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 ☒  No ☐

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 ☐  No ☒

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 ☒  No ☐

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 ☒  No ☐

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. ☒

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 ☐  No ☒

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 $1,310,263,359.

The number of the registrant’s Common Shares outstanding as of February 16, 2016 was 385,253,510.

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, 2015.

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

 

 

 

TABLE OF CONTENTS

Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its subsidiaries. We have provided definitions for some of the industry terms used in this report in the “Glossary and Selected Abbreviations” beginning on page 2.

 

 

KOSMOS ENERGY LTD.

GLOSSARY AND SELECTED ABBREVIATIONS

The following are abbreviations and definitions of certain terms that may be 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.

 

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:

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.

 

PART I

Item 1.  Business

General

Kosmos is 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 development projects offshore Ghana, large discoveries offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Portugal, Sao Tome and Principe, Suriname, Morocco and Western Sahara. Kosmos is listed on the New York Stock Exchange (“NYSE”) and is traded under the ticker symbol KOS.

Kosmos was founded in 2003 to find oil in under‑explored or overlooked parts of West Africa. Members of the management team—who had previously worked together making significant discoveries and developing them in Africa, the Gulf of Mexico, and other areas—established the company on a single geologic concept that previously had been overlooked by others in the industry, the Late Cretaceous play system.

Following our formation, we acquired multiple exploration licenses and proved the geologic concept with the discovery of the Jubilee Field within the Tano Basin in the deep waters 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. As technical operator of the initial phase of the Jubilee Field, we planned and executed the development. Oil production from the Jubilee Field began in November 2010, just 42 months after initial discovery, a record for a deepwater development in this water depth in West Africa. Gross production from the Jubilee Field averaged approximately 102,500 Bopd for 2015.

Following our Initial Public Offering, we acquired several new exploration licenses and again proved our geologic concept with the Ahmeyim discovery in the deepwater offshore Mauritania in 2015. The Ahmeyim discovery (formerly known as Tortue) was one of the largest natural gas discoveries worldwide in 2015 and is believed to be the largest ever gas discovery offshore West Africa. We have since demonstrated the extension of the gas discovery into Senegal with the successful Guembeul-1 exploration well.

Our business strategy focuses on achieving three key objectives: (1) maximize the value of our Ghana assets; (2) continue to explore and appraise the deepwater basin offshore Mauritania and Senegal to maximize and monetize value; and (3) increase value further through a high‑impact exploration program to unlock new petroleum systems. In Ghana, we are focused on increasing production, cash flows and reserves from the Jubilee Field, the development of the Tweneboa‑Enyenra‑Ntomme (“TEN”) project, and the appraisal and development of our other Ghanaian discoveries. In Mauritania and Senegal, we expect to efficiently appraise and develop our current Ahmeyim discovery as well as continue to test our inventory of oil and gas prospects. We have a large inventory of leads and prospects in the remainder of our exploration portfolio which we plan to continue to build through new ventures and we plan to test this prospectivity targeting high impact opportunities along the Atlantic Margin.

Our Business Strategy

Grow proved reserves and production through exploration, appraisal and development

In the near‑term we plan to grow proved reserves and production by further developing and debottlenecking the Jubilee Field, including incorporating our Mahogany and Teak discoveries into the Greater Jubilee Full Field Development Plan (“GJFFDP”) and by completing the TEN development, which is expected to deliver first oil in the third quarter of 2016 through a second, dedicated FPSO. In the medium-term, growth could also be realized following the appraisal and ongoing assessment of commerciality and development over all or a portion of our new discoveries in Mauritania and Senegal. In the longer‑term, we plan to drill exploration prospects, with the intent to provide further growth in reserves and ultimately production.

Successfully open and develop our offshore exploration plays

We believe the prospects and leads potentially existing offshore Mauritania, Portugal, Sao Tome and Principe, Senegal, Suriname and Western Sahara in particular provide a favorable opportunity to create substantial value through exploration drilling. Given the potential size of these prospects and leads, we believe that exploratory success in our operating areas could significantly add to our growth profile.

