Kosmos Energy Ltd. - Annual Report: 2012 (Form 10-K)

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Item 8. Financial Statements and Supplementary Data

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

FORM 10-K

Commission file number: 001-35167

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

Registrant's telephone number, including area code: +1 441 295 5950

Securities registered pursuant to Section 12(b) of the Act:

          Securities registered pursuant to Section 12(g) of the Act: None

          Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    No o

          Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

          Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

          Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

          Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

          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.

          Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

          The aggregate market value of the voting and non-voting common shares held by non-affiliates, based on the per-share closing price of the registrant's common shares as of the last business day of the registrant's most recently completed second fiscal quarter was $778,343,016.

          The number of the registrant's Common Shares outstanding as of February 18, 2013 was 388,593,342.

DOCUMENTS INCORPORATED BY REFERENCE

          Part III, Items 10-14, is incorporated by reference from the Proxy Statement for the Annual Meeting of Shareholders to be held on June 3, 2013.

          Certain exhibits previously filed with the Securities and Exchange Commission are incorporated by reference into Part IV of this report.

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        Unless otherwise stated in this report, references to "Kosmos," "we," "us" or "the company" refer to Kosmos Energy Holdings and its subsidiaries prior to the completion of the corporate reorganization, which was completed in connection with our initial public offering ("IPO"), and Kosmos Energy Ltd. and its subsidiaries as of the completion of the corporate reorganization and thereafter. We have provided definitions for some of the industry terms used in this report in the "Glossary and Selected Abbreviations" beginning on page 2.

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KOSMOS ENERGY LTD.
GLOSSARY AND SELECTED ABBREVIATIONS

        The following are abbreviations and definitions of certain terms used in this report. Unless listed below, all defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings.

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Cautionary Statement Regarding Forward-Looking Statements

        This annual report on Form 10-K contains estimates and forward-looking statements, principally in "Item 1. Business," "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." 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 our annual report on Form 10-K, may adversely affect our results as indicated in forward-looking statements. You should read this annual report on Form 10-K and the documents that we have filed as exhibits hereto 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:

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



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



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



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



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termination of or intervention in concessions, rights or authorizations granted by the governments of Ghana, Cameroon, Mauritania, Morocco or Suriname (or their respective national oil companies) or any other federal, state or local governments or authorities, to us;



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



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



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the volatility of oil and natural gas prices;



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



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



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other competitive pressures;



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



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



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cost of compliance with laws and regulations;



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



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environmental liabilities;



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geological, technical, drilling, production and processing problems;



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military operations, civil unrest, terrorist acts, wars or embargoes;

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the cost and availability of adequate insurance coverage;



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our vulnerability to severe weather events;



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our ability to meet our obligations under the agreements governing our indebtedness;



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the availability and cost of financing and refinancing our indebtedness;



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the amount of collateral required to be posted from time to time in our hedging transactions;



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our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; and



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other risk factors discussed in the "Item 1A. Risk Factors" section of this annual report on Form 10-K.

        The words "believe," "may," "will," "aim," "estimate," "continue," "anticipate," "intend," "expect," "plan" 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 annual report on Form 10-K 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.

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PART I

Item 1.    Business

General

        We are a leading independent oil and gas exploration and production company focused on frontier and emerging areas in Africa and South America. Our asset portfolio includes existing production and other major project developments offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Mauritania, Morocco and Suriname and onshore Cameroon. Kosmos is listed on The New York Stock Exchange ("NYSE") and is traded under the ticker symbol KOS.

        Following our formation in 2003, we acquired multiple exploration licenses and established a new, major oil province in West Africa with the discovery of the Jubilee Field within the Tano Basin offshore Ghana in 2007. This was the first of our discoveries offshore Ghana; it was one of the largest oil discoveries worldwide in 2007 and is considered one of the largest finds offshore West Africa during the last decade. Oil production from the Jubilee Field commenced in November 2010.

        In the near-term, we are focused on maximizing production and cash flow from the Jubilee Field, and progressing the appraisal and development of our other discoveries in Ghana as well as the acquisition, exploration, appraisal and development of existing and new opportunities, including identifying, capturing and testing additional high-potential prospects to grow reserves and production.

Our Business Strategy

Grow proved reserves and production through exploration, appraisal and development

        We plan to continue to produce and further develop the Jubilee Field, while completing appraisal and development of our existing Ghana discoveries (Tweneboa, Enyenra, Ntomme and Wawa in the Deepwater Tano Block offshore Ghana ("DT Block") and Mahogany, Teak and Akasa in the West Cape Three Points Block offshore Ghana ("WCTP Block")). In the event of a declaration of commerciality and/or approval of a plan of development, we intend to develop these discoveries to grow proved reserves and production. During 2012, we submitted a declaration of commerciality and PoD over the Tweneboa, Enyenra and Ntomme ("TEN") discoveries and are awaiting approval from the government of Ghana. We also plan to drill exploration prospects in our asset portfolio, with the intent to further grow proved reserves and production should discoveries be made.

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 geoscientists, petroleum engineers and major projects personnel 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 make discoveries in and produce from the Tano Basin offshore Ghana, a significant new petroleum system the industry previously did not consider either prospective or commercially viable.

Focus on optimally developing our discoveries to initial production

        We focus on the development of fields designed to deliver early learnings and production. There are numerous benefits to pursuing a phased development to support our production growth plan. Importantly, a phased development strategy can provide for first oil production earlier than could

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otherwise be possible using traditional development techniques, which are disadvantaged by more time-consuming, costly and sequential appraisal and pre-development activities. In certain circumstances, we believe a phased approach can optimize full-field development through a better understanding of dynamic reservoir behavior and allows numerous activities to be performed in a parallel rather than a sequential manner. 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 also refines the appraisal and development plans based on experience gained in initial phases of production and by leveraging existing infrastructure as subsequent phases of development are implemented. Production and reservoir performance from the initial phase are monitored closely to determine the most efficient and effective techniques to maximize the recovery of reserves in the most economic manner. 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.

        For example, first oil production from the Jubilee Field commenced in November 2010, and we received our first oil revenues in early 2011. This development timeline from discovery to first oil was significantly less than the industry average of seven to ten years and set a record for a deepwater development at this water depth in West Africa. This condensed timeline reflects the lessons learned by members of our experienced management while leading other large scale deepwater developments.

Identify, access and explore emerging regions and hydrocarbon plays

        Our management and exploration team has demonstrated an ability to identify regions and hydrocarbon plays that yield multiple large commercial discoveries. We will continue to utilize our systematic and proven geologically focused approach to emerging petroleum systems where geological data suggests hydrocarbon 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 initially focus. Many of our licenses 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 Atlantic Margin, 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 into other regions and play types.

        We may farm-in to new venture opportunities to undertake exploration in emerging basins, new plays and fairways to enhance and optimize our portfolio. Consistent with this strategy, we may also evaluate potential corporate and asset acquisition opportunities as a source of new ventures to support and expand our asset portfolio.

Kosmos Exploration Approach

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

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

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

        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.

Operations by Geographic Area

        We operate in the oil and gas exploration and production industry and have operations in Africa and South America. Currently, all revenues are generated from our operations offshore Ghana. Oil produced from the Jubilee Field has priced in reference to Dated Brent crude. Brent crude is produced in the North Sea and is widely accepted by the oil and gas industry as the most representative of the global physical standards for the oil market in comparison to other reference oils, such as West Texas Intermediate ("WTI"). The location of the Jubilee Field offshore Ghana allows us to sell our oil to the major refining markets of North America, Asia and Europe.

Ghana

        The WCTP and DT Blocks are located within the Tano Basin, offshore Ghana. This basin contains a proven world-class petroleum system as evidenced by our discoveries.

        The Tano Basin represents the eastern extension of the Deep Ivorian Basin which resulted from the development of an extensional sedimentary basin caused by tensional forces associated with opening of the Atlantic Ocean, 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 Tano Basin sediments comprise 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 trapping geometries.

        The primary reservoir types consist of well imaged Turonian and Campanian aged submarine fans situated along the steeply dipping shelf margin and trapped in an up dip direction by thinning of the reservoir and/or faults. Many of our discoveries have similar trap geometries.

