checks under all applicable laws and regulations pursuant to the transactions contemplated in the Finance Documents.
 
14.         COSTS AND EXPENSES
 
14.1       Security Agent’s ongoing costs
 
(A)         In the event of (i) a Default or (ii) the Security Agent considering it necessary or expedient or (iii) the Security Agent being requested by an Obligor or an Instructing Group to undertake duties which the Security Agent and the Borrower agree to be of an exceptional nature and/or outside the scope of the normal duties of the Security Agent under the Finance Documents, the Borrower shall pay to the Security Agent any additional remuneration (together with any applicable VAT) that may be agreed between them.
 
(B)          If the Security Agent and the Borrower fail to agree upon the nature of those duties or upon any additional remuneration, that dispute shall be determined by an investment bank (acting as an expert and not as an arbitrator) selected by the Security Agent and approved by the Borrower or, failing approval, nominated (on the application of the Security Agent) by the President for the time being of the Law Society of England and Wales (the costs of the nomination and of the investment bank being payable by the Borrower) and the determination of any investment bank shall be final and binding upon the parties to this Agreement.
 
45

 
14.2       Transaction expenses
 
The Borrower shall, within 15 Business Days, pay the Security Agent the amount of all costs and expenses (including legal fees) (together with any applicable VAT) reasonably incurred by the Security Agent and any Receiver or Delegate in connection with the negotiation, preparation, printing, execution, syndication and perfection of:
 
(A)         this Agreement and any other documents referred to in this Agreement and the Transaction Security; and
 
(B)          any other Finance Documents executed after the date of this Agreement.
 
14.3       Stamp taxes
 
The Borrower shall (in accordance with the terms of the other Finance Documents) pay and, within five Business Days of demand, indemnify the Security Agent against any cost, loss or liability the Security Agent incurs in relation to all stamp duty, registration and other similar Taxes payable in respect of any Finance Document.
 
14.4       Interest on demand
 
If any Creditor or Obligor fails to pay any amount payable by it under this Agreement on its due date, interest shall accrue on the overdue amount (and be compounded with it) from the due date up to the date of actual payment (both before and after judgment and to the extent interest at a default rate is not otherwise being paid on that sum) at the rate which is one per cent. per annum over the rate at which the Security Agent was being offered, by leading banks in the London interbank market, deposits in an amount comparable to the unpaid amounts in the currencies of those amounts for any period(s) that the Security Agent may from time to time select.
 
14.5       Enforcement and preservation costs
 
Kosmos shall, within five Business Days of demand, pay to the Security Agent the amount of all costs and expenses (including legal fees and together with any applicable VAT) incurred by it in connection with the enforcement of or the preservation of any rights under any Finance Document and the Transaction Security and any proceedings instituted by or against the Security Agent as a consequence of taking or holding the Transaction Security or enforcing these rights.
 
15.         INDEMNITIES
 
15.1       Obligors’ indemnity
 
Each Obligor shall promptly indemnify the Security Agent and every Receiver and Delegate against any cost, loss or liability (together with any applicable VAT) incurred by any of them:
 
(A)         in relation to or as a result of:
 
(i)           any failure by the Borrower to comply with obligations under Clause 14 (Costs and Expenses);
 
46

 
(ii)                                the taking, holding, protection or enforcement of the Transaction Security;
 
(iii)                             the exercise of any of the rights, powers, discretions and remedies vested in the Security Agent, each Receiver and each Delegate by the Finance Documents or by law; or
 
(iv)                            any default by any Obligor in the performance of any of the obligations expressed to be assumed by it in the Finance Documents; or
 
(B)                               which otherwise relates to any of the Security Property or the performance of the terms of this Agreement (otherwise than as a result of its gross negligence or wilful misconduct and in the case of the Security Agent under the Onshore Security Assignment as a result of its breach of trust or the duty of care and diligence required of it as trustee under this Agreement).
 
Each Obligor expressly acknowledges and agrees that the continuation of its indemnity obligations under this Clause 15.1 ( Obligors’ indemnity ) will not be prejudiced by any release or disposal under Clause 9.2 ( Distressed Disposals ) taking into account the operation of that Clause 9.2.
 
15.2                      Priority of indemnity
 
The Security Agent and every Receiver and Delegate may, in priority to any payment to the Secured Parties, indemnify itself out of the Charged Property in respect of, and pay and retain, all sums necessary to give effect to the indemnity in Clause 15.1 ( Obligors’ indemnity ) and shall have a lien on the Transaction Security and the proceeds of the enforcement of the Transaction Security for all moneys payable to it.
 
15.3                      Creditors’ indemnity
 
(A)                             Each Creditor shall (in the proportion that the Liabilities due to it bears to the aggregate of the Liabilities due to all the Creditors for the time being (or, if the Liabilities due to each of those Creditors is zero, immediately prior to their being reduced to zero)), indemnify the Security Agent and every Receiver and every Delegate, within three Business Days of demand, against any cost, loss or liability incurred by any of them (otherwise than by reason of the relevant Security Agent’s, Receiver’s or Delegate’s gross negligence or wilful misconduct and in the case of the Security Agent under the Onshore Security Assignment as a result of its breach of trust or the duty of care and diligence required of it as trustee under this Agreement) in acting as Security Agent, Receiver or Delegate under the Finance Documents (unless the relevant Security Agent, Receiver or Delegate has been reimbursed by an Obligor pursuant to a Finance Document) and the Obligors shall jointly and severally indemnify each Creditor against any payment made by it under this Clause 15.
 
(B)                               For the purposes only of paragraph (A) above, to the extent that any Hedging Transaction under a Hedging Agreement has not been terminated or closed out, the Hedging Liabilities due to any Hedging Counterparty in respect of that Hedging Transaction will be deemed to be:
 
47

 
(i)                                   if the relevant Hedging Agreement is based on an ISDA Master Agreement, the amount, if any, which would be payable to it under that Hedging Agreement in respect of those Hedging Transactions, if the date on which the calculation is made was deemed to be an Early Termination Date (as defined in the relevant ISDA Master Agreement) for which the relevant Obligor is the Defaulting Party (as defined in the relevant ISDA Master Agreement); or
 
(ii)                                if the relevant Hedging Agreement is not based on an ISDA Master Agreement, the amount, if any, which would be payable to it under that Hedging Agreement in respect of that Hedging Transaction, if the date on which the calculation is made was deemed to be the date on which an event similar in meaning and effect (under that Hedging Agreement) to an Early Termination Date (as defined in any ISDA Master Agreement) occurred under that Hedging Agreement for which the relevant Obligor is in a position similar in meaning and effect (under that Hedging Agreement) to that of a Defaulting Party (under and as defined in the same ISDA Master Agreement),
 
that amount, in each case, to be certified by the relevant Hedging Counterparty and as calculated in accordance with the relevant Hedging Agreement.
 
15.4                      Borrower’s indemnity to Creditors
 
The Borrower shall promptly and as principal obligor indemnify each Creditor against any cost, loss or liability (together with any applicable VAT), whether or not reasonably foreseeable, incurred by any of them in relation to or arising out of the operation of Clause 9.2 ( Distressed Disposals ).
 
16.                             INFORMATION
 
16.1                      Information and dealing
 
(A)                             The Creditors shall provide to the Security Agent from time to time (through their respective Agents in the case of a Lender) any information that the Security Agent may reasonably specify as being necessary or desirable to enable the Security Agent to perform its functions as trustee.
 
(B)                               Each Lender shall deal with the Security Agent exclusively through its Agent and the Hedging Counterparties shall deal directly with the Security Agent and shall not deal through any Agent.
 
(C)                               No Agent shall be under any obligation to act as agent or otherwise on behalf of any Hedging Counterparty except as expressly provided for in, and for the purposes of, this Agreement.
 
16.2                      Disclosure
 
Notwithstanding any agreement to the contrary, each of the Obligors consents, until the Final Discharge Date, to the disclosure by any of the Creditors, the Agents, the
 
48

 
Arrangers and the Security Agent to each other (whether or not through an Agent or the Security Agent) of such information concerning the Obligors obtained by it in that capacity as any Creditor, any Agent, any Arranger or the Security Agent shall see fit.
 
16.3                      Notification of prescribed events
 
(A)                             If an Event of Default either occurs or ceases to be continuing the Facility Agent shall, upon becoming aware of that occurrence or cessation, notify the Security Agent and the Security Agent shall, upon receiving that notification, notify each Hedging Counterparty.
 
(B)                               If an Acceleration Event occurs the Facility Agent shall notify the Security Agent and the Security Agent shall, upon receiving that notification, notify each other Party.
 
