Kosmos Energy Ltd. - Annual Report: 2013 (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 $951,286,205.

          The number of the registrant's Common Shares outstanding as of February 18, 2014 was 387,595,931.

DOCUMENTS INCORPORATED BY REFERENCE

          Part III, Items 10-14, is incorporated by reference from the Proxy Statement for the Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 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, Ireland, Mauritania, Morocco (including Western Sahara) 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 and production 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 along the Atlantic Margin. Our assets include existing production and other major development projects offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Ireland, Mauritania, Morocco (including Western Sahara) and Suriname. 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; developing the Tweneboa-Enyenra-Ntomme ("TEN") project which was approved by the Ministry of Energy in 2013; appraising our other discoveries in Ghana; and beginning a multi-year, exploration drilling program targeting several high impact opportunities.

Our Business Strategy

Grow proved reserves and production through exploration, appraisal and development

        We plan to optimize production and further develop the Jubilee Field, bring the TEN development project to production and appraise the Mahogany, Teak, Akasa and Wawa discoveries. In May 2013, the government of Ghana approved the PoD over the TEN discoveries. The TEN project is expected to deliver first oil in 2016. In the event of a declaration of commerciality and approval of a plan of development over our Mahogany, Teak, Akasa and/or Wawa discoveries, we intend to develop these discoveries to grow proved reserves and production. We also plan to drill exploration prospects, with the intent to further grow proved reserves and production should discoveries be made.

Successfully open and develop our offshore exploration plays

        We believe the prospects and leads potentially existing offshore Morocco, Mauritania, Suriname and Ireland provide a favorable opportunity to meaningfully create value. We anticipate drilling two to three play-opening exploratory wells per year in these basins beginning in 2014, depending on our analysis of seismic data covering the blocks, initial exploration drilling results and availability of drilling rigs and other required equipment and services. Depending on the results of these exploratory wells, additional wells may be drilled. Given the potential size of these prospects and leads, we believe that exploratory success in our operating areas could be significantly accretive to shareholder value.

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 development personnel are critical 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 enables us to fully consider and understand both risk and reward, as well as deliberately and collectively pursue strategies that maximize value. We used this philosophy and approach to make

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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 field developments designed to deliver early learnings and accelerate 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 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 use our systematic and proven geologically-focused approach to frontier and 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 Cretaceous petroleum systems across the Atlantic Margin, including play types that had previously been largely ignored. In addition, our exploration portfolio includes sub-salt plays, which has been the other recent successful play concept along the Atlantic Margin.

        This approach and focus, coupled with a first mover advantage and our management and technical teams' reputation and relationships, provide a competitive advantage in identifying and accessing new strategic growth opportunities. We expect to continue seeking new opportunities where oil has not been discovered or produced in meaningful quantities by leveraging the skills of our experienced technical team. This includes our existing areas of interest as well as selectively expanding our reach into other locations along the Atlantic Margin. We may farm-in to new venture opportunities to undertake exploration in emerging basins, new plays and fairways to enhance and optimize our portfolio.

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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. 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 targets licenses over the particular basin or fairway 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. Kosmos also looks for 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 currently have operations in Africa, Europe and South America. Currently, all revenues are generated from our operations offshore Ghana.

Ghana

        The West Cape Three Points Block ("WCTP Block") and Deepwater Tano Block ("DT Block") 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.

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        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.

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 4—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. 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 and asset value.

        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 through stimulation treatments. We received approval for the Phase 1A PoD of the Jubilee Field and production from Phase 1A development commenced in late 2012. The Phase 1A development includes the drilling of up to eight additional wells consisting of up to five production wells and three water injection wells. Five wells (three producers and two water injection wells) are online. Program execution is expected to be completed in 2014.

        The Government of Ghana is in the process of completing the construction and connection of a gas pipeline from the Jubilee Field to transport natural gas to the mainland for processing and sale; however, to date, the construction of the pipeline and the onshore plant has not been

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completed and the Company is presently unable to predict with certainty when completion will occur, as several previous completion dates have passed. In the absence of a pipeline to remove large quantities of natural gas from the Jubilee Field in order to maximize production levels it is anticipated that we will need to flare such natural gas. Currently, we have not been issued an amended permit from the Ghana Environmental Protection Agency ("Ghana EPA") to flare natural gas produced from the Jubilee Field in substantial quantities. If we are unable to resolve issues related to the continuous removal of associated natural gas in large quantities from the Jubilee Field, our oil production will be negatively impacted. See "Risk Factors—Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production."

        During 2013, we experienced mechanical issues in the Jubilee Field, including failures of our water injection facilities on the FPSO and water and gas injection wells. This equipment downtime negatively impacted oil production during the year.