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        Kosmos is the operator of the WCTP Block and holds a 30.875% participating interest. The WCTP Petroleum Agreement ("WCTP PA"), which governs our activities related to the WCTP Block, and for commercial development areas, has a duration of 30 years from its effective date of July 22, 2004; however, in July 2011, at the end of the seven-year exploration phase, parts of the WCTP Block on which we had not declared a discovery area, were not in a development and production area or were not in the Jubilee Unit were subject to relinquishment ("WCTP Relinquishment Area"). Our existing discoveries within the WCTP Block (Akasa, Mahogany and Teak) have not been relinquished, as the WCTP PA remains in effect after the end of the exploration phase for these areas while commerciality is being established. In addition, we have disputed the relinquishment of the area around the Cedrela prospect. In July 2011, immediately prior to Kosmos receiving the drilling rig from another operator, damage to the rig incurred during preparations to move the rig to the WCTP Block operations rendered the rig incapable of drilling the Cedrela-1 exploration well prior to the end of the WCTP exploration period on July 21, 2011. As a result of this unforeseen delay in the drilling of the Cedrela-1 exploration well, the Company, as Operator for the WCTP PA Block partners, delivered a Notice of Force Majeure. The Ministry of Energy and Ghana National Petroleum Corporation ("GNPC") did not agree this event was Force Majeure. On August 24, 2011, we as Operator of the WCTP Block and on behalf of the WCTP Block partners, delivered a Notice of Dispute to the Ministry of Energy and GNPC as provided under the WCTP PA, which is the initial step in triggering the formal dispute resolution process under the WCTP PA with the government of Ghana regarding our rights to drill the Cedrela-1 exploration well. This Notice of Dispute establishes a process for negotiation and consultation for a period of 30 days (or longer if mutually agreed) among senior representatives from the Ministry of Energy, GNPC and the WCTP Block partners to resolve the matter. The issue continues to be discussed in an effort to reach a mutually agreed upon resolution among the parties. See "Item 1A. 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."

        We and our WCTP Block partners have certain rights to negotiate a new petroleum contract with respect to the WCTP Relinquishment Area. We and our WCTP Block partners exercised such right in July 2010 and formally submitted a proposed new petroleum agreement for the WCTP Relinquishment Area in early 2011. We and our WCTP Block partners, the Ghana Ministry of Energy and GNPC have agreed such WCTP PA rights to negotiate extends from July 21, 2011 until such time as either a new petroleum agreement is negotiated and entered into with us or we decline to match a bona fide third party offer GNPC may receive for the WCTP Relinquishment Area.

        Kosmos holds a non-operated 18.0% participating interest in the DT Block. The DT Petroleum Agreement ("DT PA"), which governs our activities relating to the DT Block, and for commercial development areas, has a duration of 30 years from its effective date of July 19, 2006. The seven-year exploration phase of the DT PA expired in January 2013. Our existing discoveries within the DT Block (Tweneboa, Enyenra, Ntomme and Wawa) are not subject to relinquishment upon expiration of the exploration phase of the DT PA, as the DT PA remains in effect after the end of the exploration phase for these areas while commerciality is being established. We and our DT Block partners have certain rights of first refusal for the granting of a new petroleum contract and certain rights to negotiate a new petroleum contract with respect to areas of the DT Block that are subject to relinquishment under the DT PA; that is acreage not within a discovery area, development and production area or the Jubilee Unit ("DT Relinquishment Area"). We and our DT Block partners exercised such right to negotiate a new petroleum contract in January 2012.

Our Ghanaian Discoveries

        Information about our Ghanaian discoveries is summarized in the following table.

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        The following is a brief discussion of our discoveries to date on our license areas offshore Ghana. See "Item 1A. Risk Factors—We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects."

Jubilee Discovery

        The Jubilee Field was discovered by Kosmos in 2007 within the WCTP Block. An appraisal well was subsequently drilled in the offsetting DT Block, confirming a large accumulation of oil underlying areas within both blocks. The Jubilee Field 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, the discovery area was unitized for purposes of joint development by the WCTP and DT Block participating interest holders. The UUOA specifies a split operatorship role. Kosmos was the Technical Operator for Development and Tullow was designated as the Unit Operator. The initial tract participations were 50% for each block. Pursuant to the terms of the Jubilee Field UUOA, the percentage is subject to a process of redetermination. The initial redetermination process was completed on October 14, 2011. Any party to the Jubilee UUOA with more than a 10% Jubilee Unit Interest may call for a second redetermination after December 1, 2013. As a result of the initial redetermination process, the tract participation was determined to be 54.36660% for the WCTP Block and 45.63340% for the DT Block. Our Unit Interest was increased from 23.50868% (our percentage after Tullow's acquisition of EO Group Limited ("EO Group")—see "Item 8. Financial Statements and Supplementary Data—Note 5—Joint Interest Billings") to 24.07710%. See "Item 1A. 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 Jubilee Field is a combination structural-stratigraphic trap with reservoir intervals consisting of a series of stacked Upper Cretaceous Turonian-aged, deepwater turbidite fan lobe and channel deposits.

        The location of the Jubilee Field led to the decision to implement an FPSO based development plan. The FPSO is designed to provide water and natural gas injection to support reservoir pressure and to process and store oil and natural gas. The Phase 1 development focused on partial development of certain reservoirs in the Jubilee Field. The Kosmos-led integrated project team successfully executed an initial 17 well development plan, which included nine producing wells, six water injection wells and two natural gas injection wells, the "Kwame Nkrumah" FPSO and subsea infrastructure. This initial phase provided infrastructure capacity for additional production and injection wells that could potentially be drilled in future phases of development. Future phases include the further development of the two existing producing reservoirs and development of the three remaining reservoirs to maximize ultimate recovery.

        Production from the Phase 1 development commenced in November 2010, with Kosmos' first lifting in early 2011. As production from the field grew through 2011, certain near-wellbore productivity issues were identified, impacting several of the Phase 1 production wells. The Jubilee Unit partners identified a means of successfully mitigating the near-wellbore productivity issues experienced in the Jubilee production wells. To date, six wells have been successfully treated and additional stimulation treatments will be conducted as required. We have received an approval for the Phase 1A PoD of the Jubilee Field, with production from Phase 1A commencing in late 2012. The Phase 1A development is expected to include five additional production wells and three additional water injection wells and associated infrastructure.

        Oil production from the Jubilee Field averaged approximately 72,000 barrels of oil per day during 2012 and we exited 2012 with production of approximately 110,000 barrels of oil per day. The JFFDP was submitted to the government of Ghana in December 2012. The JFFDP

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contemplates future development of the Jubilee Field, after Phase 1A, which will consist of infill drilling and development of the remaining Jubilee reservoirs. The JFFDP is anticipated to fully develop the field.

WCTP Block Discoveries

        Mahogany is located within the WCTP Block, southeast of the Jubilee Field. The field is approximately 37 miles (60 kilometers) offshore Ghana in water depths of 4,101 to 5,905 feet (1,250 to 1,800 meters). We believe the field is a combination stratigraphic-structural trap with reservoir intervals contained in a series of stacked Upper Cretaceous Turonian-aged, deepwater 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, a combined area covering parts of the Mahogany East discovery and the Mahogany Deep discovery, was declared commercial in September 2010, and a PoD was submitted to Ghana's Ministry of Energy as of May 2, 2011. In a letter dated May 16, 2011, the Minister of Energy did not approve the PoD and requested that the WCTP Block partners take certain steps regarding notifications of discovery and commerciality; and requested other information. The WCTP Block partners believe the combined submission was proper and have held meetings with GNPC which resolved issues relating to the PoD work program. From May 2011, the Ministry of Energy, GNPC and the WCTP Block partners continued working to resolve other differences; however, the WCTP PA contains specific timelines for PoD approval and discussions, which expired at the end of June 2011. On June 30, 2011, we as Operator of the WCTP Block and on behalf of the WCTP Block partners, delivered a Notice of Dispute to the Ministry of Energy and GNPC as provided under the WCTP PA, which is the initial step in triggering the formal dispute resolution process under the WCTP PA with the government of Ghana regarding approval of the Mahogany PoD. This Notice of Dispute establishes a process for negotiation and consultation for a period of 30 days (or longer if mutually agreed) among senior representatives from the Ministry of Energy, GNPC and the WCTP Block partners to resolve the matter. We and the WCTP Block partners are in discussions with the Ministry of Energy and GNPC to resolve differences on the PoD.

        The Teak discovery is located in the western portion of the WCTP Block, northeast of the Jubilee Field. The field is approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 650 to 3,600 feet (200 to 1,100 meters). We believe the field is a structural-stratigraphic trap with an element of four-way closure. The Teak-1, Teak-2 and Teak-3 wells have intersected multiple oil and natural gas condensate bearing reservoirs in Campanian and Turonian zones. Fluid samples recovered from the wells indicate an oil gravity of between 32 and 39 degrees API and natural gas condensate gravity of between 40 and 45 degrees API. The Teak-4A appraisal well was completed in May 2012. The well encountered non-commercial reservoirs and accordingly was plugged and abandoned.