(C)                               If the Security Agent enforces, or takes formal steps to enforce, any of the Transaction Security it shall notify each Party of that action.
 
(D)                              If any Creditor exercises any right it may have to enforce, or to take formal steps to enforce, any of the Transaction Security it shall notify the Security Agent and the Security Agent shall, upon receiving that notification, notify each Party of that action.
 
(E)                                If an Obligor defaults on any Payment due under a Hedging Agreement, the Hedging Counterparty which is party to that Hedging Agreement shall, upon becoming aware of that default, notify the Security Agent and the Security Agent shall, upon receiving that notification, notify the Facility Agent and each other Hedging Counterparty.
 
(F)                                If a Hedging Counterparty terminates or closes-out, in whole or in part, any Hedging Transaction under any Hedging Agreement under Clause 4.9 ( Permitted Enforcement: Hedging Counterparties ) it shall notify the Security Agent and the Security Agent shall, upon receiving that notification, notify each Agent and each other Hedging Counterparty.
 
(G)                               If a Mandatory Prepayment is waived the Facility Agent shall notify the Security Agent of the amount of the Mandatory Prepayment waived and the Security Agent shall, upon receiving that notification, notify each Hedging Counterparty.
 
17.                             NOTICES
 
17.1                      Communications in writing
 
Any communication to be made under or in connection with this Agreement shall be made in writing and, unless otherwise stated, may be made by fax or letter.
 
49

 
17.2                      Security Agent’s communications with Lenders and Hedging Counterparties
 
The Security Agent shall be entitled to carry out all dealings:
 
(A)                             with the Lenders and the Arrangers through their respective Agents and may give to the Agents, as applicable, any notice or other communication required to be given by the Security Agent to a Lender or Arranger; and
 
(B)                               with each Hedging Counterparty directly with that Hedging Counterparty.
 
17.3                      Addresses
 
The address and fax number (and the department or officer, if any, for whose attention the communication is to be made) of each Party for any communication or document to be made or delivered under or in connection with this Agreement is:
 
(A)                             in the case of the Original Obligors, that identified with its name below;
 
(B)                               in the case of the Security Agent, that identified with its name below; and
 
(C)                               in the case of each other Party, that notified in writing to the Security Agent on or prior to the date on which it becomes a Party
 
or any substitute address, fax number or department or officer which that Party may notify to the Security Agent (or the Security Agent may notify to the other Parties, if a change is made by the Security Agent) by not less than five Business Days’ notice.
 
17.4                      Delivery
 
(A)                             Any communication or document made or delivered by one person to another under or in connection with this Agreement will only be effective:
 
(i)                                   if by way of fax, when received in legible form; or
 
(ii)                                if by way of letter, when it has been left at the relevant address or five Business Days after being deposited in the post postage prepaid in an envelope addressed to it at that address,
 
and, if a particular department or officer is specified as part of its address details provided under Clause 17.3 ( Addresses ), if addressed to that department or officer.
 
(B)                              Any communication or document to be made or delivered to the Security Agent will be effective only when actually received by the Security Agent and then only if it is expressly marked for the attention of the department or officer identified with the Security Agent’s signature below (or any substitute department or officer as the Security Agent shall specify for this purpose).
 
50

 
(C)                               Any communication or document made or delivered to the Kosmos in accordance with this Clause 17.4 will be deemed to have been made or delivered to each of the Obligors.
 
17.5                      Notification of address and fax number
 
Promptly upon receipt of notification of an address and fax number or change of address or fax number pursuant to Clause 17.3 ( Addresses ) or changing its own address or fax number, the Security Agent shall notify the other Parties.
 
17.6                      Electronic communication
 
(A)                             Any communication to be made between the Security Agent and an Agent, an Arranger, a Lender or a Hedging Counterparty under or in connection with this Agreement may be made by electronic mail or other electronic means, if the Security Agent and the relevant Agent, Arranger, Lender or Hedging Counterparty:
 
(i)                                   agree that, unless and until notified to the contrary, this is to be an accepted form of communication;
 
(ii)                                notify each other in writing of their electronic mail address and/or any other information required to enable the sending and receipt of information by that means; and
 
(iii)                             notify each other of any change to their address or any other such information supplied by them.
 
(B)                               Any electronic communication made between the Security Agent and an Agent, an Arranger, a Lender or a Hedging Counterparty will be effective only when actually received in readable form and in the case of any electronic communication made by a Lender, Hedging Counterparty, Arranger or Agent to the Security Agent only if it is addressed in such a manner as the Security Agent shall specify for this purpose.
 
17.7                      English language
 
(A)                             Any notice given under or in connection with this Agreement must be in English.
 
(B)                               All other documents provided under or in connection with this Agreement must be:
 
(i)                                   in English; or
 
(ii)                                if not in English, and if so required by the Security Agent, accompanied by a certified English translation and, in this case, the English translation will prevail unless the document is a constitutional, statutory or other official document.
 
51

 
18.                             PRESERVATION
 
18.1                      Partial invalidity
 
If, at any time, any provision of this Agreement is or becomes illegal, invalid or unenforceable in any respect under any law of any jurisdiction, neither the legality, validity or enforceability of the remaining provisions nor the legality, validity or enforceability of that provision under the law of any other jurisdiction will in any way be affected or impaired.
 
18.2                      No impairment
 
If, at any time after its date, any provision of a Finance Document (including this Agreement) is not binding on or enforceable in accordance with its terms against a person expressed to be a party to that Finance Document, neither the binding nature nor the enforceability of that provision or any other provision of that Finance Document will be impaired as against the other party(ies) to that Finance Document.
 
18.3                      Remedies and waivers
 
No failure to exercise, nor any delay in exercising, on the part of any Party, any right or remedy under this Agreement shall operate as a waiver, nor shall any single or partial exercise of any right or remedy prevent any further or other exercise or the exercise of any other right or remedy.  The rights and remedies provided in this Agreement are cumulative and not exclusive of any rights or remedies provided by law.
 
18.4                      Waiver of defences
 
The provisions of this Agreement will not be affected by an act, omission, matter or thing which, but for this Clause 18.4, would reduce, release or prejudice the subordination and priorities expressed to be created by this Agreement including (without limitation and whether or not known to any Party):
 
(A)                             any time, waiver or consent granted to, or composition with, any Obligor or other person;
 
(B)                               the release of any Obligor or any other person under the terms of any composition or arrangement with any creditor of any Obligor;
 
(C)                               the taking, variation, compromise, exchange, renewal or release of, or refusal or neglect to perfect, take up or enforce, any rights against, or security over assets of, any Obligor or other person or any non presentation or non observance of any formality or other requirement in respect of any instrument or any failure to realise the full value of any Security;
 
(D)                              any incapacity or lack of power, authority or legal personality of or dissolution or change in the members or status of any Obligor or other person;
 
(E)                                any amendment, novation, supplement, extension (whether of maturity or otherwise) or restatement (in each case, however fundamental and of
 
52

 
whatsoever nature, and whether or not more onerous) or replacement of a Finance Document or any other document or security;
 
(F)                                any unenforceability, illegality or invalidity of any obligation of any person under any Finance Document or any other document or security;
 
(G)                               any intermediate Payment of any of the Liabilities owing to the Creditors in whole or in part; or
 
(H)                              any insolvency or similar proceedings.
 
18.5                      Priorities not affected
 
Except as otherwise provided in this Agreement the priorities referred to in Clause 2 (Ranking and Priority) will:
 
(A)                             not be affected by any reduction or increase in the principal amount secured by the Transaction Security in respect of the Liabilities owing to the Creditors or by any intermediate reduction or increase in, amendment or variation to any of the Finance Documents, or by any variation or satisfaction of, any of the Liabilities or any other circumstances;
 
(B)                               apply regardless of the order in which or dates upon which this Agreement and the other Finance Documents are executed or registered or notice of them is given to any person; and
 
(C)                               secure the Liabilities owing to the Creditors in the order specified, regardless of the date upon which any of the Liabilities arise or of any fluctuations in the amount of any of the Liabilities outstanding.
 
19.                             CONSENTS, AMENDMENTS AND OVERRIDE
 
19.1                      Required consents
 
(A)                             Subject to paragraph (B) below, to Clause 19.4 (Exceptions) and to Clause 19.5 (Snooze/Lose), this Agreement may be amended or waived only with the consent of the Agents, the Majority Lenders and the Security Agent.
 