Apply our entrepreneurial culture, which fosters innovation and creativity, to continue our successful exploration and development program

We differentiate ourselves from other exploration and production companies through our approach to exploration and development. Our geoscientists and engineers 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 new fields. Culturally, we have an open, team‑oriented work environment that fosters entrepreneurial, 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. This philosophy and approach was successfully utilized offshore Ghana, Mauritania and Senegal, resulting in the discovery of significant new petroleum systems, which 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 accelerate production, deliver early learnings and maximize returns. In certain circumstances, we believe a phased approach can be employed to optimize full‑field development through a better understanding of dynamic reservoir behavior and enable activities to be performed in a parallel rather than a sequential manner. A phased approach also facilitates refinement of the 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 and returns. 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. 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 sequentially, before first production is achieved. This approach can considerably lengthen the time from discovery to first production.

For example, post‑discovery in 2007, first oil production from the Jubilee Field commenced in November 2010. This development timeline from discovery to first oil was significantly less than the seven to ten year industry average and set a record for a deepwater development of this size and scale at this water depth in West Africa. This condensed timeline reflects the lessons learned by our experienced team while leading other large scale deepwater developments.

Additionally, we look to partner with high quality, industry partners with world‑class development capabilities early in our exploration projects. This strategy is designed to ensure that upon successful exploration and appraisal activities, the project can benefit from development and production operations expertise provided by these partners, as we have done with BP plc (“BP”) in Morocco and Chevron Corporation (“Chevron”) in Suriname.

Identify, access and explore emerging regions and hydrocarbon plays

Our management and exploration teams have demonstrated an ability to identify regions and hydrocarbon plays that yield multiple large commercial discoveries. We focus on frontier and emerging areas that have been underexplored yet offer attractive commercial terms as a result of first‑mover advantage. We expect to continue to use our systematic and proven geologically‑focused approach in 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 hydrocarbon potential.

This approach and focus, coupled with a first‑mover advantage and our management and technical teams’ discipline in execution, provide a competitive advantage in identifying and accessing new strategic growth opportunities. We expect to continue seeking new opportunities where hydrocarbons have not been discovered or produced in meaningful quantities by leveraging the reputation and relationships of our experienced technical and management teams. This includes our existing areas of interest as well as selectively expanding our reach into other locations.

Farm‑in opportunities may offer a way to participate in 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.

Maintain Financial Discipline

We strive to maintain a conservative financial profile and strong balance sheet with ample liquidity. Typically, we fund exploration activities from a combination of production cash flows or partner carries, and development activities from a combination of production cash flows and debt. As of December 31, 2015, we have approximately $1.8 billion of liquidity available to fund our opportunities. Additionally, we use derivative instruments to partially limit our exposure to fluctuations in oil prices and interest rates. We have an active commodity hedging program where we hedge a portion of our anticipated sales volumes on a two‑to‑three year rolling basis. As of December 31, 2015, we have hedged positions covering 10.9 million barrels of oil from 2016 to 2018, which provide partial downside protection should Dated Brent oil prices remain below our floor prices. We also maintain insurance to partially protect against loss of production revenues from our Jubilee asset.

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 careful consideration given to those attributes that lead to working petroleum systems. The process includes basin modeling to predict oil or gas 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 where available and seismic data. 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 promote and preserve hydrocarbon accumulation. Once an area is high‑graded based on this play/fairway analysis, geophysical analysis based on new 3D seismic is conducted to identify prospective traps of interest.

Alongside the subsurface analysis, Kosmos performs an analysis of country‑specific risks to gain an 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 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 operating revenues are generated from our operations offshore Ghana.

Our Discoveries

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

 

Exploration License Areas(1)

Ghana

The WCTP Block and 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.

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.

The following is a brief discussion of our discoveries to date on our license areas offshore Ghana.