        The Akasa discovery is located in the western portion of the WCTP Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 3,200 to 5,050 feet (950 to 1,550 meters). The discovery is southeast of the Jubilee Field. We believe the target reservoirs are channels and lobes that are stratigraphically trapped. The Akasa-1 well intersected oil bearing reservoirs in the Turonian zones. Fluid samples recovered from the well indicate an oil gravity of 38 degrees API.

        Following additional appraisal and evaluation, a decision regarding the commerciality of these discoveries on the WCTP Block will be made by the WCTP Block partners. Should a discovery be declared commercial, a PoD would be prepared for submission to Ghana's Ministry of Energy

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within six months of the declaration of commerciality. We expect that any future development of the WCTP Block discoveries would be a subsea tie-back through the Jubilee FPSO.

DT Block Discoveries

        The Tweneboa discovery is located in the central portion of the DT Block approximately 31 miles (50 kilometers) offshore Ghana in water depths of approximately 3,281 to 5,252 feet (1,000 to 1,500 meters). We believe 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, Tweneboa-3ST and Tweneboa-4 wells have intersected multiple natural gas condensate and oil bearing reservoirs in this Turonian turbidite sequence. Fluid samples recovered from the wells indicate an oil gravity of approximately 31 degrees API and a natural gas condensate gravity of between 41 and 47 degrees API.

        The Enyenra discovery is located in the Western portion of the DT Block. The field is approximately 28 miles (45 kilometers) offshore Ghana in water depths of approximately 3,300 to 5,000 feet (1,000 to 1,500 meters). We believe the field is primarily a stratigraphic trap with reservoir intervals contained within a series of stacked Upper Cretaceous Turonian-aged, deepwater channel deposits. The Owo-1, Owo-1 ST1, Owo-1RA, Enyenra-2A, Enyenra-3A and Enyenra-4A wells have intersected multiple oil and natural gas condensate bearing reservoirs in a Turonian turbidite sequence. As of December 2012, drilling operations on the Enyenra-6A well have commenced and well results are expected in the first quarter of 2013. Fluid samples recovered from the wells indicate an approximate oil gravity of 32 degrees API, and a natural gas condensate gravity of between 42 and 48 degrees API. We believe Enyenra is predominantly an oil accumulation.

        The Ntomme discovery is located in the central portion of the DT Block. The field is approximately 32 miles (52 kilometers) offshore Ghana in water depths of approximately 3,950 to 5,700 feet (1,200 to 1,750 meters). We believe the field is a stratigraphic trap with reservoir intervals contained within a series of stacked Upper Cretaceous Turonian-aged, deepwater fan lobes and channel deposits. The Tweneboa-3ST well discovered the Ntomme discovery and the Ntomme-2A appraisal well confirmed a downdip extension of the field. The wells encountered high-quality stacked reservoir sandstones. The Ntomme-2A confirmed the majority of the resources in the discovery to be oil. Fluid samples recovered from the wells indicate an oil gravity of 35 degrees API.

        In November 2012, we submitted a declaration of commerciality and PoD over the TEN discoveries and are awaiting approval from the government of Ghana. Upon receiving approval, we anticipate commencing execution of the development plan, which is focused on an oil-based FPSO development.

        The Wawa-1 exploration well intersected oil and gas-condensate in a Turonian-aged turbidite channel system. Pressure data shows that it is a separate accumulation from the TEN fields. Following additional appraisal and evaluation, a decision regarding the commerciality of the Wawa discovery will be made by the DT Block partners. Should the discovery be declared commercial, a PoD would be prepared for submission to Ghana's Ministry of Energy within six months of the declaration of commerciality.

Our Ghanaian Prospects

WCTP Block

        We and our WCTP Block partners have certain rights to negotiate a new petroleum contract with respect to the WCTP Relinquishment Area. We and our WCTP Block partners exercised such

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right in July 2010 and formally submitted a proposed new petroleum agreement for the WCTP Relinquishment Area in early 2011. We and our WCTP Block partners, the Ghana Ministry of Energy and GNPC have agreed such WCTP PA rights to negotiate extends from July 21, 2011 until such time as either a new petroleum agreement is negotiated and entered into with us or we decline to match a bona fide third party offer GNPC may receive for the WCTP Relinquishment Area. Should a new petroleum agreement be entered into for the WCTP Relinquishment Area, we have identified prospects that have yet to be drilled on the WCTP Relinquishment Area.

DT Block

        In December 2012, we spud the Sapele-1 exploration well. Drilling of the well was completed in February 2013. The well is not considered a productive well and accordingly will be plugged and abandoned. We and our DT Block partners have certain rights to negotiate a new petroleum contract with respect to the DT Relinquishment Area. We and our DT Block partners exercised such right in January 2012. Should a new petroleum agreement be entered into for the DT Relinquishment Area, we have identified prospects that have yet to be drilled on the DT Relinquishment Area.

Cameroon

        We have two petroleum contracts in Cameroon, governing the Ndian River Block and adjoining Fako Block. These blocks are located within the Rio del Rey and Douala Basins. Kosmos is the operator of the Ndian River Block and Fako Block and holds a 100% participating interest in both blocks.

        The Ndian River Block petroleum contract has a duration of up to 7 years from the November 2006 effective date with the current exploration period continuing into November 2013. We are in the first of two optional renewals, which was recently extended by one year, of the exploration period of our Ndian River Block, expiring in November 2013. The current exploration period carries a one-well obligation. In the event of commercial success, we have the right to develop and produce oil for a period of 20 years and gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended for an additional period of 10 years under certain circumstances.

        In January 2012, Kosmos entered into a license with the Republic of Cameroon for the Fako Block, which borders the southeast portion of our Ndian River Block in the Rio del Rey Basin. The Fako Block petroleum contract has an initial period of two years from the January 2012 effective date and may be extended into January 2018 at our election. In the event of commercial success, we have the right to develop and produce oil for a period of 20 years and gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended for an additional period of 10 years under certain circumstances.

        Kosmos has acquired gravity, magnetic and 2D seismic data over selected portions of our Cameroon licenses. Cameroon's producing basins lie south of the prolific Niger Delta in the Gulf of Guinea. The coastal area 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. The Ndian River Block and portions of the Fako Block are located in the Rio del Rey Basin. The Fako Block also extends south into the Douala Basin.

        There are two primary play types on the Ndian River Block, the Isongo (Miocene) turbidite structural play and the Upper Cretaceous structural play. The Isongo turbidite structural play focuses on the Miocene aged turbidite reservoirs charged from the traditional Rio Del Rey Tertiary source rocks. We will test this play type with our Sipo-1 exploration well, which spud in February 2013. The Isongo reservoir fairway constitutes the primary reservoir in multiple other oil and gas discoveries to

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the south. The Sipo prospect is located onshore, in the southern part of the Ndian River Block. It is a large structurally trapped anticline associated with multiple stacked targets within the Miocene Isongo Formation. The Upper Cretaceous structural play targets Upper Cretaceous reservoirs charged from Cretaceous source rocks.

        We are currently assessing prospectivity on our recently acquired Fako Block license area, and accordingly information concerning prospects, if any, on such recently acquired license area is not yet available. We currently are, and plan to continue, assessing the prospectivity for this license area.

Mauritania

        In June 2012, Kosmos successfully acquired three new petroleum contracts offshore Mauritania. The new exploration licenses are Offshore Blocks C8, C12 and C13. Kosmos is the operator and holds a 90% participating interest in all blocks. The initial period of each contract is four years and may be extended to June 2022 at our election if certain requirements are met. Kosmos is currently in the first exploration period of the blocks, expiring in June 2016. In the event of commercial success, we have the right to develop and produce oil for 25 years and gas for 30 years from the grant of an exploitation authorization from the government, which may be extended for an additional period of 10 years under certain circumstances.

        Offshore Blocks C8, C12 and C13 are located on the western margin of the proven petroleum system of the Mauritania Salt Basin. The blocks are adjacent to a proven petroleum system with the primary targets being Cretaceous sediments on structure and stratigraphic traps. Available geologic and geophysical data has led to the interpretation and mapping of possible Cretaceous basin floor fans outboard of the Salt Basin. The target prospects are basin floor fans over anticlinal structures. The Cretaceous source rocks penetrated by wells and typed to oils in the Mauritania Salt Basin are the same age as those which charge oil and gas fields throughout West Africa.

        During the first half of 2013, the Company anticipates initiating a 2D seismic data acquisition program on approximately 6,000 line-kilometers, covering all three blocks. A 3D seismic program will be targeted for commencement in 2013. Information concerning prospects, if any, on such recently acquired license area is not yet available.