(B)                               An amendment or waiver that has the effect of changing or which relates to:
 
(i)                                   Clause 7 (Redistribution), Clause 10 (Application of Proceeds) or this Clause 19 (Consents, amendments and override );
 
(ii)                                paragraphs 11.3(D)(iii), 11.3(E) and11.3(F) (Instructions to Security Agent and exercise of discretion); or
 
(iii)                             the order of priority or subordination under this Agreement,
 
shall not be made without the consent of:
 
53

 
(a)                               the Agents;
 
(b)                              the Lenders;
 
(c)                               each Hedging Counterparty (to the extent that the amendment or waiver would adversely affect the Hedging Counterparty); and
 
(d)                              the Security Agent.
 
19.2                      Amendments and Waivers: Transaction Security Documents
 
(A)                             Subject to paragraph (B) below and to Clause 19.4 (Exceptions) and unless the provisions of any Finance Document expressly provide otherwise, the Security Agent may, if authorised by an Instructing Group, and if the Borrower consents, amend the terms of, waive any of the requirements of or grant consents under, any of the Transaction Security Documents which shall be binding on each Party.
 
(B)                               Subject to paragraph 19.4(C) (Exceptions), the prior consent of the Creditors is required to authorise any amendment or waiver of, or consent under, any Transaction Security Document which would affect the nature or scope of the Charged Property or the manner in which the proceeds of enforcement of the Transaction Security are distributed.
 
19.3                      Effectiveness
 
Any amendment, waiver or consent given in accordance with this Clause 19 (Consents, Amendments and Override) will be binding on all Parties and the Security Agent may effect, on behalf of any Agent, Arranger or Creditor, any amendment, waiver or consent permitted by this Clause 19 ( Consents, Amendments and Override ).
 
19.4                      Exceptions
 
(A)                             Subject to paragraph (C) below, if the amendment, waiver or consent may impose new or additional obligations on or withdraw or reduce the rights of any Party other than:
 
(i)                                   in the case of a Creditor, in a way which affects or would affect Creditors of that Party’s class generally; or
 
(ii)                                in the case of an Obligor, to the extent consented to by Kosmos under paragraph 19.2(A) ( Amendments and Waivers: Transaction Security Documents ),
 
the consent of that Party is required.
 
(B)                               Subject to paragraph (C) below, an amendment, waiver or consent which relates to the rights or obligations of an Agent, an Arranger, the Security Agent (including, without limitation, any ability of the Security Agent to act in its discretion under this Agreement) or a Hedging Counterparty may not be
 
54

 
effected without the consent of that Agent or, as the case may be, that Arranger, the Security Agent or that Hedging Counterparty.
 
(C)                               Neither paragraph (A) nor (B)above, nor paragraph 19.2(B) (Amendments and Waivers: Transaction Security Documents ) shall apply:
 
(i)                                   to any release of Transaction Security, claim or Liabilities; or
 
(ii)                                to any consent
 
which, in each case, the Security Agent gives in accordance with Clause 9 (Disposals).
 
19.5                      Enforcement Action
 
For the avoidance of doubt, as between on the one hand, the Creditors and, on the other hand, the Obligors, nothing in this Agreement shall give the Creditors a greater or any additional right in relation to taking a particular Enforcement Action (including as to the time at which such Enforcement Action may be taken and/or the circumstances under which any Enforcement Action may be taken) than exists under the terms of the other Finance Documents or at law.
 
19.6                      Snooze/Lose
 
(A)                             If in relation to:
 
(i)                                   a request for a Consent in relation to any of the terms of this Agreement;
 
(ii)                                a request to participate in any other vote of Creditors under the terms of this Agreement;
 
(iii)                             a request to approve any other action under this Agreement; or
 
(iv)                            a request to provide any confirmation or notification under this Agreement;
 
any Creditor:
 
(1)                                fails to respond to that request within 10 Business Days of that request being made; or
 
(2)                                (in the case of paragraphs (i) to (iii) above and if so requested by the Security Agent), fails to provide details of its Credit Participation to the Security Agent within the timescale specified by the Security Agent:
 
(v)                               in the case of paragraphs (i) to (iii) above, that Creditor’s Credit Participation (as the case may be) shall be deemed to be zero for the purpose of calculating the Credit Participations when ascertaining
 
55

 
whether any relevant percentage of Credit Participations has been obtained to give that Consent, carry that vote or approve that action;
 
(vi)                            in the case of paragraph (iv) above, that confirmation or notification shall be deemed to have been given.
 
19.7                      Disenfranchisement of Sponsor Affiliates
 
(A)                             For so long as a Sponsor Affiliate (i) beneficially owns a Commitment or (ii) has entered into a sub-participation agreement relating to a Commitment or other agreement or arrangement having a substantially similar economic effect and such agreement or arrangement has not been terminated:
 
(i)                                   in ascertaining:
 
(a)                                an Instructing Group; or
 
(b)                               whether:
 
(1)                                any relevant percentage of Commitments or Credit Participations; or
 
(2)                                the agreement of any specified group of Creditors,
 
has been obtained to approve any request for a Consent or to carry any other vote or approve any action under this Agreement,
 
that Commitment and any associated Credit Participation shall be deemed to be zero and, subject to paragraph (ii) below, that Sponsor Affiliate (or the person with whom it has entered into that sub-participation, other agreement or arrangement (a “ Counterparty ”)) shall be deemed not to be a Lender.
 
(ii)                                Paragraph (A) above shall not apply to the extent that a Counterparty (other than a Sponsor Affiliate) is a Lender by virtue otherwise than by beneficially owning the relevant Commitment.
 
(B)                               Each Sponsor Affiliate that is a Lender agrees that:
 
(i)                                   in relation to any meeting or conference call to which all the Creditors are invited to attend or participate, it shall not attend or participate in the same if so requested by the Security Agent or, unless the Security Agent otherwise agrees, be entitled to receive the agenda or any minutes of the same; and
 
(ii)                                it shall not, unless the Security Agent otherwise agrees, be entitled to receive any report or other document prepared at the behest of, or on the instructions of, the Security Agent or one or more of the Creditors.
 
56

 
19.8                      Calculation of Credit Participations
 
For the purpose of ascertaining whether any relevant percentage of Credit Participations has been obtained under this Agreement, the Security Agent may notionally convert the Credit Participations into their Dollar Currency Amounts.
 
19.9                      No liability
 
None of the Lenders or the Facility Agent will be liable to any other Creditor, Agent or Obligor for any Consent given or deemed to be given under this Clause 19.
 
19.10               Agreement to override
 
Unless expressly stated otherwise in this Agreement, this Agreement overrides anything in the Finance Documents to the contrary.
 
20.                             COUNTERPARTS
 
This Agreement may be executed in any number of counterparts, and this has the same effect as if the signatures on the counterparts were on a single copy of this Agreement.
 
21.                             GOVERNING LAW
 
This Agreement is governed by English law.
 
22.                             ENFORCEMENT
 
22.1                      Jurisdiction
 
(A)                             The courts of England have exclusive jurisdiction to settle any dispute arising out of or in connection with this Agreement (including a dispute relating to the existence, validity or termination of this Agreement or the consequences of its nullity) (a “ Dispute ”).
 
(B)                               The Parties agree that the courts of England are the most appropriate and convenient courts to settle Disputes and accordingly no Party will argue to the contrary.
 
(C)                               This Clause 22.1 is for the benefit of the Secured Parties only.  As a result, no Secured Party shall be prevented from taking proceedings relating to a Dispute in any other courts with jurisdiction.  To the extent allowed by law, the Secured Parties may take concurrent proceedings in any number of jurisdictions.
 
22.2                      Service of process
 
(A)                             Without prejudice to any other mode of service allowed under any relevant law, each Obligor (unless incorporated in England and Wales):
 
(i)                                   irrevocably appoints Trusec Limited of 2 Lambs Passage, London, EC1Y 8BB as its agent for service of process in relation to any
 
57

 
proceedings before the English courts in connection with this Agreement; and
 
(ii)                                agrees that failure by a process agent to notify the relevant Obligor of the process will not invalidate the proceedings concerned;
 
(B)                               If any person appointed as an agent for service of process is unable for any reason to act as agent for service of process, the Borrower (in the case of an agent for service of process for an Obligor), must immediately (and in any event within 30 days of such event taking place) appoint another agent on terms acceptable to the Facility Agent.  Failing this, the Facility Agent may appoint another agent for this purpose.
 
This Agreement has been entered into on the date stated at the beginning of this Agreement and executed as a deed by the Obligors and is intended to be and is delivered by them as a deed on the date specified above.
 