Jubilee Discovery

The Jubilee Field was discovered by Kosmos in 2007, with first oil produced in November 2010. Appraisal activities confirmed that the Jubilee discovery straddled the WCTP and DT Blocks. Pursuant to the terms of the UUOA, the discovery area was unitized for purposes of joint development by the WCTP and DT Block partners. Our current unit interest is 24.1%.

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 Jubilee Field is located approximately 37 miles offshore Ghana in water depths of approximately 3,250 to 5,800 feet, which led to the decision to implement an FPSO based development. The FPSO is designed to provide water and natural gas injection to support reservoir pressure, to process and store oil and to export gas through a pipeline to the mainland. The Jubilee Field is being developed in a phased approach. The Phase 1 development focused on partial development of certain reservoirs in the Jubilee Field. The Kosmos‑led Integrated Project Team (“IPT”) successfully executed the initial 17 well development plan, which included nine producing wells that produced through subsea infrastructure to the “Kwame Nkrumah” FPSO, six water injection wells and two natural gas injection wells. This initial phase provided subsea infrastructure capacity for additional production and injection wells to be drilled in future phases of development.

The Phase 1A development provided further development to the currently producing Jubilee Field reservoirs. The Phase 1A development included the drilling of eight additional wells consisting of five production wells and three water injection wells. Approval was given for an additional well, a gas injector, considered as part of Phase 1A. The Phase 1A Addendum PoD was submitted to the Ministry of Petroleum in June 2015 and deemed approved in July 2015 to enable drilling and completion of two additional wells consisting of one production well and one water injection well.

In November 2015, we signed the Jubilee Field Unit Expansion Agreement with our partners to allow for the development of the Mahogany and Teak discoveries through the Jubilee FPSO and infrastructure. The expansion of the Jubilee Unit becomes effective upon approval of the GJFFDP by Ghana’s Ministry of Petroleum. The GJFFDP was submitted to the government of Ghana in December 2015. The GJFFDP includes further development of the three producing reservoirs and final development of the two remaining reservoirs to maximize ultimate recovery and asset value.

The Government of Ghana completed the construction and connection of a gas pipeline from the Jubilee Field to transport natural gas to the mainland for processing and sale. In November 2014, the transportation of gas produced from the Jubilee Field commenced through the gas pipeline to the onshore gas plant. However, the uptime of the facility during 2016 and in future periods is not known. In the absence of the continuous export of large quantities of natural gas from the Jubilee Field 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. Our inability to continuously export associated natural gas in large quantities from the Jubilee Field could impact our oil production.

In prior years, certain near wellbore productivity issues were identified, impacting several Phase 1 production wells. We have also 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 past oil production. The Jubilee Unit partners identified a means of successfully mitigating the near wellbore productivity issues with ongoing acid stimulation treatments and we are in the process of correcting the mechanical issues experienced in the Jubilee Field.

Oil production from the Jubilee Field averaged approximately 102,500 barrels (gross) of oil per day during 2015.  

Following a February 2016 inspection of the turret area of the FPSO, by SOFEC, Inc. (“SOFEC”), the original turret manufacturer, a potential issue was identified with the turret bearing. As a precautionary measure, additional operating procedures to monitor the turret bearing and reduce the degree of rotation of the vessel are being put in place.

SOFEC will now undertake further offshore examinations and Tullow will work with SOFEC to determine what further measures will be required. Oil production and gas export is continuing as normal.

Deepwater Tano Block Discoveries

The Tweneboa, Enyenra and Ntomme fields are located in the western and central portions of the DT Block, approximately 30 miles offshore Ghana in water depths of approximately 3,300 to 5,700 feet. In November 2012, we submitted a declaration of commerciality and PoD over the TEN discoveries. In May 2013, the government of Ghana approved the TEN PoD. The discoveries are being jointly developed with shared infrastructure and a single FPSO.

