PART I

appraisal and development of our other Ghanaian discoveries. In Mauritania and Senegal, we expect to fully appraise and develop our current Greater Tortue discovery with the objective of making a final investment decision during 2018 and producing first gas as soon as 2021, as well as continue to test our inventory of oil and gas prospects. We also have a large inventory of leads and prospects in the remainder of our exploration portfolio which we plan to continue to mature. We plan to test the prospectivity of high impact opportunities in the coming years along the Atlantic Margins.

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 the Jubilee Field, including incorporating our Mahogany and Teak discoveries into the Greater Jubilee Full Field Development Plan (“GJFFDP”) and by increasing production at TEN through further development after delivering first oil in August 2016 through a second, dedicated FPSO. In the medium-term, growth could also be realized through the development of all or a portion of our new discoveries in Mauritania and Senegal.

Focus on optimally developing our discoveries to initial production

Our development focus is 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, detailed 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.

Successfully open and develop our offshore exploration plays

We believe the prospects and leads offshore Mauritania, Senegal, Sao Tome and Principe, Suriname, Morocco and Western Sahara provide favorable opportunities to create substantial value through exploration drilling. Starting in the second quarter of 2017, we plan to resume our exploration drilling to test this potential in Mauritania and Senegal and in other areas starting in 2018. 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.

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 have the potential to 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 reduced competition and 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 focus on poorly understood, under‑explored or otherwise overlooked hydrocarbon basins enables us to unlock significant hydrocarbon potential and create substantial value for shareholders.

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.

In addition to ideas developed organically, 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.

Kosmos Exploration Approach

Kosmos’ exploration philosophy is deeply rooted in a fundamental, geologically‑based approach geared toward the identification of poorly understood, 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 suggest 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 accumulations. 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 manage exploration risks and 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.

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

Our geoscientists and engineers are critical to the success of our business strategy and 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 create and 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.

Build the right strategic partnerships with complementary capabilities

We look to partner with high quality, industry players with world‑class complementary capabilities early in our exploration projects. This strategy is designed to ensure that upon successful exploration and appraisal activities, the project can benefit from specific expertise provided by these partners, including exploration, development, production and above-ground capabilities. We have proven we can execute this with BP in Mauritania and Senegal, and Chevron Corporation (“Chevron”) and Hess Corporation (“Hess”) in Suriname and Galp Energia Sao Tome E Principe, Unipessoal, LDA

(“Galp”) in Sao Tome and Principe. In addition, bringing in the right strategic partners early in our projects, typically comes with a financial carry on future expenditures, allowing us to reduce our cost basis and increase return on investment.

Maintain Financial Discipline

We strive to maintain a conservative financial profile and strong balance sheet with ample liquidity. Typically, we fund exploration and development activities from a combination of operating cash flows, debt or partner carries. As of December 31, 2016, we have approximately $1.2 billion of liquidity available to fund our opportunities. In the fourth quarter of 2016, with growing cash flow from our Ghana assets and reduced capital expenditures as the TEN fields came into production, Kosmos generated positive cash flow from operations which is expected to continue into 2017.

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, 2016, we have hedged positions covering 9.9 million barrels of oil in 2017 and 2018 oil production, 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 and TEN assets.

Operations by Geographic Area

We currently have operations in Africa and South America. Currently, all operating revenues are generated from our operations offshore Ghana.

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 Field

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 plan 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 Energy 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 Energy. The GJFFDP was submitted to the government of Ghana in December 2015 and is expected to be resubmitted in 2017 to address comments received from the Ministry of Energy. 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 2017 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 reinject or flare such natural gas. 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. The Jubilee Unit partners identified a means of successfully mitigating the near wellbore productivity issues with ongoing acid stimulation treatments. 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. We are in the process of correcting mechanical issues experienced in the Jubilee Field.

In February 2016, the Jubilee Field operator identified an issue with the turret bearing of the FPSO Kwame Nkrumah. This necessitated the FPSO to be shut down for an extended period beginning in March with production resuming in early May. This resulted in the need to implement new operating and offloading procedures, including the use of tug boats for heading control and a dynamically positioned (“DP”) shuttle tanker and storage vessel for offloading.