Morocco

        During 2011, Kosmos acquired two new petroleum contracts, renewed an existing petroleum contract and acquired a new reconnaissance contract in Morocco. Our exploration licenses currently include the Cap Boujdour Offshore Block, which is within the Aaiun Basin, and the Essaouira Offshore Block and the Foum Assaka Offshore Block, which are within the Agadir Basin. Our reconnaissance contract is over the Tarhazoute Offshore area within the Agadir Basin.

        Kosmos is the operator of the Cap Boujdour Offshore Block and has a 75% participating interest. We are currently in the first exploration period, which was recently extended to March 2014. The exploration phase may be extended up to eight years from the September 2011 effective date, or to September 2019. In the event of commercial success, we have the right to develop and produce oil or gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended for an additional period of 10 years under certain circumstances.

        This block is located within the Aaiun Basin, along the Atlantic passive margin and covers a high-graded area within the original Boujdour Offshore Block which expired in February 2011. Detailed seismic sequence analysis suggests the possible existence of stacked deepwater turbidite systems throughout the region. The scale of the license area has allowed us to identify distinct exploration fairways on this block, which provide substantial exploration opportunities. Based in part on a 3D seismic survey, we have been able to identify 20 prospects through trap identification, structural

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analysis, and depositional history mapping. The primary prospect types consist of well imaged Lower Cretaceous age slope channels and fans draped over anticlinal structures or in three-ways fault traps. The prospects exist in water depths varying from 1,000 to 3,000 meters. See "Item 1A. 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."

        Kosmos is the operator of the Foum Assaka Offshore Block. In October 2012, the Moroccan government issued a joint ministerial order approving our acquisition of an additional 18.75% participating interest in the Foum Assaka Offshore Block from Pathfinder Hydrocarbon Ventures, Ltd. ("Pathfinder"), a wholly owned subsidiary of Fastnet Oil and Gas plc ("Fastnet"), one of our block partners. Upon receipt of this order, we closed the acquisition of such additional participating interest with Pathfinder and have a 56.25% participating interest. We expect final governmental processes required to officially reflect the acquisition under Moroccan law to be completed in due course.

        We are currently in the first exploration period, which is for two and one-half years from its effective date (July 1, 2011) ending in December 2013. The exploration phase may be extended to July 2019 at our election. In the event of commercial success, we have the right to develop and produce oil or gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended for an additional period of 10 years under certain circumstances.

        Kosmos is the operator of the Essaouira Offshore Block and has a 37.5% participating interest. We are currently in the first exploration period, which is for two and one-half years from its effective date (November 8, 2011) ending in May 2014. The exploration phase may be extended to November 2019 at our election. In the event of commercial success, we have the right to develop and produce oil or gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended for an additional period of 10 years under certain circumstances.

        During the first quarter of 2013, we closed an acquisition to acquire an additional 37.5% participating interest in the Essaouira Offshore Block from Canamens Energy Morocco SARL, one of our block partners. We expect final governmental processes required to officially reflect the acquisition under Moroccan law to be completed in due course. After giving effect to this acquisition, our participating interest in the Essaouira Offshore Block will be 75%.

        In September 2012, as provided under the reconnaissance contract, we provided notification of intent to the Office National des Hydrocarbures et des Mines ("ONHYM") to enter into a petroleum contract for the Tarhazoute Offshore area. Negotiation of the petroleum contract and associated documents is currently ongoing. We anticipate we will be the operator of the block and will have a 75% participating interest. The Tarhazoute Offshore area is located offshore Morocco in the Agadir Basin between the Company's Essaouira and Foum Assaka Offshore Blocks.

        The Foum Assaka Offshore Block, Essaouira Offshore Block and Tarhazoute Offshore area are located in the Agadir Basin. A working petroleum system has been established in the onshore area of the Agadir Basin based on onshore and shallow offshore wells. Well control, geological and geochemical studies suggest possible Cretaceous and Jurassic source rocks are located in the offshore Agadir Basin. The offshore Agadir Basin sediments are interpreted to comprise thick sequences of Lower to Upper Cretaceous age formations consisting of deep water channels and lobes. The interpreted prospects trapping styles are varied and include pre-salt ponded slope fans, salt domes, salt cored anticlines and sub-salt structures.

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        The Company has fulfilled the 3D seismic acquisition requirements for the Foum Assaka Offshore Block and Essaouira Offshore Block by acquiring approximately 4,900 square kilometers of 3D seismic data across the blocks. We are in process of interpreting the results of the newly acquired 3D seismc and pre-existing data, and may drill an exploration well as early as late 2013.

        We are currently assessing prospectivity on our Agadir Basin acreage (Foum Asska, Essaouira and Tarhazoute) in Morocco, and accordingly information concerning prospects, if any, on such recently acquired license areas is not yet available. We currently are, and plan to continue, to process seismic information to assess the prospectivity for these license areas.

Suriname

        Kosmos has petroleum contracts covering Block 42 and Block 45 offshore Suriname. In November 2012, Kosmos finalized the assignment of a 50% participating interest in Block 42 and Block 45 to Chevron Global Energy Inc. ("Chevron") reducing its original interest from 100%. Kosmos retains a 50% participating interest in the blocks and remains the operator for the exploration phase of the petroleum contracts.

        The initial period for Block 42 offshore Suriname is for 4 years from its effective date (December 12, 2011). The Block 42 exploration phase may be extended to December 2020 at our election. Kosmos is currently in the first exploration period ending on December 13, 2015. In the event of commercial success, the duration of the contract will be 30 years from the effective date or 25 years from governmental approval of a plan of development, whichever is longer.

        The initial period for Block 45 offshore Suriname is for three years from its effective date (December 12, 2011). The Block 45 exploration phase may be extended to December 2018 at our election. Kosmos is currently in the first exploration period ending on December 13, 2014. In the event of commercial success, the duration of the contract will be 30 years from the effective date or 25 years from governmental approval of a plan of development, whichever is longer.

        Our blocks in Suriname are located within the Guyana-Suriname Basin, along the Atlantic passive margin of northern South America. The basin resulted from rock deformation caused by tensional forces associated with the opening of the Atlantic Ocean, as South America separated from Africa in the mid-Cretaceous period. This basin has experienced the same geologic forces which occurred along the transform margin of Africa and, therefore, we believe the basin's petroleum system to be analogous to petroleum systems seen in West Africa. A petroleum system in Suriname has been proven by the presence of onshore producing fields.

        During 2012, we completed a 3D seismic data acquisition program which covered approximately 3,900 square kilometers of portions of Block 42 and Block 45 offshore Suriname. The processing of this seismic data is expected to be completed in late 2013.

        We believe the play types offshore Suriname are relatively similar to those offshore West Africa. We believe the subsurface underlying the deep water offshore Suriname may contain subtle stratigraphic traps similar to those discovered offshore Ghana in our Jubilee field. Target reservoirs are Upper and Middle Cretaceous age basin floor fans and mid-slope channel sands which may have good lateral continuity. The Tambaredjo and Calcutta Fields onshore Suriname prove that a working petroleum system exists in the area. Geological and geochemical studies suggest the hydrocarbons in these fields were generated in source rocks located over 100 miles offshore in the area of our petroleum contracts. The source rocks are believed to be the same ones which charged giant fields offshore West Africa. We are currently assessing prospectivity on our recently acquired license areas in Suriname, and accordingly information concerning prospects, if any, on such recently acquired license areas is not yet available. We currently are, and plan to continue, to process seismic information to assess the prospectivity for these license areas.

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Our Reserves

        The following table sets forth summary information about our estimated proved reserves as of December 31, 2012. See "Item 8. Financial Statements and Supplementary Data—Supplemental Oil and Gas Data (Unaudited)" for additional information.

        All of our estimated proved reserves as of December 31, 2012, 2011 and 2010 were associated with our Jubilee Field in Ghana.

Summary of Oil and Gas Reserves

        Changes for the year ending December 31, 2012, include a reclassification of 15 MMBbl of proved undeveloped reserves to proved developed reserves related to the successful remediation efforts in treating the near wellbore productivity issues on certain of the producing wells in the Jubilee Field and continued field developmental drilling in the Jubilee Field. Additional changes include a decrease of 14 Bcf in proved gas reserves due to a decrease in our estimate of fuel gas which will be utilized for operating the FPSO.

        Changes for the year ending December 31, 2011, include an increase of 8 MMBbl of proved undeveloped oil reserves due to the reclassification of some of the proved developed producing volumes to proved undeveloped for volumes related to the remediation efforts to mitigate the near wellbore productivity issues on certain of the producing wells in the Jubilee Field and an increase in our Jubilee Field unit interest. Additional changes include an increase of 4 Bcf in proved undeveloped gas reserves due to an increase in our Jubilee Field unit interest (see "Item 8. Financial Statements and Supplementary Data—Note 4—Jubilee Field Unitization") and an increase in the estimated gas reserves to be used as fuel gas for operating the FPSO.