The TEN fields consist of multiple stratigraphic traps with reservoir intervals consisting of a series of stacked Upper Cretaceous Turonian‑aged, deepwater fan lobes and channel deposits. Fluid samples recovered from the fields indicate an oil gravity of approximately 31‑35 degrees API and a natural gas condensate gravity of between 41 and 48 degrees API.

The TEN development is being developed in a phased manner. The plan of development for TEN was designed to include an expandable subsea system that would provide for multiple phases. Phase 1 of the TEN development includes the drilling and completion of up to 17 wells, 11 of which have been drilled and are being completed. Seven additional development wells are expected to be drilled during Phase 2. The remaining Phase 1 and Phase 2 wells are a combination of production wells and water or gas injection wells needed to maximize recovery. The remainder of Phase 1 and all Phase 2 drilling is dependent on the International Tribunal for the Law of the Sea (the “ITLOS”) ruling expected by late 2017.

The TEN development is on schedule and expected to deliver first oil in the third quarter of 2016 and is expected to increase towards the FPSO capacity of 80,000 barrels (gross) per day as the phased development progresses. Future development of gas resources at the TEN development is anticipated following the commencement of oil production.

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 Petroleum within six months of the declaration of commerciality.

West Cape Three Points Block Discoveries

Mahogany is located within the WCTP Block, southeast of the Jubilee Field. The field is approximately 37 miles offshore Ghana in water depths of approximately 4,100 to 5,900 feet. 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 Teak discovery is located in the western portion of the WCTP Block, northeast of the Jubilee Field. The field is approximately 31 miles offshore Ghana in water depths of approximately 650 to 3,600 feet. We believe the field is a structural‑stratigraphic trap with an element of four‑way closure.

The Akasa discovery is located in the western portion of the WCTP Block approximately 31 miles offshore Ghana in water depths of approximately 3,200 to 5,050 feet. 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.

The GJFFDP incorporating the Mahogany and Teak discoveries was submitted to the Ghanaian Ministry of Petroleum in December 2015. While we are currently in discussions with the government of Ghana, we can give no assurance that approval by the Ministry of Petroleum will be forthcoming in a timely manner or at all. We signed the Jubilee Field Unit Expansion Agreement with our partners in November 2015. This allows for the Mahogany and Teak discoveries to be developed contemporaneously with the Jubilee Field. Upon approval of the GJFFDP by the Ministry of Petroleum, the Jubilee Unit will be expanded to include the Mahogany and Teak discoveries and revenues and expenses associated with these discoveries will be at the Jubilee Unit interests. We are currently in discussions with the government of Ghana regarding additional technical studies and evaluation that we want to conduct before we are able to make a determination regarding commerciality of the Akasa discovery. Additionally, the WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow after approval of the GJFFDP by Ghana’s Ministry of Petroleum.

Mauritania

We are operator of three Offshore Blocks, C8, C12 and C13, which are located on the western margin of the Mauritania Salt Basin. Our blocks both include and are adjacent to proven petroleum systems, with our primary targets being Cretaceous sediments in structural and stratigraphic traps. We believe that the Triassic salt basin formed at the onset of rifting and contains Jurassic, Cretaceous and Tertiary passive margin sequences of limestones, sandstone and shales. Interpretation of available geologic and geophysical data has identified Cretaceous basin floor channels and fans in trapping geometries outboard of the Salt Basin. Cretaceous source rocks penetrated by wells and typed to oils in the Mauritania Salt Basin are the same age as those which charge other oil and gas fields in the Late Cretaceous of West Africa.

Our acreage is located outboard of the Chinguetti Field and range in water depth from 4,900 to 9,800 feet. These blocks cover an aggregate area of approximately 6.6 million acres. We have obtained approximately 6,000 line-kilometers of 2D seismic data and 10,300 square kilometers of 3D seismic data covering portions of our blocks in Mauritania. Based on these 2D and 3D seismic programs, we have identified numerous prospects in our blocks and we continue to integrate the results of our successful drilling program in Mauritania to further evaluate our reservoir model and delineate prospectivity.

The following is a brief discussion of our discoveries to date in Block C8 offshore Mauritania.