These new operating procedures were successfully implemented in April 2016 and are working effectively as evidenced by the fact that 81 parcels have been offloaded from the FPSO since implementation through December 31, 2016. Oil production from the Jubilee Field averaged approximately 73,700 barrels (gross) of oil per day during 2016.

Kosmos and its partners have determined the preferred long-term solution to the turret bearing issue is to convert the FPSO to a permanently spread moored facility, with offloading through a new deepwater Catenary Anchor Leg Mooring (“CALM”) buoy. The partners are now working with the Government of Ghana to amend the field operating philosophy for this field remediation solution. The Jubilee turret remediation work is progressing as planned and the FPSO spread-mooring on its current heading is expected to be completed by March 2017. This will allow the tug boats previously required to hold the vessel on a fixed heading to be removed, significantly reducing the complexity of the current operation. The next phase of the remediation work involves modifications to the turret for long-term spread-moored operations. At present, the partnership is evaluating options to select the optimal long-term orientation and to determine if a rotation of the FPSO is necessary. This evaluation is ongoing amongst the partnership and the Government of Ghana, and final decisions and approvals are expected in the first half of 2017. A facility shutdown of up to 12 weeks may be required during 2017. However, significant efforts are ongoing within the partnership to reduce the duration of the shutdown.

A deepwater CALM buoy, anticipated to be installed in 2018, is intended to restore full offloading functionality and remove the need for the DP shuttle and storage tankers and associated operating costs. Market inquiries are currently ongoing to estimate the cost and schedule for the fabrication and installation of this buoy. This phase of work also requires approval of both the Government of Ghana and the Jubilee Unit partners.

The financial impact of lower Jubilee production as well as the additional expenditures associated with the damage to the turret bearing is being mitigated through a combination of the comprehensive Hull and Machinery insurance (“H&M”), procured by the operator, Tullow, on behalf of the Jubilee Unit partners, and the corporate Loss of Production Income (“LOPI”) insurance procured by Kosmos. Both LOPI and H&M insurance coverages have been confirmed by our insurers and payments are being received. Our LOPI coverage for this incident ends in May 2017. 

TEN Fields

The Tweneboa, Enyenra and Ntomme fields (“TEN”) 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.

The TEN fields are 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 fields includes the drilling and completion of up to 17 wells, 11 of which have been 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. See “Item 1A. Risk Factors—A maritime boundary demarcation between Côte D’Ivoire and Ghana may affect a portion of our license areas offshore Ghana.” for additional information.

Following first oil from the TEN fields in August 2016, oil production and water injection systems were commissioned and are now operational and gas compression and injection commissioning is ongoing. In early January 2017, the capacity of the FPSO was successfully tested at an average rate of 80,000 Bopd during a short-term flow test. Future development of non-associated gas resources at the TEN fields is anticipated before August 2018. However, due to certain issues with managing pressures in the Enyenra reservoir and because no new wells can be drilled until after the previously disclosed ITLOS ruling expected later in 2017, the operator has elected to manage the existing wells in a prudent manner to optimize long-term recovery over the lifetime of the field. Work continues among the project partners to consider ways to increase production. This reservoir management is not expected to negatively impact the ultimate field recovery. The TEN fields are expected to increase towards FPSO capacity of 80,000 Bopd once development progresses.

The construction and connection of a gas pipeline between the Jubilee and TEN fields to transport natural gas to the mainland for processing and sale is expected to be completed in the first quarter of 2017. However, the uptime of the gas processing facility during 2017 and in future periods is not known. Our inability to continuously export associated natural gas in large quantities from the TEN fields could impact our oil production.

Other Ghana 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 Energy 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 Energy 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 the Mahogany and Teak discoveries to be developed contemporaneously with the Jubilee Field. Upon approval of the GJFFDP by the Ministry of Energy, 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 Energy.

The Wawa discovery is located within the DT Block, north of the TEN fields. The Wawa‑1 exploration well intersected oil and gas‑condensate in a Turonian‑aged turbidite channel system. In April 2016, the Ghana Ministry of Energy approved our request to enlarge the TEN development and production area subject to continued subsurface and development concept evaluation, along with the requirement to integrate the Wawa Discovery into the TEN PoD.