        Oil production from the Jubilee Field averaged approximately 97,500 barrels of oil per day during 2013. We submitted the JFFDP to Ghana's Minister of Energy in December 2012 and subsequently withdrew based on discussions with the government of Ghana. A PoD providing for development of the next phase within the Jubilee Field is expected to be submitted during 2014, although we can give no assurance that such approvals will be forthcoming in a timely manner or at all.

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.

        Effective January 14, 2014, the Ministry of Energy and GNPC entered into a Memorandum of Understanding with Kosmos Energy, on behalf of the WCTP PA Block partners, wherein all parties have settled all matters pertaining to the Notices of Dispute for the Mahogany East PoD and the Cedrela Notice of Force Majeure, and the Ministry of Energy has approved the Appraisal Programs for the Mahogany, Teak, and Akasa discoveries. As a result of the settlement, a portion of the WCTP PA area which contained the Cedrela prospect has been relinquished.

        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. We believe that the Akasa-2A appraisal well successfully

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identified the down dip water contact associated with the Akasa-1 discovery as intended. Should the Akasa discovery progress to a development, the Akasa-2A appraisal well is expected to be utilized in the development as a water injection well. However, since the Akasa-2A appraisal well did not encounter oil or gas reserves sufficient to be utilized as a producing well, accounting rules require that the costs associated with the Akasa-2A appraisal well be impaired. 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 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.

        Kosmos is the operator of the WCTP Block and holds a 30.875% participating interest. The 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 relinquished ("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. Effective January 14, 2014, the Ministry of Energy and GNPC entered into a Memorandum of Understanding with Kosmos Energy, on behalf of the WCTP PA Block partners, wherein all parties have settled all matters pertaining to the Notices of Dispute for the Mahogany East PoD and the Cedrela Notice of Force Majeure, and the Ministry of Energy has approved the Appraisal Programs for the Mahogany, Teak, and Akasa discoveries. As a result of the settlement, a portion of the WCTP PA area which contained the Cedrela prospect has been relinquished.

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, Enyenra-4A and Enyenra-6A wells have intersected multiple oil and natural gas condensate bearing reservoirs in a Turonian turbidite sequence. 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

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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 (includes Tweneboa, Enyenra and Ntomme). In May 2013, the government of Ghana approved the PoD over the TEN discoveries. Development of TEN will include the drilling and completion of up to 24 development wells, half of the wells designed as producers and the remainder as water or gas injectors to support ultimate field recoveries. The TEN development is expected to deliver first oil in 2016. Future development of gas resources at TEN is anticipated following the commencement of oil startup.

        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.

        Kosmos holds a non-operated 18.0% participating interest in the DT Block. The DT PA, which governs our activities relating to the DT Block and for commercial development areas therein, 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 determined.

Ireland

        We have identified the Porcupine Basin Offshore Ireland as an underexplored basin with the potential for large oil hydrocarbon accumulations in our core Cretaceous stratigraphic play concept.

        The Porcupine Basin is a Jurassic aged rift basin located on the eastern Atlantic margin offshore Southwest Ireland. Previous exploration was focused on Jurassic and Tertiary aged sandstones located in the shallow water portions of the basin. These wells encountered Jurassic, Cretaceous and Tertiary reservoirs, Jurassic source rocks and oil and gas; however, no commercial developments have taken place in the basin. We have identified a number of geologic features of Cretaceous age on vintage 2D seismic data which have play potential similar to the features identified in our Atlantic Margin acreage.

        In April 2013, we entered into a farm-in agreement with Antrim Energy Inc. ("Antrim"), whereby we acquired a 75% participating interest and operatorship, covering Licensing Option 11/5 offshore the west coast of Ireland. As part of the agreement, we reimbursed a portion of previously-incurred exploration costs and are paying the partner's share of 3D seismic costs.

        In April 2013, we entered into a farm-in agreement with Europa Oil & Gas (Holdings) plc ("Europa"), whereby we acquired an 85% participating interest and operatorship, covering Licensing Option 11/7 and 11/8 offshore the west coast of Ireland. As part of the agreement, we reimbursed a portion of previously-incurred exploration costs and are paying the partner's share of 3D seismic costs. Contingent upon an election by us and our partner to enter into a subsequent exploration drilling phase on one or both of the blocks, we will also fund 100% of the costs of the first exploration well on each block, subject to an investment cap of $90.0 million and $110.0 million, respectively, on each block.