Block C8 Discoveries

The Ahmeyim discovery (formerly named Tortue) is located in Block C8 offshore Mauritania. The discovery is a significant, play-opening gas discovery for the outboard Cretaceous petroleum system. Based on analysis of drilling results and logging data, the well intersected approximately 117 meters (383 feet) of net hydrocarbon pay. A single gas pool was encountered in the Lower Cenomanian objective, which is comprised of three reservoirs totaling 88 meters (288 feet) in thickness over a gross hydrocarbon interval of 160 meters (528 feet). A fourth reservoir totaling 19 meters (62 feet) was penetrated within the Upper Cenomanian target over a gross hydrocarbon interval of 150 meters (492 feet). The exploration well also intersected an additional 10 meters (32 feet) of net hydrocarbon pay in the lower Albian section, which is interpreted to be gas. The well was drilled to a total depth of 5,107 meters. The Ahmeyim discovery extends across the Mauritania border into our Saint Louis Offshore Profond block offshore Senegal. In January 2016, we drilled the Guembeul-1 well in Senegal, which confirmed the extension of the Ahmeyim discovery into Senegal. We are currently drilling the Ahmeyim-2 well as part of the appraisal program in Mauritania to further delineate the Ahmeyim discovery.

The Marsouin discovery, located in Block C8 offshore Mauritania, is a significant, play-extending gas discovery, building on our successful exploration program in the outboard Cretaceous petroleum system offshore Mauritania. The Marsouin-1 well is located approximately 60 kilometers north of the Ahmeyim discovery and was drilled to a total depth of 5,153 meters in nearly 2,400 meters of water. Based on analysis of drilling results and logging data, Marsouin-1 encountered at least 70 meters (230 feet) of net gas pay in Upper and Lower Cenomanian intervals comprised of excellent quality reservoir sands. An appraisal program is currently being planned to delineate the Marsouin discovery.

Senegal

We are the operator of the Cayar Offshore Profond and Saint Louis Offshore Profond Blocks offshore Senegal. The blocks are located in the Senegal River Mid‑Cretaceous deep water system, which is an extention of a working petroleum system in the Mauritania Salt Basin. We believe the area has multiple Lower Cretaceous source rocks with Albo‑Cenomanian reservoir sands. We obtained approximately 7,000 square kilometers of 3D seismic data over the central and eastern portions of the Cayar Offshore Profond and Saint Louis Offshore Profond blocks in January 2015. The results of these 3D seismic programs provided sufficient encouragement to begin acquiring additional seismic data in November 2015 in the western portions of both blocks to fully evaluate the prospectivity.  This survey is expected to be completed in February 2016. We have identified numerous prospects in our blocks and we continue to integrate the results of our successful drilling program in Mauritania and Senegal to further evaluate our reservoir model and delineate prospectivity. 

The following is a brief discussion of our discovery in the Saint Louis Offshore Profond Block offshore Senegal.

Saint Louis Offshore Profond Discoveries

The Guembeul-1 exploration well, located in the northern part of the Saint Louis Offshore Profond license area in Senegal, has made a significant gas discovery. The Guembeul-1 exploration well is located approximately five kilometers south of the Tortue-1 exploration well in Mauritania in approximately 2,700 meters of water and was drilled to a total depth of 5,245 meters. The well encountered 101 meters (331 feet) of net gas pay in two excellent quality reservoirs, including 56 meters (184 feet) in the Lower Cenomanian and 45 meters (148 feet) in the underlying Albian, with no water encountered. Importantly, the Guembeul-1 exploration well has demonstrated reservoir continuity as well as static pressure communication with the Tortue-1 exploration well in the Lower Cenomanian.

Suriname

We are the operator for petroleum contracts covering Block 42 and Block 45 offshore Suriname, which are located within the Guyana‑Suriname Basin, along the Atlantic transform margin of northern South America. Suriname lies between Guyana and French Guyana. The Guyana-Suriname 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. The Suriname basin is considered similar to the working petroleum systems of the West African transform margin. The emerging petroleum system in Suriname has been proven by the presence of onshore producing fields and nearby discoveries offshore Guyana.