58

 
Schedule 1
FORM OF OBLIGOR ACCESSION DEED
 
THIS AGREEMENT is made on [·] and made between:
 
(1)                                [Insert Full Name of New Obligor] (registration number [·]) (the “Acceding Obligor”); and
 
(2)                                BNP PARIBAS (the “Security Agent”), for itself and each of the other parties to the Intercreditor Agreement referred to below.
 
This agreement is made on [date] by the Acceding Obligor in relation to an intercreditor agreement (the “Intercreditor Agreement ”) dated [ · ] 2011 between, amongst others, BNP Paribas as Security Agent, BNP Paribas as Facility Agent, the Creditors and the Obligors (each as defined in the Intercreditor Agreement).
 
The Acceding Obligor intends to [incur Liabilities under the following documents]/[give a guarantee, indemnity or other assurance against loss in respect of Liabilities under the following documents]:
 
[Insert details (date, parties and description) of relevant documents]
 
the “Relevant Documents”.
 
IT IS AGREED as follows:
 
1.                                     Terms defined in the Intercreditor Agreement shall, unless otherwise defined in this Agreement, bear the same meaning when used in this Agreement.
 
2.                                     The Acceding Obligor and the Security Agent agree that the Security Agent shall hold:
 
(a)                                 [any Security in respect of Liabilities created or expressed to be created pursuant to the Relevant Documents;
 
(b)                                all proceeds of that Security; and]
 
(c)                                 all obligations expressed to be undertaken by the Acceding Obligor to pay amounts in respect of the Liabilities to the Security Agent as trustee for the Secured Parties (in the Relevant Documents or otherwise) and secured by the Transaction Security together with all representations and warranties expressed to be given by the Acceding Obligor (in the Relevant Documents or otherwise) in favour of the Security Agent as trustee for the Secured Parties,
 
on trust for the Secured Parties on the terms and conditions contained in the Intercreditor Agreement.
 
3.                                     The Acceding Obligor confirms that it intends to be party to the Intercreditor Agreement as an Obligor, undertakes to perform all the obligations expressed to be assumed by an
 
59

 
Obligor under the Intercreditor Agreement and agrees that it shall be bound by all the provisions of the Intercreditor Agreement as if it had been an original party to the Intercreditor Agreement.
 
4.             This Agreement is governed by English law.
 
THIS AGREEMENT has been signed on behalf of the Security Agent and executed as a deed by the Acceding Obligor and is delivered on the date stated above.

The Acceding Obligor	 	
 	 	
[EXECUTED AS A DEED	)	 	
By: [Full Name of Acceding Obligor]	)	 	
 	 	
 	 	Director	 	
 	 	 	 	
 	 	Director/Secretary	 	
 	 	 	 	
OR	 	 	
 	 	 	
[EXECUTED AS A DEED	 	 	
 	 	 	
By: [Full name of Acceding Obligor]	 	 	
 	 	 	
 	 	Signature of Director	 	
 	 	 	 	
 	 	Name of Director	 	
 	 	 	
in the presence of	 	 	
 	 	 	
 	 	Signature of witness	 	
 	 	 	 	
 	 	Name of witness	 	
 	 	 	 	
 	 	Address of witness	 	

 	 	 	 	

 	 	Occupation of witness]	 	
 	 	 	
Address for notices:	 	 	
 	 	 	
Address:	 	 	
 	 	 	
Fax:	 	 	

60

 
The Security Agent	 	
 	 	
BNP PARIBAS	 	
 	 	
By:	 	
 	 	
Date:	 	
 
61

 
Schedule 2
FORM OF CREDITOR/AGENT ACCESSION UNDERTAKING
 
To:                            BNP PARIBAS for itself and each of the other parties to the Intercreditor Agreement referred to below.
 
To:          BNP PARIBAS as Facility Agent.
 
From:      [Acceding Creditor/Agent]
 
THIS UNDERTAKING is made on [date] by [insert full name of new Lender/Hedging Counterparty/Facility Agent /[Investor]] (the “ Acceding [Lender/Hedging Counterparty/Facility Agent ”) in relation to the intercreditor agreement (the “Intercreditor Agreement”) dated [ · ] 2011 between, among others, BNP Paribas as Security Agent, BNP Paribas as agent, the Creditors and the Obligors (each as defined in the Intercreditor Agreement).  Terms defined in the Intercreditor Agreement shall, unless otherwise defined in this Undertaking, bear the same meanings when used in this Undertaking.
 
In consideration of the Acceding [Lender/Hedging Counterparty/Agent being accepted as a [Lender/Hedging Counterparty/Facility Agent] for the purposes of the Intercreditor Agreement, the Acceding [Lender/Hedging Counterparty/Facility Agent] confirms that, as from [date], it intends to be party to the Intercreditor Agreement as a [Lender/Hedging Counterparty/Facility Agent] and undertakes to perform all the obligations expressed in the Intercreditor Agreement to be assumed by a [Lender/Hedging Counterparty/Facility Agent] and agrees that it shall be bound by all the provisions of the Intercreditor Agreement, as if it had been an original party to the Intercreditor Agreement.
 
[The Acceding Hedging Counterparty has become a provider of hedging arrangements to the [Borrower].
 
This Undertaking is governed by English law.
 
THIS UNDERTAKING has been entered into on the date stated above and is delivered on the date stated above].
 
Acceding [Creditor/Agent]
 
EXECUTED as a DEED
 
[insert full name of Acceding
Creditor/Agent ]
 
By:
 
Address:
 
Fax:
 
62

 
Accepted by the Security Agent	 	Accepted by the Facility Agent	

 	 	 	 	
for and on behalf of	 	 	for and on behalf of	
 	 	 	 	
BNP PARIBAS	 	BNP PARIBAS	
 	 	 	 	
Date:	 	 	Date:	
 
63

 
SIGNATURES
 
The Obligors	 	 	
 	 	 	
Borrower	 	 	
 	 	 	
Executed and Delivered as a Deed by	)	 	
 	 	 	
KOSMOS ENERGY FINANCE INTERNATIONAL	)	 	
 	 	 	
in the presence of:	)	/s/ Ryan Turner	
 	 	 	
 	)	Per:Ryan Turner	
 	 	 	
Joseph Biesterfield	 	)	Title: Attorney In Fact	

Witness’s Signature	/s/ Joseph Biesterfield	 	 	

(Name) Joseph Biesterfield	 	 	
 	 	 	
(Address) One Bunhill Row, London	 	 	
 	 	 	
(Occupation) Solicitor,	 	 	

 
(Note: The above details are to be completed
in the witness’s own handwriting.)

Address:	 	P.O. Box 32322	 	Copy:	 	c/o Kosmos Energy LLC	
 	 	4th Floor Century Yard	 	 	 	8176 Park Lane	
 	 	Cricket Square	 	 	 	Suite 500	
 	 	Elgin Avenue	 	 	 	Dallas	
 	 	Georgetown	 	 	 	Texas 75231	
 	 	Grand Cayman	 	 	 	USA	
 	 	KY1 — 1209	 	 	 	 	
 	 	Cayman Islands	 	 	 	 	
 	 	 	 	 	 	 	
Fax:	 	+1 345 946 4090	 	Fax:	 	+1 214 445 9705	
Attention:	 	Andrew Johnson	 	Attention:	 	William S. Hayes	
 
64

 
The Guarantors	 	 	
 	 	 	
Executed and Delivered as a Deed by	)	 	
 	 	 	
KOSMOS ENERGY GHANA HC	)	 	
 	 	 	
in the presence of:	)	/s/ Ryan Turner	
 	 	 	
 	)	Per:Ryan Turner	
 	 	 	
Joseph Biesterfield	 	)	Title: Attorney In Fact	

Witness’s Signature	/s/ Joseph Biesterfield	 	 	

(Name) Joseph Biesterfield	 	 	
 	 	 	
(Address) One Bunhill Row, London	 	 	
 	 	 	
(Occupation) Solicitor	 	 	

(Note: The above details are to be completed
in the witness’s own handwriting.)