        Changes for the year ending December 31, 2010, include a decrease of 35 MMBbl of proved undeveloped oil reserves, associated with reclassification to proved developed, resulting from first oil in the Jubilee Field on November 28, 2010. Additional changes include an increase of 4 Bcf, associated with the booking of gas reserves to be utilized as fuel gas for operating the FPSO.

        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

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December 31, 2012. All estimated future net revenues are attributable to projected production from the Jubilee Field in Ghana.

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Estimated proved reserves

        Unless otherwise specifically identified in this report, the summary data with respect to our estimated proved reserves presented above has been prepared by Netherland, Sewell & Associates, Inc. ("NSAI"), our independent reserve engineering firm, in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC") applicable to companies involved in oil and natural gas producing activities and adjusted for imbalances. These rules require SEC reporting companies to prepare their reserve estimates using reserve definitions and pricing based on 12-month historical unweighted first-day-of-the-month average prices, rather than year-end prices. For a definition of proved reserves under the SEC rules, see the "Glossary and Selected Abbreviations." 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, 2012 are based on costs in effect at December 31, 2012 and the 12-month unweighted arithmetic average of the first-day-of-the-month price for the fiscal year ending December 31, 2012, 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 "Item 1A. Risk Factors—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."

Independent petroleum engineers

        NSAI, our independent reserve engineers, was established in 1961. Over the past 50 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.

        For the years ended December 31, 2012, 2011 and 2010, we engaged NSAI to prepare independent estimates of the extent and value of the proved reserves of certain of our oil and gas properties. These reports were prepared at our request to estimate our reserves and related future net revenues and

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PV-10 for the periods indicated therein. Our estimated reserves at December 31, 2012 and related future net revenues and PV-10 at December 31, 2012 are taken from reports prepared by NSAI, adjusted for imbalances, 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. The December 31, 2012 reserve report was completed on January 28, 2013, and a copy is included as an exhibit to this report.

        In connection with the preparation of the December 31, 2012, 2011 and 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, 2012, based upon its evaluation. NSAI's primary economic assumptions in estimates included an ability to sell oil at a price of $112.61/Bbl, a certain level of capital expenditures necessary to complete the Jubilee Field development program and the exercise of GNPC's back-in right on the Jubilee Field 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 report.

Technology used to establish proved reserves

        Under the 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 have been field tested and have 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, production and injection data, electrical logs, radioactivity logs, acoustic logs, whole core analysis, sidewall core analysis, downhole pressure and temperature measurements, reservoir fluid samples, geochemical information, geologic maps, seismic data, well test and interference pressure and rate data. Reserves attributable to undeveloped locations were estimated using performance from analogous wells with similar geologic depositional environments, rock quality, appraisal plans 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

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techniques include, but are not limited to, nodal analysis, material balance, and numerical flow simulation.

Internal controls over reserves estimation process

        In our technical services team, we currently maintain an internal staff of eight petroleum engineering and geoscience professionals with significant international experience that contribute to our Resource Management System. This team works closely with NSAI to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserve and resource estimation process. Our technical services team is responsible for overseeing the preparation of our reserves estimates. Our technical services team has over 100 combined years of industry experience among them with positions of increasing responsibility in engineering and evaluations. Each member of our team holds a Bachelor of Science degree in petroleum engineering or geology. The NSAI technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Joseph J. Spellman and Mr. Daniel T. Walker. Mr. Spellman has been practicing consulting petroleum engineering at NSAI since 1989. Mr. Spellman is a Licensed Professional Engineer in the State of Texas (No. 73709) and has over 30 years of practical experience in petroleum engineering. He graduated from University of Wisconsin-Platteville in 1980 with a Bachelor of Science Degree in Civil Engineering. Mr. Walker has been practicing consulting petroleum geology at NSAI since 1993. Mr. Walker is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 1272) and has over 30 years of practical experience in petroleum geoscience. He graduated from Michigan State University in 1980 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

        The Audit Committee reviews the processes utilized in the development of our Resource Management System and reserve estimates on an annual basis. In addition, our technical services team meets with representatives of our independent reserve engineers to review our assets and discuss methods and assumptions used in preparation of the reserve and resource estimates. Finally, our senior technical/operations management review reserves and resource estimates on an annual basis.

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License Areas

        The following table sets forth certain information regarding the developed and undeveloped portions of our license areas as of December 31, 2012 for the countries in which we currently operate.

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Drilling activity

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

        The following table shows the number of wells that are in the process of being drilled or are in active completion stages, and the number of wells suspended or waiting on completion as of December 31, 2012. The following table does not include the Sipo-1 exploration well on the Ndian River Block in Cameroon which spud in February 2013.

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Undeveloped license area expirations

        The WCTP PA has a duration of 30 years from its effective date (July 2004); however, in July 22, 2011, at the end of the seven-year exploration phase, the WCTP Relinquishment Area was subject to relinquishment. We maintain rights to our three existing discoveries within the WCTP Block (Akasa, Mahogany and Teak) as the WCTP PA remains in effect after the end of the exploration phase. In July 2011, immediately prior to Kosmos receiving the drilling rig from another operator, damage to the rig incurred during preparations to move the rig to the WCTP Block rendered the rig incapable of drilling the Cedrela-1 exploration well prior to the end of the WCTP exploration period on July 21, 2011. As a result of this unforeseen delay in the drilling of the Cedrela-1 exploration well, the Company, as Operator for the WCTP Block partners, delivered a Notice of Force Majeure. The Ministry of Energy and GNPC did not agree this event was Force Majeure. On August 24, 2011, we as Operator of the WCTP Block and on behalf of the WCTP PA Block partners, delivered a Notice of Dispute to the Ministry of Energy and GNPC as provided for under the WCTP PA, which is the initial step in triggering the formal dispute resolution process under the WCTP PA with the Government regarding our rights to drill the Cedrela-1 exploration well. This Notice of Dispute establishes a process for negotiation and consultation for a period of 30 days (or longer if mutually agreed) among senior representatives from the Ministry of Energy, GNPC and the WCTP Block partners to resolve the matter. The issue continues to be discussed in an effort to reach a mutually agreed upon resolution among the parties. See "Item 1A. 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."

        We and our WCTP Block partners have certain rights to negotiate a new petroleum contract with respect to the WCTP Relinquishment Area. We and our WCTP Block partners exercised such right in July 2010 and formally submitted a proposed new petroleum agreement for the WCTP Relinquishment Area in early 2011. We and our WCTP Block partners, the Ghana Ministry of Energy and GNPC have agreed such WCTP PA rights to negotiate extends from July 21, 2011 until such time as either a new petroleum agreement is negotiated and entered into with us or we decline to match a bona fide third party offer GNPC may receive for the WCTP Relinquishment Area.

        Mahogany, a combined area covering parts of the Mahogany East discovery and the Mahogany Deep discovery, was declared commercial in September 2010, and a PoD was submitted to Ghana's Ministry of Energy as of May 2, 2011. In a letter dated May 16, 2011, the Minister of Energy did not approve the PoD and requested that the WCTP Block partners take certain steps regarding notifications of discovery and commerciality; and requested other information. The WCTP Block partners believe the combined submission was proper and have held meetings with GNPC which resolved issues relating to the PoD work program. From May 2011, Ministry of Energy, GNPC and the WCTP Block partners continued working to resolve other differences; however, the WCTP PA contains specific timelines for PoD approval and discussions, which expired at the end of June 2011. On June 30, 2011, we as Operator of the WCTP Block and on behalf of the WCTP Block partners, delivered a Notice of Dispute to the Ministry of Energy and GNPC as provided under the WCTP PA, which is the initial step in triggering the formal dispute resolution process under the WCTP PA with the government of Ghana regarding approval of the Mahogany PoD. This Notice of Dispute establishes a process for negotiation and consultation for a period of 30 days (or longer if mutually agreed) among senior representatives from the Ministry of Energy, GNPC and the WCTP Block partners to resolve the matter. We and the WCTP Block partners are in discussions with the Ministry of Energy and GNPC to resolve differences on the PoD.

        In the DT Block in Ghana, the first extension period of the exploration phase over the undeveloped acreage of the DT Block expired on January 19, 2011. In accordance with the DT PA, Tullow, as Operator and on behalf of the DT Block partners, formally extended the DT PA into the second extension period and relinquished 25% of the DT Block. The seven-year exploration phase of

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the DT PA expired in January 2013. Our existing discoveries within the DT Block are not subject to relinquishment upon expiration of the exploration phase of the DT PA, as the DT PA remains in effect after the end of the exploration phase, and these are Tweneboa, Enyenra, Ntomme and Wawa. The DT Block partners submitted a declaration of commerciality and PoD for the TEN discoveries to Ghana's Ministry of Energy on November 6, 2012. Evaluation and appraisal activities continue on the Wawa discovery. We and our DT Block partners have certain rights of first refusal for the granting of a new petroleum contract and certain rights to negotiate a new petroleum contract with respect to the DT Relinquishment Area. We and our DT Block partners exercised such right to negotiate a new petroleum contract in January 2012.