Suriname Block 42 and Block 45 are positioned centrally in the Suriname-Guyana Basin, and located to the southeast of the recent play opening Liza-1 oil discovery. Likewise, the blocks are also positioned to the northwest of the French Guyana Basins’ Zaedysus oil discovery.

We believe that there are several independent play types of importance to our operated blocks. Of note are the listric faulted structural stratigraphic play of the lower Cretaceous and the stratigraphically trapped Upper Cretaceous plays similar to those discovered offshore West Africa in the Ghanaian Jubilee Field. The recent oil discovery in Guyana (Liza-1) in the same geologic basin provides a positive point of calibration for the Upper Cretaceous stratigraphic play. 

Target reservoirs in our blocks are similar Upper and Middle Cretaceous age basin floor fans and mid‑slope channel sands. Seismic evidence suggests thick Late Cretaceous and Tertiary reservoir systems are present in the deep water area demonstrated by Liza-1.

The Tambaredjo and Calcutta Fields onshore Suriname as well as the Liza-1 well discovery offshore Guyana demonstrate that a working petroleum system exists, and geological and geochemical studies suggest the hydrocarbons in these fields were generated from 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.

During 2012, we completed a 3D seismic data acquisition program which covered approximately 3,900 square kilometers over 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 the seismic data was completed during 2014.

In December 2015, we received an extension of Phase 1 of the Exploration Period for Block 42 offshore Suriname which now expires in September 2018. We have compiled an initial inventory of prospects on the license areas in Suriname and will continue to refine and assess the prospectivity of these areas during 2016.

Morocco (including Western Sahara)

Our petroleum contracts in Morocco 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.

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. 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.

During 2014, we conducted a new 3D seismic survey of approximately 5,100 square kilometers over the Cap Boujdour Offshore Block. The processing of this seismic data was completed in 2015.

Drilling of the CB-1 exploration well on the Cap Boujdour Offshore Block was completed in March 2015. The well penetrated approximately 14 meters of net gas and condensate pay in clastic reservoirs over a gross hydrocarbon bearing interval of approximately 500 meters. The discovery was sub-commercial, and the well was plugged and abandoned. However, the well demonstrated a working petroleum system including the presence of a hydrocarbon charge. The results are being integrated with the ongoing geological evaluation to determine future exploration activity.

Agadir Basin

The Foum Assaka Offshore, Essaouira Offshore and Tarhazoute Offshore Blocks 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.

We 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 conducted a 3D seismic data acquisition program of approximately 4,300 square kilometers over the Tarhazoute Offshore and Essaouira Offshore Blocks. The processing of this seismic data was completed in late 2015.

During 2014, we drilled the FA‑1 exploration well in the Foum Assaka Offshore block. The well encountered oil and gas shows while drilling and in sidewall cores suggesting the presence of a working petroleum system; however, it failed to encounter commercial reservoirs and was plugged and abandoned.

We are currently assessing prospectivity on our Agadir Basin Blocks offshore Morocco and plan to continue processing and interpreting seismic information to assess the prospectivity of these license areas.

Portugal

In March 2015, we closed a farm‑in agreement to acquire a non‑operated interest in the Camarao, Ameijoa, Mexilhao and Ostra Blocks offshore Portugal. Offshore Atlantic Portugal has been identified as a potentially attractive Central Atlantic margin area with Jurassic source rocks and Lower Cretaceous reservoirs in combination traps. This overlooked and underexplored area has a number of wells showing good evidence for working charge from oil shows and drill stem tests in Late Jurassic and Early Cretaceous sandstones and limestones. These blocks cover an area of approximately 3.0 million acres in water depths ranging from approximately 200 to 3,200 meters.