Address:	 	P.O. Box 32322	 	Copy:	 	c/o Kosmos Energy LLC	
 	 	4th Floor Century Yard	 	 	 	8176 Park Lane	
 	 	Cricket Square	 	 	 	Suite 500	
 	 	Elgin Avenue	 	 	 	Dallas	
 	 	Georgetown	 	 	 	Texas 75231	
 	 	Grand Cayman	 	 	 	USA	
 	 	KY1 — 1209	 	 	 	 	
 	 	Cayman Islands	 	 	 	 	
 	 	 	 	 	 	 	
Fax:	 	+1 345 946 4090	 	Fax:	 	+1 214 445 9705	
 	 	 	 	 	 	 	
Attention:	 	Andrew Johnson	 	Attention:	 	William S. Hayes	
 
65

 
Executed and Delivered as a Deed by	)	 	
 	 	 	
KOSMOS ENERGY OPERATING	)	 	
 	 	 	
in the presence of:	)	/s/ Ryan Turner	
 	 	 	
 	)	Per: Ryan Turner	
 	 	 	
Joseph Biesterfield	 	)	Title: Attorney In Fact	

Witness’s Signature	/s/ Joseph Biesterfield	 	 	
 	 	 	 	
(Name) Joseph Biesterfield	 	 	
 	 	 	
(Address) One Bunhill Row, London	 	 	
 	 	 	
(Occupation) Solicitor	 	 	

(Note: The above details are to be completed
in the witness’s own handwriting.)

Address:	 	P.O. Box 32322	 	Copy:	 	c/o Kosmos Energy LLC	
 	 	4th Floor Century Yard	 	 	 	8176 Park Lane	
 	 	Cricket Square	 	 	 	Suite 500	
 	 	Elgin Avenue	 	 	 	Dallas	
 	 	Georgetown	 	 	 	Texas 75231	
 	 	Grand Cayman	 	 	 	USA	
 	 	KY1 — 1209	 	 	 	 	
 	 	Cayman Islands	 	 	 	 	
 	 	 	 	 	 	 	
Fax:	 	+1 345 946 4090	 	Fax:	 	+1 214 445 9705	
 	 	 	 	 	 	 	
Attention:	 	Andrew Johnson	 	Attention:	 	William S. Hayes	
 
66

 
Executed and Delivered as a Deed by	)	 	
 	 	 	
KOSMOS ENERGY DEVELOPMENT	)	 	
 	 	 	
in the presence of:	)	/s/ Ryan Turner	
 	 	 	
 	)	Per:Ryan Turner	
 	 	 	
Joseph Biesterfield	 	)	Title: Attorney In Fact	

Witness’s Signature	/s/ Joseph Biesterfield	 	 	
 	 	 	 	
(Name) Joseph Biesterfield	 	 	
 	 	 	
(Address) One Bunhill Row, London	 	 	
 	 	 	
(Occupation) Solicitor	 	 	

(Note: The above details are to be completed
in the witness’s own handwriting.)

Address:	 	P.O. Box 32322	 	Copy:	 	c/o Kosmos Energy LLC	
 	 	4th Floor Century Yard	 	 	 	8176 Park Lane	
 	 	Cricket Square	 	 	 	Suite 500	
 	 	Elgin Avenue	 	 	 	Dallas	
 	 	Georgetown	 	 	 	Texas 75231	
 	 	Grand Cayman	 	 	 	USA	
 	 	KY1 — 1209	 	 	 	 	
 	 	Cayman Islands	 	 	 	 	
 	 	 	 	 	 	 	
Fax:	 	+1 345 946 4090	 	Fax:	 	+1 214 445 9705	
 	 	 	 	 	 	 	
Attention:	 	Andrew Johnson	 	Attention:	 	William S. Hayes	
 
67

 
Executed and Delivered as a Deed by	)	 	
 	 	 	
KOSMOS ENERGY INTERNATIONAL	)	 	
 	 	 	
in the presence of:	)	/s/ Ryan Turner	
 	 	 	
 	)	Per:Ryan Turner	
 	 	 	
Joseph Biesterfield	 	)	Title: Attorney In Fact	

Witness’s Signature	/s/ Joseph Biesterfield	 	 	
 	 	 	 	
(Name) Joseph Biesterfield	 	 	
 	 	 	
(Address) One Bunhill Row, London	 	 	
 	 	 	
(Occupation) Solicitor	 	 	

(Note: The above details are to be completed
in the witness’s own handwriting.)

Address:	 	P.O. Box 32322	 	Copy:	 	c/o Kosmos Energy LLC	
 	 	4th Floor Century Yard	 	 	 	8176 Park Lane	
 	 	Cricket Square	 	 	 	Suite 500	
 	 	Elgin Avenue	 	 	 	Dallas	
 	 	Georgetown	 	 	 	Texas 75231	
 	 	Grand Cayman	 	 	 	USA	
 	 	KY1 — 1209	 	 	 	 	
 	 	Cayman Islands	 	 	 	 	
 	 	 	 	 	 	 	
Fax:	 	+1 345 946 4090	 	Fax:	 	+1 214 445 9705	
 	 	 	 	 	 	 	
Attention:	 	Andrew Johnson	 	Attention:	 	William S. Hayes	
 
68

 
The Security Agent	 	 	
 	 	 	
BNP PARIBAS	 	 	
 	 	
By:	/s/ Xavier Venereau	 	By:	/s/ Olivier Warnan	

Name:	Xavier Venereau	Name:	Olivier Warnan	
Title:	Managing Director	Title:	Director-BNP Paribas	
 	 	
Address:	BNP Paribas S.A., Paris	 	
 	 	 	
 	16, rue de Hanovre	 	
 	 	 	
 	75002 Paris (France)	 	
 	 	 	
Fax:	+ 33 142 98 49 25	 	
 	 	 	
Attention:	Hong Ngoc PHAM / Phoï-Van PHUONG	
 	 	 	
The Facility Agent	 	 	
 	 	 	
BNP PARIBAS	 	 	
 	 	
By:	/s/ Xavier Venereau	 	By:	/s/ Olivier Warnan	

Name:	Xavier Venereau	Name:	Olivier Warnan	
Title:	Managing Director	Title:	Director-BNP Paribas	

The Lenders	 	 	
 	 	 	
ABSA CAPITAL, A DIVISION OF ABSA BANK LIMITED	
 	 	
By:	/s/ Narisa Balgobind	 	By:	/s/ David Pilling	

Name:	Narisa Balgobind	Name:	David Pilling	
Title:	Principal	Title:	Associate Principal	

69

 
BARCLAYS BANK PLC	 	
 	 	
By:	/s/ C.J. Morphett	 	By:	

Name:	C.J. Morphett	Name:	
Title:	Director	Title:	

BNP PARIBAS	
 	 	
By:	/s/ Xavier Venereau	 	By:	/s/ Olivier Warnan	

Name:	Xavier Venereau	Name:	Olivier Warnan	
Title:	Managing Director	Title:	Director-BNP Paribas	

CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANK	
 	 	 	
By:	/s/ L. Renard	 	By:	

Name:	L. Renard	Name:	
Title:	Associate Director	Title:	

HSBC BANK PLC	 	
 	 	 	
By:	/s/ William Stevens	 	By:	

Name:	William Stevens	Name:	
Title:	Managing Director	Title:	
 
70

 
SOCIÉTÉ GÉNÉRALE, LONDON BRANCH	
 	 	 	
By:	/s/ Maria Martin	 	By:	

Name:	Maria Martin	Name:	
Title:	Associate	Title:	

STANDARD CHARTERED BANK	
 	 	 	
By:	/s/ A.D. Bartlett	 	By:	
 	 	 	
Name:	Andrew Bartlett	Name:	
Title:	Managing Director	Title:	

The Arrangers	 	
 	 	 	
ABSA CAPITAL, A DIVISION OF ABSA BANK LIMITED	
 	 	 	 	
By:	/s/ Narisa Balgobind	 	By:	/s/ David Pilling	

Name:	Narisa Balgobind	Name:	David Pilling	
Title:	Principal	Title:	Associate Principal	

BNP PARIBAS	 	 	
 	 	 	 	
By:	/s/ Xavier Venereau	 	By:	/s/ Olivier Warnan	

Name:	Xavier Venereau	Name:	Olivier Warnan	
Title:	Managing Director	Title:	Director-BNP Paribas	
 
71

 
CRÉDIT AGRICOLE CORPORATE AND INVESTMENT BANK	
 	 	 	
By:	/s/ L. Renard	 	By:	

Name:	L. Renard	Name:	
Title:	Associate Director	Title:	

HSBC BANK PLC	
 	 	 	
By:	/s/ William Stevens	 	By:	

Name:	William Stevens	Name:	
Title:	Managing Director	Title:	

SOCIÉTÉ GÉNÉRALE, LONDON BRANCH	
 	 	 	
By:	/s/ Maria Martin	 	By:	

Name:	Maria Martin	Name:	
Title:	Associate	Title:	

STANDARD CHARTERED BANK	
 	 	 	
By:	/s/ Andrew Bartlett	 	By:	
 	 	 	
Name:	Andrew Bartlett	Name:	
Title:	Managing Director	Title:	
 