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        In July 2013, Ireland granted us Frontier Exploration Licenses 1-13, 2-13, and 3-13 pursuant to Licensing Options 11/5, 11/7 and 11/8. The term of each contract is 15 years unless surrendered or revoked, and is divided into an initial phase of three years, and three subsequent phases of four years each. Relinquishment of 25% of the existing area is required at the end of the first phase and 50% of the existing area at the end of the second phase. Three months before the end of each phase, we must propose a work program for the subsequent phase for the approval of the Minister of Communications, Energy and Natural Resources. The second phase work program must include an exploration well. The contract area must be surrendered if a second exploration well has not been commenced by the end of the third phase. Upon entering these Frontier Exploration Licenses, we and the other block partners relinquished approximately 25% of the acreage covered by the Licensing Options.

        We completed a 3D seismic data acquisition program of approximately 5,000 square kilometers over these blocks and in the surrounding area in October 2013. The processing of this seismic data is expected to be completed in 2014.

        We are currently assessing prospectivity on license areas in Ireland, and accordingly information concerning prospects, if any, on such recently acquired license areas is not yet available. We currently are, and plan to continue, processing seismic information to assess the prospectivity for these license areas.

Mauritania

        In June 2012, we successfully acquired three new petroleum contracts offshore Mauritania. The new petroleum contracts are Offshore Blocks C8, C12 and C13. We are the operator and hold 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. We are 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 Mauritania Salt Basin. The blocks are adjacent to a proven petroleum system with the primary targets being Cretaceous sediments in structural and stratigraphic traps. Available geologic and geophysical data has led to the interpretation and mapping of possible Cretaceous basin floor fans in possible trapping geometries outboard of the Salt Basin. The Cretaceous source rocks penetrated by wells and typed to oils in the Mauritania Salt Basin are believed to be the same age as those which charge other oil and gas fields in the Late Cretaceous of West Africa.

        Mauritania is located in Northwest Africa and its continental shelf is part of the Mauritania-Senegal-Guinea Bissau (MSGBC) Atlantic margin basin. This is a Triassic salt basin which formed at the onset of rifting and contains an overlying Jurassic, Cretaceous and Tertiary passive margin sequence of limestones, sandstone and shales.

        A number of exploration wells have been drilled in shallow to moderate water depths in the basin and have resulted in oil and gas discoveries in both Tertiary and Cretaceous aged features. One of these, the Chinguetti Field is currently producing.

        Our acreage is located outboard of the producing area in three licenses which vary in water depth from 1,500 to 3,000 meters. These blocks cover an aggregate area of approximately 6.6 million acres and are focused beyond the edge of the salt province on the basin floor where potentially reservoir bearing Mid to Late Cretaceous aged stratigraphy has been identified on vintage 2D seismic data in areas where there is evidence for trapping geometries. Our understanding of the blocks will be refined with additional seismic data acquisition over the areas where a number of leads with considerable petroleum potential have been identified.

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        In May 2013, we completed a 2D seismic data acquisition program on approximately 6,000 line-kilometers, covering Blocks C8, C12 and C13. In November 2013, we completed a 3D seismic program of approximately 10,300 square kilometers over portions of Blocks C8 and C12. Processing of this seismic data is expected to be completed in 2014.

        We are currently assessing prospectivity on license areas in Mauritania, and accordingly information concerning prospects, if any, on such recently acquired license areas is not yet available. We currently are, and plan to continue, processing seismic information to assess the prospectivity for these license areas.

Morocco (including Western Sahara)

        During 2011, we acquired two new petroleum contracts, renewed an existing petroleum contract and acquired a new reconnaissance contract (which was subsequently converted to a new petroleum contract) in Morocco. Our petroleum contracts include the Cap Boujdour Offshore block, which is within the Aaiun Basin, and the Essaouira Offshore block, the Foum Assaka Offshore block and the Tarhazoute Offshore block, which are within the Agadir Basin. We are the operator of these petroleum contracts and our initial participating interests were 75%, 37.5%, 37.5% and 75% for the Cap Boujdour Offshore block, the Essaouira Offshore block, the Foum Assaka Offshore block and the Tarhazoute Offshore block, respectively.

Aaiun Basin

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

        We are the operator of the Cap Boujdour Offshore block. 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 and/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.