During 2015, we conducted a 3D seismic survey of approximately 3,200 square kilometers over the Camarao Block. The processing of this seismic data is expected to be completed in 2016. We are integrating the results from the 3D seismic survey into our geologic model to further assess prospectivity on the blocks.

Sao Tome and Principe

During the fourth quarter of 2015 and in January 2016, Kosmos acquired acreage in Blocks 5, 6 and 11 offshore Sao Tome and Principe in the Gulf of Guinea. We are the operator of Block 11, Equator Exploration Limited (“Equator”), an affiliate of Oando Energy Resources, is the operator of Block 5 and Galp Energia Sao Tome E Principe, Unipessoal, LDA (“Galp”), a wholly owned subsidiary of Petrogal, S.A., is the operator of Block 6. These blocks cover an area of approximately 4.2 million acres in water depth ranging from 2,250 to 3,000 meters and provide an opportunity

to pursue the core Cretaceous theme that was successful for us in Ghana. Block 5 is subject to certain governmental approvals and processes required to be completed before this acquisition is effective.

Our blocks are adjacent to a proven and prolific petroleum system in Equatorial Guinea and northern Gabon comprising Early Cretaceous post-rift source rocks and Late Cretaceous reservoirs and provide an extension of this basin.

We believe that the southern extent of the West African transform margin in Sao Tome and Principe comprises a series of Albian pull-apart basins formed during the separation of Africa from South America and provides the necessary conditions for the generation, migration and trapping of hydrocarbons. Early in the basin history, restricted marine conditions prevailed allowing rich source rocks to be deposited. Large sandstone depo-centers were developed at the structural junctions of rift and shear fault trends resulting in the deposition of deep-water slope channels and basin floor fans draping over and around anticlinal highs adjacent to fracture zones. These constitute the main play in the acreage.

We have approximately 1,250 line kilometers of 2D seismic covering portions of our blocks and have identified numerous leads in our Sao Tome and Principe acreage. We intend to further delineate this prospectivity with a seismic acquisition program which will facilitate a detailed geologic evaluation.

Our Reserves

The following table sets forth summary information about our estimated proved reserves as of December 31, 2015. 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, 2015 and 2014 were associated with our Jubilee Field and the TEN development in Ghana. Our estimated proved reserves as of December 31, 2013 were associated with our Jubilee Field in Ghana.

Summary of Oil and Gas Reserves

Changes for the year ended December 31, 2015, include an increase of 11.8 MMBbl of net proved reserves related to Jubilee field performance and in‑fill drilling results, which were partially offset by negative revisions to the TEN development of 2.1 MMBbl due to lower oil prices and by 8.6 MMBbl of net Jubilee production during 2015. During the year ended December 31, 2015, we incurred $80.6 million of capital expenditures related to the Jubilee Field Phase 1A and 1A addendum developments, which consisted of drilling and completing two wells, resulting in the conversion of approximately 3 MMBbl of net proved undeveloped reserves at December 31, 2014 to proved developed reserves as of December 31, 2015.

Changes for the year ended December 31, 2014, include an increase of 27 MMBbl of net proved reserves related to the initial recognition of reserves associated with the TEN development. Jubilee net proved oil reserves increased 11 MMBbl as a result of field performance and in‑fill drilling results, which was partially offset by 8.5 MMBbl of net Jubilee production during 2014. During the year ended December 31, 2014, we incurred $82.8 million of capital expenditures related to the Jubilee Field Phase 1A development, which resulted in the conversion of approximately 6 MMBbl of net proved undeveloped reserves at December 31, 2013 to proved developed reserves as of December 31, 2014. This conversion of proved undeveloped reserves to proved developed reserves was due to the drilling of the remaining Jubilee Field Phase 1A development wells.

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 net production during 2013. During 2013, approximately 1 MMBbl of proved undeveloped reserves at December 31, 2012 were 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.

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, 2015. All estimated future net revenues are attributable to projected production from the Jubilee Field and the TEN development in Ghana. If we are unable to export associated natural gas in large quantities from the Jubilee Field and TEN development then production could be limited and the future net revenues discussed herein will be adversely affected.