72

 
The Hedging Counterparties	
 	 	 	
ABSA CAPITAL, A DIVISION OF ABSA BANK LIMITED	
 	 	 	 	 	
By:	/s/ Narisa Balgobind	 	By:	/s/ David Pilling	

Name:	Narisa Balgobind	Name:	David Pilling	
Title:	Principal	Title:	Associate Principal	

BNP PARIBAS	
 	 	 	 	 	
By:	/s/ Xavier Venereau	 	By:	/s/ O. Warnan	

Name:	Xavier Venereau	Name:	Olivier Warnan	
Title:	Managing Director	Title:	Director-BNP Paribas	

CREDIT SUISSE INTERNATIONAL	
 	 	 	
By:	 	By:	

Name:	 	Name:	
Title:	 	Title:	

SOCIÉTÉ GÉNÉRALE	
 	 	 	
By:	/s/ Maria Martin	 	By:	

Name:	Maria Martin	Name:	
Title:	Associate	Title:	
 
73

 
STANDARD CHARTERED BANK	
 	 	 	
By:	/s/ Andrew Bartlett	 	By:	

Name:	Andrew Bartlett	Name:	
Title:	Managing Director	Title:	

HSBC BANK PLC	
 	 	 	
By:	/s/ William Stevens	 	By:	

Name:	William Stevens	Name:	
Title:	Managing Director	Title:	
 
74

Exhibit 10.33
 
PARTICIPATION AGREEMENT
 
BY AND BETWEEN
 
Kosmos Energy Ghana HC
 
AND
 
E.O. Group Limited
 
RELATING TO THE
 
West Cape Points Block
 
REPUBLIC OF GHANA
 
June 1, 2004

 
Table of Contents
 
Article 1 Definitions	2	
 	 	
Article 2 Implementation	2	
 	 	
Article 3 Participating Interests	2	
 	 	
Article 4 Execution of PSA	2	
 	 	
Article 5 Rights and Obligations; and Costs and Expenses	3	
 	 	
Article 6 Operating Agreement	3	
 	 	
Article 7 Representations of the Parties	4	
 	 	
Article 8 Confidentiality and Announcements	5	
 	 	
Article 9 Assignment	6	
 	 	
Article 10 Governing Law and Dispute Resolution	7	
 	 	
Article 11 Termination	8	
 	 	
Article 12 Miscellaneous	8	
 
EXHIBIT A - Definitions
 
EXHIBIT B - Joint Operating Agreement
 
EXHIBIT C - Draft of PSA
 
i

 
PARTICIPATION AGREEMENT
 
This Participation Agreement (hereinafter referred to as “Agreement”) is made and entered into effective as of the Effective Date, by and between:
 
Kosmos Energy Ghana HC, a company organized and existing under the laws of the Cayman Islands (hereinafter referred to as “Kosmos”); and
 
E.O. Group Limited, a company organized and existing under the laws of the Republic of Ghana (hereinafter referred to as “EO Group”).
 
Kosmos and EO Group are hereinafter collectively referred to as “Parties” and separately as a “Party”.
 
RECITALS:
 
A.           WHEREAS, The parties entered into that certain Letter Agreement dated April 30, 2004, (the “Prior Letter Agreement”) relative to the West Cape Block.
 
B.           WHEREAS, the parties have agreed to cooperate concerning the West Cape Block and desire to define their respective rights and obligations relative to the West Cape Block and the activities and operations to be undertaken in connection therewith and this Agreement shall supersede in its entirety the Prior Letter Agreement.
 
NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements hereinafter set forth, the Parties agree as follows:
 
1

 
Article 1 Definitions
 
Unless the context otherwise requires, the respective terms defined inExhibit A attached hereto and incorporated herein or elsewhere in this Agreement shall, when used herein, have the respective meanings specified, with each such definition to be equally applicable both to the singular and the plural forms of the term so defined.
 
Article 2 Implementation
 
2.1                 During the Term of this Agreement and subject to the terms hereof, the Parties shall work exclusively with each other to execute and enter into the PSA for the West Cape Block.
 
Article 3 Participating Interests
 
3.1                 Subject to obtaining the Consent of the Government the initial Participating Interests under the PSA shall be:
 
 	Kosmos Energy	 	86.5	%	 	
 	EO Group	 	3.5	%	 	
 	GNPC	 	10	%	 	
 
Article 4 Execution of the PSA
 
4.1                 Previously, the parties have negotiated the PSA with the Government and have initialed a draft of the PSA. A copy of the initialed draft of the PSA is attached to this Agreement as Exhibit C.
 
2

 
Article 5 Rights and Obligations; and Costs and Expenses
 
5.1                 Each Party shall bear and pay its own costs and expenses associated with the negotiation and execution of this Agreement, the JOA, and the PSA.
 
5.2                 INTENTIONALLY DELETED
 
5.3                 Notwithstanding any other provision of this Agreement, Kosmos agrees, commencing on the effective date of the PSA and continuing until “Payment Termination” as described in Section 5.4, to bear and pay one hundred percent (100%) of EO Group’s Participating Interest share of PSA costs.
 
5.4                 Kosmos’ obligation to bear and pay all EO Group’s Participating Interest share of PSA Costs pursuant to Section 5.3 shall terminate (“ Payment Termination ”) on the date on which first production commences on the West Cape Block.
 
5.5                Following Payment Termination, Kosmos and EO Group shall each bear and pay their Participating Interest share of PSA costs subject to and in accordance with the provisions of the PSA and the JOA. For the avoidance of doubt, it is agreed that each Party shall be entitled to cost recovery under the PSA for such costs actually paid and borne by such Party. Prior to EO Group receiving any proceeds from the West Cape Block, Kosmos shall be repaid all incurred on behalf of EO Group’s Participating Interest pursuant to Section 5.3 above.
 
Article 6 Operating Agreement
 
6.1                 Upon execution of the PSA, the Parties shall also execute and enter into a Joint Operating Agreement (“JOA”) for the West Cape Block substantially in the form of Exhibit B  attached hereto.
 
3

 
6.2                 The Parties agree that Kosmos shall be the operator of the West Cape Block under the JOA.
 
Article 7 Representations of the Parties
 
7.1                 Each of the Parties hereby represents to the other Party that:
 
(a)                   It is a corporate entity which has been duly formed and currently exists with the full power and authority to execute this Agreement and the JOA, and to enter into the PSA; and
 
(b)                  The transactions contemplated by this Agreement will not violate or be in conflict with (i) any provision of its charter, articles of incorporation, or other organizational documents (as the case may be); (ii) any agreement or instrument by which it is bound; (iii) any present judgment, order or decree applicable to it; or (iv) to the best of its knowledge, any present law, agreement or instrument by which it is bound; and
 
(c)                   To the best of its knowledge, no suit, action or arbitration, or legal, administrative or other proceeding is pending, or has been threatened against such Party, or any of its Affiliates, relating to the West Cape Block or the subject matter of this Agreement; and
 
(d)                  The execution, delivery and performance of this Agreement and the transactions contemplated hereunder have been duly authorized by all requisite company action; and when executed this Agreement shall constitute a legal, valid and binding obligation of such Party enforceable in accordance with its terms; and
 
(e)                   It, nor any of its affiliated entities, has incurred any obligation or entered into any agreement for any investment banking, brokerage, finder’s fee, commission or similar payment in respect of the transaction contemplated by this Agreement for which the other Party may incur any liability.
 
4

 
7.2                 No party shall take any action, directly or indirectly, in connection with this Agreement, the transactions contemplated hereby or any agreement contemplated by this Agreement that would constitute a violation of the United States Foreign Corrupt Practices Act of 1977, as amended from time to time (“FCPA”) by either Party. Accordingly each Party covenants that neither it nor of any of it’s officers, directors, employees, ultimate beneficial owners or shareholders owners, shall make or cause to be made in connection with this Agreement, the transactions contemplated hereby or any other agreement contemplated by this Agreement, any payments, loans, or gifts or promises or offer of payments, loans or gifts of any money or anything of value, directly or indirectly to obtain or retain any contract, business opportunity or similar benefit; (a) to or for the use or benefit of any official or employee of any Government, or the agency of the instrumentalities of any such government except to the extent required by applicable law to obtain any necessary approval of the Government; (b) to any political party or official or candidate thereof; (c) to any other person either as an advance or as a reimbursement if it knows or has reason to suspect that any part of such payment, loan or gift will be directly or indirectly given or paid by such other person, or will reimburse such other person for payments, gifts or loans previously made, to any such government official or political party or candidate thereof which cannot be made directly by such Party in accordance with this Section 7.2; or (d) to any other persons if such payment would violate the laws, decrees, regulations or policies having the force of law in Ghana or country or countries of such person or the laws of the United States of America, including without limitation, the FCPA.
 