        In October 2013, we entered into a farm-out agreement with Capricorn Exploration & Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC ("Cairn"), covering the Cap Boujdour Offshore block, offshore Western Sahara. Under the terms of the agreement, Cairn will acquire a 20% non-operated interest in the exploration permits comprising the Cap Boujdour Offshore block. Cairn will pay 150% of its share of costs of a 3D seismic survey capped at $25.0 million and one exploration well capped at $100.0 million. In the event the exploration well is successful, Cairn will pay 200% of its share of costs on two appraisal wells capped at $100.0 million per well. Additionally, Cairn will contribute $12.3 million towards our future costs and, upon close of the transaction, $0.6 million for their share of costs incurred from the effective date of the contract through December 31, 2013. Completion of the transaction is subject to customary closing conditions, including Moroccan Government approvals. After completing the transaction, our participating interest in the Cap Boujdour Offshore block will be 55.0% and we will remain the operator.

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Agadir Basin

        We are the operator of the Foum Assaka Offshore, Essaouira Offshore and Tarhazoute Offshore blocks, which 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. Existing well data and geological and geochemical studies have demonstrated the presence of Cretaceous source rocks in the acreage. Onshore production suggests that possible Jurassic source rocks are also present 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.

        In January 2013, we closed on an agreement to acquire an additional 37.5% participating interest in the Essaouira Offshore block from Canamens Energy Morocco SARL, one of our block partners. Governmental approvals and processes for this acquisition were finalized in November 2013.

        In August 2013, final government approvals and processes were completed for the acquisition of an additional 18.75% participating interest in the Foum Assaka block in the Agadir Basin offshore Morocco from Pathfinder Hydrocarbon Ventures Limited ("Pathfinder"), a wholly owned subsidiary of Fastnet Oil and Gas plc ("Fastnet"), one of our block partners.

        In October 2013, we entered into three farm-out agreements with BP plc ("BP") covering our three blocks in the Agadir Basin, offshore Morocco. Under the terms of the agreements, BP will acquire a non-operating interest in each of the Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks. BP will fund Kosmos' share of the cost of one exploration well in each of the three blocks, subject to a maximum spend of $120.0 million per well, and pay its proportionate share of any well costs above the maximum spend. In the event a second exploration well is drilled in any block, BP will pay 150% of its share of costs subject to a maximum spend of $120.0 million per well. Upon close of the transaction, BP shall also pay $36.3 million for their share of past costs and $8.9 million for their portion of shared costs incurred from the effective date of the contract through December 31, 2013. Completion of the transactions is subject to customary closing conditions, including Moroccan Government approvals. After completing the transaction, our participating interests will be 30.0%, 29.925% and 30.0% in the Essaouira Offshore, Foum Assaka Offshore and Tarhazoute Offshore blocks, respectively, and we will remain the operator.

        We have recently completed interpretation of approximately 7,800 square kilometers of new and reprocessed 3D seismic data in our Foum Assaka Offshore and Essaouira Offshore blocks. During 2014, we plan to begin a seismic data acquisition program over the Tarhazoute Offshore and Essaouira Offshore blocks. We have identified numerous prospects in the Foum Assaka Offshore and Essaouira Offshore blocks. We plan to drill the FA-1 exploration well on the Eagle prospect during 2014.

        The Foum Assaka Offshore block is currently in the first extension period of the exploration permit, which is for two and one-half years from its effective date (January 1, 2014) ending in June 2016. 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 and/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.

        The Essaouira Offshore block is 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 and/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.

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        In October 2013, Kosmos executed a petroleum agreement with the Office National des Hydrocarbures et des Mines ("ONHYM"), the national oil company of the Kingdom of Morocco, covering the Tarhazoute Offshore block, to which the Company previously held certain exploration rights under a 2011 reconnaissance contract. Under the terms of the petroleum contract, the Company is the operator of the Tarhazoute Offshore block. ONHYM holds a 25% carried interest in the block through the exploration period. The Tarhazoute Offshore block is currently in the first exploration period, which is for two and one-half years from its effective date (December 9, 2013) ending in June 2016. The exploration phase may be extended for a total duration of eight years at our election and subject to our fulfilling specific work obligations, which include acquisition of 3D seismic data during the first period and drilling an exploration well in each of the subsequent periods. In the event of commercial success, the Company has the right to develop and produce oil and/or gas for a period of 25 years from the grant of an exploitation concession from the Government of Morocco, which may be extended for an additional period of 10 years under certain circumstances.

        We are currently assessing prospectivity on the Tarhazoute Offshore block 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, processing seismic information to assess the prospectivity for these license areas.

Suriname

        Our blocks in Suriname are located within the Guyana-Suriname Basin, along the Atlantic transform 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. 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.