Estimated proved reserves

Unless otherwise specifically identified in this report, the summary data with respect to our estimated net proved reserves for the years ended December 31, 2015 and 2014 has been prepared by Ryder Scott Company, L.P. (“RSC”), our independent reserve engineering firm, and for the year ended December 31, 2013 was prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineering firm for such years, 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.

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, 2015 are based on costs in effect at December 31, 2015 and the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the year ended December 31, 2015, 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 prices and costs will remain constant.

Independent petroleum engineers

Ryder Scott Company, L.P.

RSC, our independent reserve engineers for the years ended December 31, 2015 and 2014, was established in 1937. Over the past 75 years, RSC has provided services to the worldwide petroleum industry that include the issuance

of reserves reports and audits, appraisal of oil and gas properties including fair market value determination, reservoir simulation studies, enhanced recovery services, expert witness testimony, and management advisory services. RSC professionals subscribe to a code of professional conduct and RSC is a Registered Engineering Firm in the State of Texas.

For the years ended December 31, 2015 and 2014, we engaged RSC 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, 2015 and 2014 and related future net revenues and PV‑10 at December 31, 2015 and 2014 are taken from reports prepared by RSC, in accordance with petroleum engineering and evaluation principles which RSC believes are commonly used in the industry and definitions and current regulations established by the SEC. The December 31, 2015 reserve report was completed on January 21, 2016, and a copy is included as an exhibit to this report.

In connection with the preparation of the December 31, 2015 and 2014 reserves report, RSC prepared its own estimates of our proved reserves. In the process of the reserves evaluation, RSC 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 RSC which brought into question the validity or sufficiency of any such information or data, RSC 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. RSC 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. RSC issued a report on our proved reserves at December 31, 2015, based upon its evaluation. RSC’s primary economic assumptions in estimates included an ability to sell Jubilee Field oil and TEN development oil at a price of $53.72 and $54.13, respectively, and certain levels of future capital expenditures. The assumptions, data, methods and precedents were appropriate for the purpose served by these reports, and RSC used all methods and procedures as it considered necessary under the circumstances to prepare the report.

Netherland, Sewell & Associates, Inc.  NSAI 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 year ended December 31, 2013, 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.

In connection with the preparation of the December 31, 2013 reserves report, 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.

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, RSC and 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 production and development team, we maintain an internal staff of petroleum engineering and geoscience professionals with significant international experience that contribute to our internal reserve and resource estimates. This team works closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of data furnished in their reserve and resource estimation process. Our Production and Development team is responsible for overseeing the preparation of our reserves estimates and 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 minimum of Bachelor of Science degree in petroleum engineering or geology.

The RSC technical person primarily responsible for preparing the estimates set forth in the RSC reserves report incorporated herein is Mr. Guadalupe Ramirez. Mr. Ramirez has been practicing consulting petroleum engineering at RSC since 1981. Mr. Ramirez is a Licensed Professional Engineer in the State of Texas (No. 48318) and has over 35 years of practical experience in petroleum engineering. He graduated from Texas A&M University in 1976 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Ramirez meets or exceeds 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 and is 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 provides oversight on the processes utilized in the development of our internal reserve and resource estimates on an annual basis. In addition, our Production and Development 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 management review reserve and resource estimates on an annual basis.

Gross and Net Undeveloped and Developed Acreage

The following table sets forth certain information regarding the developed and undeveloped portions of our license areas as of December 31, 2015 for the countries in which we currently operate.

Productive Wells

Productive wells consist of producing wells and wells capable of production, including wells awaiting connections. For wells that produce both oil and gas, the well is classified as an oil well. The following table sets forth the number of productive oil and gas wells in which we held an interest at December 31, 2015:

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, 2015.

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/gas 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.

Significant License Agreements

Below is a discussion concerning the petroleum contracts 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 petroleum contract 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 Ghana Limited, a subsidiary