        In Cameroon, under the Ndian River peteroleum contract and pursuant to a one-year extension approved by the Ministry of Industry, Mines, and Technological Development, the initial exploration phase to the Ndian River Block expired on November 19, 2010. On September 16, 2010, in compliance with the production sharing contract, we applied to Cameroon's Minister of Industry, Mines and Technology Development for a two-year renewal of the exploration period (the first of two additional exploration periods of two years each). On November 20, 2010, in accordance with the Ndian River Production Sharing Contract, Kosmos relinquished 30% of the original license area of the Ndian River Block and entered into the first two-year renewal period. In an order dated March 3, 2011, the Minister of Industry, Mines and Technology Development confirmed our entry into the first renewal period. On September 7, 2012, we applied to Cameroon's Minister of Industry, Mines and Technology Development for a one-year extension of the first renewal period, which was granted in an order dated October 11, 2012. The current exploration period now ends on November 20, 2013.

Domestic Supply Requirements

        Many of our petroleum contracts 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, the Jubilee Field partners agreed to provide the first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to GNPC at no cost. See "Item 1A. 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."

Significant License Agreements

        Below is a discussion concerning the licenses governing our current drilling and production operations.

West Cape Three Points Block

        Effective July 22, 2004, Kosmos, the EO Group and GNPC entered into the WCTP PA covering the WCTP Block offshore Ghana in the Tano Basin. As a result of farm-out agreements and other sales of partners interests for the WCTP Block, Kosmos, Anadarko WCTP Company ("Anadarko"), Tullow and Sabre Oil and Gas Limited ("Sabre"), a wholly owned subsidiary of Petro S.A., participating interests are 30.875%, 30.875%, 26.396% and 1.854%, respectively. Kosmos is the operator. GNPC has a 10% participating interest and will be carried through the exploration and development phases. GNPC has the option to acquire additional paying interests in a commercial discovery on the WCTP Block of 2.5%. 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. Under the WCTP PA, 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

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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 PA. Kosmos 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.

        Due to contractual relinquishments at the end of contract periods, the WCTP Block currently comprises areas that are part of our existing discoveries (Akasa, Mahogany and Teak) in the WCTP Block as well as the Cedrela prospect area, or approximately 123,635 acres (500 square kilometers) in water depths ranging from 165 to 5,900 feet (approximately 50 to 1,800 meters). The term of the WCTP PA is 30 years from the effective date of such agreement, being July 22, 2004. The exploration phase of the WCTP PA has expired and all work and financial obligations for the exploration periods under the WCTP PA have been met.

        We and our WCTP Block partners have certain rights to negotiate a new petroleum contract with respect to the WCTP Relinquishment Area. We and our WCTP Block partners exercised such right in July 2010 and formally submitted a proposed new petroleum agreement for the WCTP Relinquishment Area in early 2011. We and our WCTP Block partners, the Ghana Ministry of Energy and GNPC have agreed such WCTP PA rights extend from July 21, 2011 until such time as either a new petroleum agreement is negotiated and entered into with us or we decline to match a bona fide third party offer GNPC may receive for the WCTP Relinquishment Area.

Deepwater Tano Block

        Effective July 31, 2006, Kosmos, Tullow and Sabre entered into the DT PA with GNPC covering the DT Block offshore Ghana in the Tano Basin. As a result of farm-out agreements and other sales of partners interests for the DT Block, Kosmos, Anadarko, Tullow and Sabre's participating interests are 18%, 18%, 49.95% and 4.05%, respectively. Tullow is the operator. GNPC has a 10% participating interest and will be carried through the exploration and development phases. GNPC has the option to acquire additional paying interests in a commercial discovery on the DT Block of 5%. 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. Under the DT PA, 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 PA. Kosmos 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.

        Due to contractual relinquishments at the end of contract periods, the DT Block currently comprises approximately 203,345 acres (823 square kilometers). The term of the DT PA is 30 years from the effective date of such agreement, July 31, 2006. We are currently in the second extension period of the exploration phase of the DT PA, which expired in January 2013. All commitments under the extension period were fulfilled by drilling exploration wells on the DT Block in December 2012.

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        After the expiration of the exploration phase, the DT Block will comprise areas that are part of our existing discoveries in the DT Block. We and our DT Block partners have certain rights of first refusal for the granting of a new petroleum contract and certain rights to negotiate a new petroleum contract with respect to the DT Relinquishment Area. We and our DT Block partners exercised such right to negotiate a new petroleum contract in January 2012.

        The Ghanaian Petroleum Law and the WCTP and DT PAs 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 programs, for operations other than exploration and appraisal, must be approved by a joint management committee, consisting of representatives of certain block partners and GNPC. Certain decisions require unanimity. See "Item 1A. 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 PAs and as required by Ghana's Ministry of Energy, it was agreed the Jubilee Field would be unitized for optimal resource recovery. A Pre Unit Agreement was agreed to between the contractors groups of the WCTP and DT Blocks in 2008, with a more comprehensive unit agreement, the UUOA, agreed to in 2009 which govern each party's respective rights and duties in the Jubilee Unit. Tullow is the Unit Operator, while Kosmos is the Technical Operator for Development of the Jubilee Unit. The Jubilee Unit holders' interests are subject to redetermination in accordance with the terms of the UUOA. See "Item 1A. 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 initial redetermination process was completed on October 14, 2011. As a result of the initial redetermination process, the tract participation was determined to be 54.36660% for the WCTP Block and 45.63340% for the DT Block. Our Unit Interest was increased from 23.50868% (our percentage after Tullow's acquisition of EO Group—see "Item 8. Financial Statements and Supplementary Data—Note 5—Joint Interest Billings") to 24.07710%. The accounting for the Jubilee Unit is in accordance with the redetermined tract participation stated. Although the Jubilee Field is unitized, Kosmos' participating interests in each block outside the boundary of the Jubilee Unit remains the same. Kosmos remains operator of the WCTP Block outside the Jubilee Unit area.

        We, as the Technical Operator, led the Integrated Project Team ("IPT"), which consisted of geoscience, engineering, commercial, project services, and operations disciplines from within the Jubilee Unit partnership. The Technical Operator evaluated the resource base and developed an optimized reservoir depletion plan. This plan included the design and placement of wells and the selection of topside and subsea facilities. The Technical Operator's responsibilities also extended to project management of the design and implementation of the complete field development system. The Unit Operator is responsible for drilling and completing the development wells for the Jubilee Field development, according to the specifications outlined by the IPT, and providing other in-country support. Upon first production, the Unit Operator assumed responsibility for the day-to-day operations and maintenance of the FPSO as well as overseeing and optimizing the reservoir management plan based on field performance, including any well workover activity or additional infill drilling and subsequent phases. The responsibility of the Technical Operator and the IPT for the Jubilee Field Phase 1 development was completed upon commissioning of the gas compression and injection systems and project administrative close out.

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        First oil from the Jubilee Field Phase 1 development commenced on November 28, 2010, and we received approval from Ghana's Ministry of Energy for the Jubilee Field Phase 1A development in January 2012. The JFFDP was submitted to Ghana's Minister of Energy in December 2012.

Ndian River Block

        On December 19, 2006, Kosmos signed the Ndian River petroleum contract covering the Ndian River Block located predominately onshore Cameroon. Kosmos has a 100% participating interest in the block and is the operator. Société Nationale des Hydrocarbures ("SNH") has the option to back into the contract with an interest of up to 15% upon approval of a PoD. The Ndian River petroleum 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 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. On September 16, 2010, in accordance with the terms of the Ndian River petroleum contract and after fulfillment of all the obligations of the initial period, we submitted an application for entry into the first of two renewal periods of the exploration phase with an attendant one-well obligation. On September 7, 2012, we applied to Cameroon's Minister of Industry, Mines and Technology Development for a one-year extension of the first renewal period, which was granted in an order dated October 11, 2012. The current exploration period now ends on November 20, 2013.

        The Sipo-1 exploration well on the Ndian River Block spud in February 2013.

Sales and Marketing

        Production from the Jubilee Field began in November 2010, and we received our first oil revenues in early 2011. As provided under the UUOA and the WCTP and DT PAs, 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 Field oil on the international spot market, and we approve the terms of each sale proposed by such agent. We do not anticipate entering into any long term sales agreements at this time.