        We believe the play types offshore Suriname are relatively similar to those offshore West Africa and may contain subtle stratigraphic traps similar to those discovered offshore Ghana in the 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 demonstrate 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 in the offshore basin. The source rocks are believed to be similar in age to those which charged some of the fields offshore West Africa. Suriname lies on the Atlantic transform margin of South America located between Guyana and French Guyana. The deep water basin is subdivided by the Demerara high, a platform area which separates the Suriname deep water basin from the French Guyana Basin where the recent Zaedyus oil discovery was made in Late Cretaceous sandstones in a stratigraphic trap. Block 42 and Block 45 sit in the deep water area west of the Demerara Platform in the center of a thick Cretaceous and Tertiary succession associated with the post rift subsidence of the Atlantic continental margin.

        A number of onshore and shelf wells have encountered oil and, as previously noted, the Tamberedjo and Calcutta fields are currently producing. These fields are believed to be sourced from deep water Cretaceous source rocks. Seismic evidence suggests thick Late Cretaceous and Tertiary reservoir systems have been deposited in the deep water area and this stratigraphy may contain stratigraphic and structural trapping geometries analogous to both the Zaedyus and Jubilee discoveries.

        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. In August 2013, we completed a 2D seismic program of approximately 1,400 line kilometers over a portion of Block 42, outside of the existing 3D seismic survey. The processing of these seismic data programs is expected to be completed by mid-2014.

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        The initial period for Block 42 offshore Suriname is for four years from its effective date (December 13, 2011). The Block 42 exploration phase may be extended to December 2020 at our election. We are currently in the first exploration period ending on December 12, 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 13, 2011). The Block 45 exploration phase may be extended to December 2018 at our election. We are currently in the first exploration period ending on December 12, 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.w

        We have petroleum contracts covering Block 42 and Block 45 offshore Suriname. In November 2012, we finalized the assignment of a 50% participating interest in Block 42 and Block 45 to Chevron Global Energy Inc. ("Chevron") reducing our original interest from 100%. We retain a 50% participating interest in the blocks and remain the operator for the exploration phase of the petroleum contracts.

        We are currently assessing prospectivity on 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, processing seismic information to assess the prospectivity for these license areas.

Our Reserves

        The following table sets forth summary information about our estimated proved reserves as of December 31, 2013. 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, 2013, 2012 and 2011 were associated with our Jubilee Field in Ghana.

Summary of Oil and Gas Reserves

        Changes for the year ended December 31, 2013, include an increase of 11 MMBbl of proved reserves as a result of drilling and reservoir performance, which is partially offset by 8 MMBbl of production during 2013. During 2013, approximately 1 MMBbl of proved undeveloped reserves from December 31, 2012 converted to proved developed reserves as of December 31, 2013. During the year ended December 31, 2013, we incurred $116.6 million of capital expenditures related to the Jubilee Field Phase 1A development.

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        Changes for the year ended 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 through the Phase 1A development of the Jubilee Field. These successful remediation efforts reduced the number of future drilling locations for the Jubilee Field (which included drilling locations related to our proved undeveloped reserves) and, as a result, approximately 5 MMBbl of proved undeveloped reserves from December 31, 2011 converted to proved developed reserves as of December 31, 2012. 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. As a result of progress on the Phase 1A development, approximately 10 MMBbl of proved undeveloped reserves from December 31, 2011 converted to proved developed reserves as of December 31, 2012. During the year ended December 31, 2012, we incurred $163.7 million of capital expenditures related to Phase 1A.

        Changes for the year ended 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 3—Jubilee Field Unitization") and an increase in the estimated gas reserves to be used 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 December 31, 2013. All estimated future net revenues are attributable to projected production from the Jubilee Field in Ghana. If we are unable to resolve issues related to continuous removal of associated natural gas in large quantities from the Jubilee Field, and the production restraints caused thereby, then the field's future net revenues discussed herein will be adversely affected. 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."

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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. 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.

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        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, 2013 are based on costs in effect at December 31, 2013 and the 12-month unweighted arithmetic average of the first-day-of-the-month price for the fiscal year ended December 31, 2013, 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, 2013, 2012 and 2011, 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 PV-10 for the periods indicated therein. Our estimated reserves at December 31, 2013 and related future net revenues and PV-10 at December 31, 2013 are taken from reports prepared by NSAI, 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, 2013 reserve report was completed on January 15, 2014, and a copy is included as an exhibit to this report.

        In connection with the preparation of the December 31, 2013, 2012 and 2011 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, 2013, based upon its evaluation. NSAI's primary economic assumptions in estimates included an ability to sell oil at a price of $108.76/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.

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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 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 internal reserve and resource estimates. 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.

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        The Audit Committee provides oversight on the processes utilized in the development of our internal reserve and resource 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.

License Areas

        The following table sets forth certain information regarding the developed and undeveloped portions of our license areas as of December 31, 2013 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:

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        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, 2013.