Article 8 Confidentiality and Announcements
 
8.1                 Each Party agrees to keep this Agreement and information disclosed or acquired under this Agreement confidential and not disclose it to third parties, without the prior written consent of the other Party. Subject to the obligations to the Government, a Party may make
 
5

 
disclosures concerning this Agreement or the transactions described herein if required by applicable laws or regulations, including regulations of applicable securities exchanges, or for the purpose of raising funds to facilitate the performance by any Party of its obligations under this Agreement. The confidentiality obligation set forth herein shall terminate two (2) years following the expiry or termination of the Term of this Agreement.
 
8.2                 No press release or public announcement shall be made by a Party concerning this Agreement or the transaction described herein unless it has been made available and approved in advance by the other Party, which approval shall not be unreasonably withheld. Such approval shall not be required if the press release or announcement is required by applicable laws and regulations, including regulations of applicable securities exchanges, but the other Party shall be notified to the extent reasonably practicable in advance of any such required release.
 
Article 9 Assignment
 
9.1                 Any Party may assign all or part of its rights and obligations under this Agreement to an Affiliate of the assigning Party,            such Affiliate executes an assumption agreement (in a form reasonably acceptable to the other Party for the benefit of the other Party pursuant to which such Affiliate assumes the obligations of its assignor under this Agreement.
 
9.2                 EO Group shall not assign all or part of its rights and obligations under this Agreement to a third party which is not an Affiliate, except with the prior written consent of Kosmos, which consent will not be unreasonably withheld.
 
9.3                 Notwithstanding the foregoing, no Party shall make an assignment whereby, as a result of such assignment, any of the Parties would be placed in violation of applicable laws or regulations or subject to tax or other penalties imposed by a government in respect of carrying out business activities with such assignee.
 
6

 
Article 10 Governing Law and Dispute Resolution
 
10.1          This Agreement shall be governed by and interpreted in accordance with the laws of England, excluding any choice of law rules that would direct the application of the laws of another jurisdiction.
 
10.2          Any dispute arising out of or relating to this Agreement (whether contractual, tortious, equitable, statutory or otherwise), including any question regarding its existence, validity, termination, interpretation, performance or breach, which cannot be amicably resolved by the Parties within thirty (30) days of the date that one Party notifies the other Parties in writing of the existence of such dispute, shall be finally and exclusively resolved by arbitration administered by and conducted in accordance with the arbitration rules of the International Chamber of Commerce (“ICC”) in effect on the date the arbitration commences except as they may be modified herein. The arbitration shall be heard and determined by three (3) arbitrators. The claimant and the respondent shall each appoint an arbitrator within thirty (30) days of the submission of a notice of arbitration. The two arbitrators so appointed shall appoint a presiding arbitrator within thirty (30) days following the appointment of the two arbitrators. If the two arbitrators cannot reach agreement on a presiding arbitrator and/or one side fails to appoint an arbitrator within the foregoing time limits, the appointing authority for the implementation of such procedure shall be the President of the ICC acting in accordance with the rules adopted by the ICC for this purpose, who shall appoint an impartial arbitrator who does not have any financial interest in the dispute. The seat of the arbitration shall be London, England and the arbitration proceedings shall be conducted in the English language. The decision of the majority of the arbitrators shall be final, binding, and enforceable without the right of appeal and without the necessity of being confirmed by a court. Judgment upon the award rendered by the arbitration may be entered in any court having jurisdiction over the person or the assets of the Person owing the judgment or application may be made to such court for a judicial acceptance of the award and an order of enforcement, as the case may be.
 
7

 
10.3          No Party shall be liable to any other Party for any indirect, punitive or consequential damages resulting from or arising out of this Agreement, including any loss of profits or opportunity to earn profits, business interruption, or business opportunities, however the same may be caused. No arbitration award or decision shall include or award any of the aforesaid damages to any Party.
 
10.4          The Parties’ representations under this Agreement shall not form the basis for or give rise to any claim, demand or cause of action which is asserted, claimed, made or filed following the expiration of one (1) year after the date of this Agreement, except to the extent asserted, claimed, made or filed by way of defense or counterclaim to a claim by the other Party (however, any such counterclaim shall be allowed only to the extent the same is offsetting).
 
Article 11 Termination of this Agreement
 
11.1          The term of this Agreement (the “Term”) shall commence on the Effective Date and subject to the terms of the JOA, shall continue in effect until the earlier to occur of:
 
(a)                   the termination of the PSA; or
 
(b)                  the unanimous agreement of the Parties to terminate.
 
11.2          Upon the expiration of the Term and unless otherwise expressly stated in the Agreement to the contrary, the Parties will have no further obligations or liabilities to each other with respect to this Agreement, except that Articles 8 and 10 shall survive termination of this Agreement.
 
Article 12 Miscellaneous
 
12.1          It is expressly agreed that this Agreement shall not be construed against any Party, and no consideration shall be given or presumption made, on the basis of who drafted this
 
8

 
Agreement or any particular provision hereof or who supplied the form of this Agreement. Each Party agrees that this Agreement has been purposefully drawn and correctly reflects its understanding of the transaction that this Agreement contemplates. In construing this Agreement:
 
(a)                   Examples shall not be construed to limit, expressly or by implication, the matter they illustrate;
 
(b)                  The word “includes” and its derivatives means “includes, but is not limited to” and corresponding derivative expressions;
 
(c)                   A defined term has its defined meaning throughout this Agreement regardless of whether it appears before or after the place where it is defined; and
 
(d)                  The headings and titles identifying the Articles and Sections (or any other subdivision) in this Agreement are for reference and convenience only and shall be disregarded in construing this Agreement.
 
12.2          All references in this Agreement to an “Article,” “Exhibit” or “Section” shall be to an Article, Exhibit or Section of this Agreement, unless the context requires otherwise. Unless the context otherwise requires, the words “this Agreement,” “hereof,” “hereunder,” “herein,” “hereby,” or words of similar import shall refer to this Agreement as a whole and not to a particular Article, Section, paragraph, clause or other subdivision hereof.
 
12.3          No amendments, changes or modifications to this Agreement shall be valid unless the same are in writing and signed by a duly authorized representative of each of the Parties hereto. Any Party may, only by an instrument in writing, waive compliance by another Party with any term or provision of this Agreement on the part of such other Party to be performed or complied with. The waiver by any Party of a breach of any term or provision of this Agreement shall not be construed as a waiver of any subsequent breach.
 
9

 
12.4          Notwithstanding anything contained to the contrary in any other provision of this Agreement, it is the explicit intent of each Party that no Party is making any representation or warranty whatsoever, express, implied, statutory or otherwise, beyond those representations expressly given in this Agreement.
 
12.5          This Agreement comprises the full and complete agreement of the Parties with respect to the matters covered by this Agreement and supersedes and cancels all prior communications, understandings and agreements between the Parties (including, without limitation, the Prior Letter Agreement), whether written or oral, expressed or implied, in relation to the subject matter hereto.
 
12.6          Subject to the right of each Party to make assignments pursuant to Article 9, no person other than the Parties shall have any rights under this Agreement or be considered a third party beneficiary hereof.
 
12.7          This Agreement may be executed in any number of counterparts and such counterparts when construed together shall be deemed to be one Agreement for all purposes, provided no Party shall be bound to this Agreement unless and until all Parties have executed a counterpart. Confirmation of execution by facsimile is specifically approved.
 
12.10   Unless otherwise expressly provided in this Agreement, all notices required or permitted hereunder shall be in writing, in the English language, and deemed sufficiently given for all purposes hereof if (i) delivered by courier or in person to the Party to be notified, with receipt obtained, or (ii) sent by telecopy, telefax or other facsimile or electronic transmission, with “answer back” or other “advice of receipt” obtained, to the appropriate address or number as set forth below. Each notice shall be deemed effective on receipt by the addressee; provided that notice received by telecopy, telefax or other electronic transmission after 5:00 p.m. at
 
10

 
the location of the addressee of such notice shall be deemed received on the first working day following the date of such electronic receipt.
 
Notices shall be addressed as follows:
 
Kosmos Energy Ghana HC
c/o Kosmos Energy, LLC
8401 N. Central Expressway
Suite 280
Dallas, Texas 75225	E.O. Group Limited
Private Mailbag CT 123
Cantonments- Accra
Ghana	
 	 	
Attention: Craig Glick
Telephone: 214-363-0700
Facsimile: 214-363-9024	Attention: Mr. George Y. Owusu
Telephone: 001 281 470 1784
Facsimile: 001 281 470 9300	
 
or at such other address and to the attention of such other person as a Party may designate by written notice to the other Party.
 