        There are a variety of factors which affect the market for oil, including the proximity and capacity of transportation facilities, demand for oil, the marketing of competitive fuels and the effects of government regulations on oil production and sales. Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are readily available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long-term material adverse effect on our financial position or results of operations.

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

        We are also affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. In recent 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 our stakeholders that we will be able to successfully compete when attempting to make further strategic acquisitions.

Title to Property

        Other than as specified in this annual report on Form 10-K, 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. For examples, see "Item 1A. 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 "Item 1A. Risk Factors—Maritime boundary demarcation between Côte D'Ivoire and Ghana may affect a portion of our license areas." and "Item 1. Business—Operations by Geographic Area, Ghana."

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 operations commence;



•

enjoin some or all of the operations or 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;

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•

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



•

require remedial measures to mitigate or remediate pollution, including pollution resulting 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. We cannot assure you that we have been or will be at all times in compliance with such laws, or that environmental laws and regulations will not change or become more stringent in the future in a manner that could have a material adverse effect on our financial condition and results of operations.

        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 increase costs to the oil and gas industry in general, such as more stringent or costly waste handling, disposal or cleanup requirements or financial responsibility and assurance requirements.

        For example, the Macondo spill in the Gulf of Mexico (described in "Item 1A. 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") 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 may, operate may also impose increased regulation as a result of this or similar incidents, which could materially delay, restrict or prevent our operations in those countries.

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. Both plans are based on the principle of "Tiered Response" to oil spills ("Guide to Tiered Response and Preparedness", IPIECA Report Series, Volume 14, 2007). A Tier 1 spill is defined as a small-scale operational incident which can be addressed with resources that are immediately available to Kosmos. A Tier 2 spill is a larger incident which would need to be addressed with regionally based shared resources. A Tier 3 spill is a large incident which would require assistance from national or world wide spill co-operatives. 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 and Kosmos 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 would engage the services of Oil Spill Response Limited ("OSRL") of Southampton, United Kingdom, an oil spill response contractor.

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        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 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 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, 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 could hire additional resources such as boats, earth moving equipment and personnel as necessary to respond to such an event. While we have the above in place, we can make no assurance, that these resources will be available or timely respond as intended, perform as designed or be able to fully contain or cap any oil spill, blow-out or uncontrolled flow of hydrocarbons.

        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 participating 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. We maintain insurance coverage typical of the industry in the areas we operate in, these include; property damage insurance, loss of production insurance, wreck removal insurance, control of well insurance, general liability including pollution liability to cover pollution from wells and other operations. We also participate in an insurance coverage program for the Jubilee FPSO. Our insurance is carried in amounts typical for the industry and relative to our size and operations and in accordance with our contractual and regulatory obligations.

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 association with local or foreign contractors. Companies who wish to gain rights to explore

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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 executive capacity. The Petroleum Commission is the regulatory body for the upstream petroleum industry and the advisor to the Ministry of Energy. GNPC has rights to undertake petroleum operations in any acreage declared open by Ghana's Ministry of Energy. As well, when petroleum operations are undertaken by GNPC in association with contracts, GNPC has a carried interest in each petroleum agreement and, following the declaration of any commercial discovery, such carried interest is typically subject to increase by a certain agreed upon amount at the option of GNPC. 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 Exploration and Production Act and our Ghanaian petroleum agreements contain provisions restricting the direct or indirect assignment or transfer of such petroleum agreements or interests thereunder without the prior written consent of GNPC and the Ministry of Energy. The Petroleum Exploration and Production Act 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 interests thereunder.

        Ghana's Parliament is considering the enactment of a new Petroleum Exploration and Production Act and has enacted a new Petroleum Revenue Management Act and the Petroleum Commission Act of 2011. The new Petroleum Exploration and Production Act remains in a draft form, with industry comments having been submitted. The new Petroleum Revenue Management Act of 2011 pertains primarily to the collection, allocation, and management by the government of Ghana of the petroleum revenue. The Petroleum Commission Act creates the Petroleum Commission, whose objective is to regulate and manage the use of petroleum resources and coordinate the policies thereto. The Petroleum Commission became effective in January 2012. Among the Petroleum Commission's functions are advising the Minister of Energy on matters such as appraisal plans, field development plans, recommending to the Minister national policies related to petroleum, and storing and managing data. We understand the primary purpose of the Petroleum Commission is to fulfill the regulatory functions previously undertaken by GNPC. 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 PAs (which include stabilization clauses) and the UUOA, and will not impose additional restrictions on the direct or indirect transfer of our license interests, including upon a change of control. See "Item 1A. 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." Ghana's Parliament is also considering the enactment of Petroleum (Local Content and Local Participation in Petroleum Activities) Regulations. Industry comments have been submitted.

Cameroon

        In 1999 and 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. 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 the Republic of Cameroon, represented by SNH, the Cameroon national oil company, and assignments of such contracts require the consent of the government. SNH,

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established in March 1980, participates in the form of joint ventures with the "contractors." Assignment of license interests requires the consent of the Minister in charge of Hydrocarbons.

Mauritania

        The main legislative acts in the Islamic Republic of Mauritania (State) relevant to petroleum exploration and production are Law No. 2010-033 dated July 20, 2010 and its amendment ("Hydrocarbon Laws"). The regulatory authority in Mauritania is the Ministry of Petroleum, Energy and Mines and the national oil company acting on its behalf is the Mauritanian Society of Hydrocarbons ("SMH"). SMH was instituted by Decree No. 2005-106 of November 7, 2005 and modified by Decree No. 2009-168 of May 3, 2009. Pursuant to Hydrocarbon Laws the State or SMH may undertake petroleum operations and may authorize other legal entities to undertake petroleum operations under exploration-production contracts ("PSC"). The Ministry shall sign PSCs on behalf of the State. The exploration period shall not be more than ten years, subject to certain permitted extensions and the exploitation period shall not be more than 25 years. Each PSC may provide that the State has a carried interest of up to 10% during the exploration period. Each PSC shall grant the State the option to participate for a percentage not less then 10% in the rights of the Contractor during the exploitation period.

Morocco

        The two main legislative acts in Morocco relevant to petroleum exploration and production are (i) the Law 21-90 (April 1, 1992) as amended and completed by the Law 27-99 (February 15, 2000) and (ii) the Decree 2-93-786 (November 3, 1993) as amended and completed by decree 2-99-210 (March 16, 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 ONHYM. ONHYM is a public establishment (établissement public) with the legal personality and financial autonomy created pursuant to the Law 33-01 (November 11, 2003) which was further completed by the Decree 2-04-372 (December 29, 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 contract 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 Sahrawai Arab Democratic Republic (the "SADR") has claimed sovereignty over the Western Sahara territory, including the area offshore, and has issued exploration licenses which conflict with those issued by Morocco, including certain licenses which conflict with the Cap Boujdour Offshore license issued to Kosmos. See "Item 1A. 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."

Suriname

        The three sets of rules governing petroleum exploration and production in Suriname are (i) Staatsolie's Concession Agreement (Decree E8-B, Official Gazette 1981 no. 59), (ii) the Mining

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Decree of 1986 (Official Gazette 1986 no. 28) and (iii) the Petroleum Law 1990 (Official Gazette 1991 no. 7, as amended in 2001).

        The Mining Decree granted concession rights for petroleum activities to state enterprises. Staatsolie Maatschappij Suriname N.V. ("Staatsolie") was founded in 1980 as a state enterprise and holds mining rights onshore and offshore in Suriname. The Petroleum Law granted state enterprises with petroleum concession rights the authority, upon the approval of the Minister of Natural Resources, to enter into petroleum contracts with petroleum companies. Therefore, companies who wish to gain rights to explore and produce in Suriname can only do so by entering into a petroleum contract with Staatsolie, subject to approval by the Minister of Natural Resources.

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.

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

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

Employees

        As of December 31, 2012, we had approximately 250 employees. 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.

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 pursuant to the laws of the Cayman Islands in March 2004. Pursuant to the terms of a corporate reorganization that was completed simultaneously with the closing of our IPO, all of the interests in Kosmos Energy Holdings were exchanged for newly issued common shares of Kosmos Energy Ltd. and as a result, Kosmos Energy Holdings became a wholly-owned subsidiary of 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.

Available Information

        Kosmos is listed on the NYSE and our common shares are traded under the symbol "KOS". We file or furnish annual, quarterly and current reports, proxy statements and other information with the SEC. The public may read and copy any reports, statements or other information at the SEC's Public

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Reference Room at 100 F Street, N.E., Washington, D.C. 20549. 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 documents we file electronically with the SEC.

        The Company also maintains an internet website under the name www.kosmosenergy.com. The information on our website is not incorporated by reference into this annual report on Form 10-K and should not be considered a part of this annual report on Form 10-K. Our website is included as an inactive technical reference only. We make available, free of charge, on our website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC.

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Item 1A.    Risk Factors

        You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this report, including the consolidated financial statements and the related notes included in "Item 8. Financial Statements and Supplementary Data." 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. The risks below are not the only ones we face. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us.

Risks Relating to the Oil and Natural Gas Industry and 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. Many of our current discoveries and all of our 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. 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 (or analogous developmental costs associated with onshore production in the case of our onshore licenses) 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, our onshore Cameroon and deepwater offshore Morocco, Suriname and Mauritania licenses have not yet proved to be economically viable production areas, as to date we do not have a commercially viable discovery or production in either of these regions. We have limited proved reserves, and we may not be successful in developing additional commercially viable production from our other discoveries and prospects.

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

        In this report 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

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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.

Drilling wells is speculative, often involving significant costs that may be more than we estimate, 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 dry holes. 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, appraisal 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 and South America, 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 could be forced to modify our plan of operation.

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 report 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

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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 report under the license agreements currently in place 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 WCTP PA extends for a period of 30 years from its effective date (July 2004); however, in July 2011, the WCTP Relinquishment Area was subject to relinquishment. We and our WCTP Block partners have certain rights to negotiate a new petroleum contract with respect to the WCTP Relinquishment Area. In July 2010, we and our WCTP Block partners exercised our right to negotiate a new petroleum contract and formally submitted a proposed new petroleum agreement for the WCTP Relinquishment Area in early 2011. If we are unsuccessful in negotiating a new petroleum agreement or choose to not match a bona fide third party offer for the WCTP Relinquishment Area, any identified prospects within the WCTP Relinquishment Area will not be able to be drilled by us. Further, if we are able to negotiate a new petroleum agreement or match a bona fide third party offer, we cannot assure you that any such new agreement will either be entered into or be on the same terms as the current WCTP PA.

        The DT PA also extends for a period of 30 years from its effective date and contains similar relinquishment provisions to the WCTP PA, but with the end of the seven year exploration phase occurring in January 2013. We and our DT Block partners have certain rights of first refusal for the granting of a new petroleum agreement with respect to the DT Relinquishment Area. We exercised such right in January 2012. If we are unable to negotiate a new petroleum agreement or we choose to not match a bona fide third party offer for the DT Relinquishment Area, any identified prospects within the DT Relinquishment Area will not be able to be drilled by us. Further, if we are able to negotiate a new petroleum agreement or match a bona fide third party offer, we cannot assure you that any such new agreement will either be entered into or be on the same terms as the current DT PA.

        Regarding our licenses in Cameroon, the current exploration period for the Ndian River license will expire on November 20, 2013. Kosmos is required to drill one well before the expiration of this renewal period (such requirement to be certified by the Sipo-1 exploration well which spud in February 2013). Failure to do so may result in our loss of the license. The initial exploration period for the Fako Block will expire on January 13, 2014. Under this petroleum contract, we have work commitments to perform exploration activities and other related activities. Failure to do so may result in our loss of the license.

        We are currently in the initial exploration phase for our petroleum contracts in Mauritania, with such phases of the Offshore Blocks C8, C12 and C13 expiring in June 2016. Under these petroleum

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contracts, we have work commitments to perform exploration activities and other related activities. Failure to do so may result in our loss of the licenses.

        We are currently in the initial exploration phase for our petroleum contracts in Morocco, with such phases of the Cap Boujdour Offshore Block, Essaouira Offshore Block, and the Foum Assaka Offshore Block expiring on March 1, 2014, April 21, 2014, and January 1, 2014, respectively. Under these petroleum contracts, we have work commitments to perform exploration and other related activities. Failure to do so may result in our loss of the license. We are currently negotiating the terms of the petroleum agreement which will govern the Tarhazante Block.

        Regarding our licenses in Suriname, under the production sharing contract covering Block 42, effective December 13, 2011, Kosmos is obligated during the initial four year exploration phase to conduct certain studies, reprocess seismic; acquire, process and interpret seismic data; and acquire, process and interpret 500 square kilometers of 3D seismic. Under the production sharing contract covering Block 45, effective December 13, 2011, Kosmos is obligated during the initial three year exploration phase to conduct certain studies and reprocess seismic data. Failure to complete such requirements may result in our loss of these licenses.

        For each of our 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. For additional detail regarding the status of our operations with respect to our various licenses, please see "Item 1. Business—Operations by Geographic Area."

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.

        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 counterparties 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 Field 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 initially determined by the respective interests in such contributed block interests. Pursuant to the terms of the

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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 initial redetermination process was completed on October 14, 2011. As a result of the initial redetermination process, the tract participation was determined to be 54.36660% for the WCTP Block and 45.63340% for the DT Block. Our Unit Interest (participating interest in the Jubilee Unit) was increased from 23.50868% (our percentage after Tullow's acquisition of EO Group's interest in July 2011) to 24.07710%. A second redetermination could occur sometime after December 1, 2013, if requested by a party that holds greater than a 10% interest in the unit. 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). 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;



•

the operator's expertise and financial resources;



•

approval of other block partners in drilling wells;



•

the scheduling, pre-design, planning, design and approvals of 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.

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

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interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report. See "Item 1. 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, 2012.

        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 report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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

        You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with the 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, adjusted for anticipated market premium, 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 report. 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 December 31, 2012 would each decrease by approximately $18.3 million. See "Item 1. Business—Our Reserves."

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

        Our performance and success largely depend on the ability, expertise, judgment and discretion of our management and the ability of our technical team to identify, discover, evaluate and develop reserves. The loss or departure of one or more members of our management and technical team could be detrimental to our future success. Additionally, a significant amount of shares in Kosmos held by members of our management and technical team have vested. There can be no assurance that our management and technical team will remain in place. If any of these officers or other key personnel resigns or becomes unable to continue in their present roles and is not adequately replaced, our results of operations and financial condition could be materially adversely effected. Our ability to manage our growth, if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.

Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms or at all 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 as we expand our operations. Obtaining seismic data, as well as exploration, appraisal, development and production activities entail considerable costs, and we may need to raise substantial additional capital, through additional debt financing, strategic alliances or future private or public equity offerings if our cash flows from operations are not sufficient to cover such costs.

        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 and revolving credit facility. Additional financing may not be available on favorable terms, or at all. Even if we succeed in selling additional equity 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) could extend beyond such term for a fixed period or life of production, depending on the jurisdiction. If we are

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unable to meet our well commitments and/or declare commerciality 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. 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;



•

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 or man-made 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, availability or mandated use 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.

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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 such decreases could result in reduced availability under our commercial debt facility.

        We 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, operating costs and tax burdens 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.

        The development of the market for natural gas in our license areas is in its early stages. Currently the infrastructure to transport and process natural gas on commercial terms is limited and the expenses associated with constructing such infrastructure ourselves may not be commercially viable given local prices currently paid for natural gas. Accordingly, there may be limited or no value derived from any natural gas produced from our 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 and natural gas 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. In addition, the shutting in of wells can lead to mechanical problems upon bringing the production back on line, potentially resulting in decreased production and increased remediation costs.

        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 announced it will build a gas pipeline from the Jubilee Field to transport such natural gas to the mainland for processing and sale; however, to date, the construction of the pipeline and onshore plant has not been completed. 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

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to Ghana at no cost. 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. 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. 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'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 an infrastructure that will allow us to take advantage of our discoveries. Additionally, many of our license areas are located in deepwater, which generally increases the capital and operating costs, chances of delay, planning time, technical challenges and risks associated with oil and natural gas exploration and production activities. As a result, our oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore or develop discoveries, prospects or licenses will depend in part on the evaluation of seismic data through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.

        Furthermore, the marketability of expected oil and natural gas production from our discoveries and prospects will also be affected by numerous factors. These factors include, but are not limited to, market fluctuations of prices, proximity, capacity and availability of drilling rigs and related equipment, qualified personnel and support vessels, processing facilities, transportation vehicles and pipelines, equipment availability, access to markets 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;

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•

uncontrolled flows or leaks of oil, well fluids, natural gas, brine, toxic gas or other pollutants or hazardous materials;



•

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 or man-made 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.

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 Africa and South America 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 of and the high cost of this infrastructure, further discoveries we may make in Africa and South America may never be economically producible.

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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 PA, the DT PA and the UUOA cover the two blocks and the Jubillee Unit that form the basis of our current 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 have previously had disagreements with the Ministry of Energy 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 our IPO. These past disagreements have been resolved. The resolution of certain of these disagreements required us to pay agreed settlement costs to GNPC and/or the government of Ghana.