12.10   If any term or other provision of this Agreement is determined to be invalid, illegal or incapable of being enforced by any rule of law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any materially adverse manner to any Party, Upon a determination that any term or other provision is invalid, illegal or incapable of being enforced and there is a materially adverse effect on any Party, the Parties shall use Reasonable Commercial Efforts to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.
 
12.10   The rights, duties, obligations and liabilities of the Parties under this Agreement are several and individual, not joint or collective. It is not the intention of the Parties to create, and this Agreement shall not be deemed or construed to create, an oil and gas, mining or other partnership, joint venture, association, trust, agency or other entity. This Agreement shall not
 
11

 
be deemed or construed to authorize any Party to act as an agent, servant or employee for any other Party for any purpose whatsoever, except as explicitly set forth in this Agreement.
 
12

 
IN WITNESS WHEREOF, the duly authorized representatives of the Parties have caused this Agreement to be executed on the date first written above.

Kosmos Energy Ghana HC	E.O. Group Limited	

By:	/s/ Craig Glick	 	By:	/s/ George Y. Owusu	
Name:	Craig Glick	 	Name:	George Y. Owusu	
Title:	Vice President	 	Title:	Managing Partner	
 
13

 
Exhibit A to that certain Participation Agreement dated the 1st day of June 2004 between
Kosmos Energy Ghana HC and E.O. Group Limited
 
DEFINITIONS
 
“Affiliate” shall mean any company or legal entity which (a) controls either directly or indirectly a Party, or (b) which is controlled directly or indirectly by a Party, or (c) is directly or indirectly controlled by a company or legal entity which directly or indirectly controls such Party. “Control” means the right to exercise fifty percent (50%) or more of the voting rights in the appointment of the directors or similar representatives of such company or legal entity.
 
“Agreed Interest Rate” shall mean interest compounded on a monthly basis, at the rate per annum equal to the one (10) month term, London Interbank Offered Rate (LIBOR rate) for U.S. Dollar deposits as published by the  Wall Street Journal  or, if not published, then by the  Financial Times of London  plus five (5) percentage points, applicable on the first day prior to the due date of payment and thereafter on the first day of each succeeding calendar month. If the aforesaid rate is contrary to any applicable usury law, the rate of interest to be charged shall be the maximum rate permitted by such applicable law.
 
“Agreement” shall mean this Agreement, together with all exhibits hereto.
 
“Consent” shall mean the consents, approvals and authorizations from the Government which are required for the PSA.
 
“Effective Date” means June 1, 2004.
 
“West Cape Block” shall mean the area described in and covered by the PSA, after it is executed.
 
“JOA” has the meaning set out in Section 6.
 
“GNPC” shall mean the Ghana National Petroleum Corporation
 
“Government” shall mean the government of the Republic of Ghana or any element agency or department thereof including, without limitation, the GNPC.
 
“Participating Interest” shall mean the undivided interest (expressed as a percentage) in the rights and obligations of the Parties under this Agreement, the PSA and the corresponding JOA.
 
“Payment Termination” has the meaning set out in Section 5.4.
 
Exhibit A-1

 
“Petroleum” shall mean all liquid and gaseous hydrocarbons, including crude oil and natural gas, existing in natural condition in the strata as well as other substances which are in combination, suspension or mixture, including sulphur, nitrogen and carbon dioxide but excluding base sediments and water produced in association with such hydrocarbons.
 
“PSA” shall mean the Petroleum Agreement entered into with the Government for the exploration for, development and exploitation of Petroleum from the West Cape Block in accordance with the Law of the Republic of Ghana.
 
“PSA Costs” shall mean all costs, after the Effective Date, incurred or to be incurred in accordance with and pursuant to the PSA and/or the JOA, including but not limited to the following: bonuses payable under the PSA and all costs incurred pursuant to the JOA in conducting Petroleum operations under the PSA, including but not limited to geological and geophysical costs (e.g. the actual costs of conducting, acquiring, processing or interpreting topographical, geological, geophysical, geohazard or environmental studies along with salaries and other expenses of geologists, geophysical crews and others required to carry out such studies), drilling costs (e.g. costs incurred in drilling operations, including without limitation, the cost of permitting, site preparation, mobilization, and demobilization of the drilling rig and ancillary equipment, drilling, sidetracking, fishing, suspending, testing, completing or plugging and abandoning) and general and administrative costs (e.g. all costs of the Operator and its Affiliates which facilitate the ongoing Petroleum operations, including without limitation, employee salaries, rent, office supplies, travel and similar costs, as well as a charge for the Operator’s overhead as permitted under the JOA).
 
“Reasonable Commercial Efforts” shall mean commercially reasonable efforts which a commercial entity engaged in the international oil and gas exploration and production business and having due regard for the commercial interests of all Parties to this Agreement would take under the same or similar circumstances in a reasonable and good faith effort to achieve, cause or obtain the result specified or the other specified event or occurrence. Any requirement in this Agreement that the Parties use reasonable commercial efforts to reach unanimous agreement on a matter shall not be construed to require any delay which any Party reasonably believes could damage or cause the loss of any of rights or interests with respect to the PSA.
 
“Term” has the meaning set out in Section 11.1.
 
Exhibit A-2

 
“United States Dollars” or “US$” or “U.S.$” shall mean lawful currency of the United States of America.
 
Exhibit A-3

QuickLinks -- Click here to rapidly navigate through this document
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. 5 to the Registration Statement (Form S-1) and related Prospectus of Kosmos Energy Ltd. for the registration of its common stock.
 	 	 	
 	 	/s/ Ernst & Young LLP	
Dallas, Texas
April 22, 2011

QuickLinks
Exhibit 23.1

QuickLinks -- Click here to rapidly navigate through this document
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 April 19, 2011, in this Form S-1 Registration Statement and the related Prospectus to be filed on or about April 25, 2011. We also consent to the reference to us under the heading "Experts" in such Registration Statement and the Prospectus to which the Registration Statement is related.
 	 	 	 	 	
 	 	NETHERLAND, SEWELL & ASSOCIATES, INC.	

 	
By:	
 	
/s/ C.H. (SCOTT) REES III

C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer	
Dallas, Texas
April 25, 2011

QuickLinks
Exhibit 23.2

QuickLinks -- Click here to rapidly navigate through this document
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 4, 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-place (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$)	 	 	
 
	 	OOIP
(MMBBL)	 	Oil Reserves
(MMBBL)	 	 
	 	 	 	 	 	
Category	 	 	 	 	 	Net Oil Reserves(1)
(MMBBL)	 	Total	 	Discounted
at 10%	 	 	 	 	 	 	 	 	
Proved Undeveloped	 	 	938	 	 	234	 	 	52	 	 	1,127	 	 	699	 	 	 	 	 	 	 	 	
Probable Undeveloped	 	 	142	 	 	93	 	 	21	 	 	776	 	 	440	 	 	 	 	 	 	 	 	
Possible Undeveloped	 	 	147	 	 	117	 	 	25	 	 	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 rejected. 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 4, 2010	 	Date Signed: February 4, 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 maintained 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.

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 	 	 	 	 	
        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.

(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

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

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

(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

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

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 termsaleable 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.

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(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.

(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,

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

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 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.

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

        (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.

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 	
 	
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.	

 	
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.

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 	 	 	 	 	
        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.

QuickLinks
EXHIBIT 99.1
DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

QuickLinks -- Click here to rapidly navigate through this document
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	

April 19, 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	 	 	25	 	 	11	 	 	972	 	 	747	 	
Proved Undeveloped	 	 	 	(3)	 	77	 	 	17	 	 	4	 	 	730	 	 	475	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total Proved	 	 	942	 	 	234	 	 	52	 	 	22	 	 	2,041	 	 	1,530	 	
Probable	 	 	
141	 	 	
94	 	 	
20	 	 	
2	 	 	
910	 	 	
563	 	
Possible	 	 	
149	 	 	
115	 	 	
23	 	 	
3	 	 	
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: April 19, 2011	 	Date Signed: April 19, 2011	
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 maintained 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.

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 	 	 	 	 	
        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.

(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

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

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

(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

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

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 termsaleable 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.

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(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.

(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,

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

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 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.

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

        (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.

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 	
 	
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.	

 	
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.

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 	 	 	 	 	
        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 develop- ment 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.

QuickLinks
EXHIBIT 99.2
DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)