Mauritania

Kosmos holds a 28% participating interest and BP (the operator) holds a 62% participating interest in four offshore blocks, C6, C8, C12 and C13, which are located on the western margin of the Mauritania Salt Basin. These blocks are located in a proven petroleum system, with our primary targets being Cretaceous sands 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 slope channels and basin floor fans in trapping geometries outboard of the Salt Basin as the key exploration objective. Multiple Cretaceous source rocks penetrated by wells and typed to oils and gases in the Mauritania Salt Basin are the same age as those which charge other oil and gas fields in West Africa.

A portion of this acreage is located outboard of the Chinguetti Field and ranges in water depth from 330 to 9,800 feet. These blocks cover an aggregate area of approximately 6.0 million acres. We have acquired approximately 6,300 line-kilometers of 2D seismic data and 15,800 square kilometers of 3D seismic data covering portions of our blocks in Mauritania. Based on these 2D and 3D seismic programs, we have drilled two successful exploration wells and an appraisal well, and have identified numerous additional prospects in our blocks. We continue to integrate the results of our successful drilling program in Mauritania to identify and mature primary targets for drilling. We anticipate drilling two exploration wells in Mauritania during our four well program that commences in the second quarter of 2017.

Senegal

Kosmos BP Senegal Limited, a controlled affiliate of Kosmos (owned 50.01% by Kosmos and 49.99% by BP) is the operator of the Cayar Offshore Profond and Saint Louis Offshore Profond Blocks offshore Senegal. The blocks are located in the Senegal River Cretaceous petroleum system and range in water depth from 980 to 10,200 feet. The area is an extension of the working petroleum system in the Mauritania Salt Basin. We believe the area has multiple Cretaceous source rocks with Albo‑Cenomanian reservoir sands providing exploration targets. We acquired 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. In February 2016, we completed a 4,500 square kilometer survey over the western portions of both blocks to fully evaluate the prospectivity. We have identified numerous prospects in our blocks and we continue to mature these for drilling. We anticipate drilling two exploration wells in Senegal during our four well program that commences in the second quarter of 2017.

The following is a brief discussion of our discoveries to date offshore Mauritania and Senegal.

Greater Tortue Discovery

The Ahmeyim and Guembeul discoveries (“Greater Tortue”) are significant, play-opening gas discoveries for the outboard Cretaceous petroleum system and are located approximately 75 miles offshore Mauritania and Senegal. The Greater Tortue discovery straddles Block C8 offshore Mauritania and Saint Louis Offshore Profond offshore Senegal.

We have now drilled three wells within the Greater Tortue discovery. The wells penetrated multiple excellent quality gas reservoirs, including the Lower Cenomanian, Upper Cenomanian and underlying Albian. The wells successfully delineated the Ahmeyim and Guembeul gas discoveries and demonstrated reservoir continuity, as well as static pressure communication between the three wells drilled within the Lower Cenomanian reservoir. The discovery ranges in water depths from 8,850 feet to 9,200 feet, with total depths drilled ranging from 16,700 feet to 17,200 feet.

The Tortue-1 discovery well, located in Block C8 offshore Mauritania, 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 Guembeul-1 discovery well, located in the northern part of the Saint Louis Offshore Profond area in Senegal, is located approximately three miles south of the Tortue-1 exploration well in Mauritania. 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.

The Ahmeyim-2 appraisal well is located in Block C8 offshore Mauritania, approximately three miles northwest, and 200 meters down-dip of the basin-opening Tortue-1 discovery. The well confirmed significant thickening of the gross reservoir sequences down-dip. The Ahmeyim-2 well encountered 78 meters (256 feet) of net gas pay in two excellent quality reservoirs, including 46 meters (151 feet) in the Lower Cenomanian and 32 meters (105 feet) in the underlying Albian.

Other Mauritania and Senegal Discoveries

The BirAllah discovery (formally known as Marsouin), 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 37 miles north of the Ahmeyim discovery and was drilled to a total depth of 16,900 feet in nearly 7,900 feet 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.

The Teranga discovery is located in the Cayar Offshore Profond block approximately 40 miles northwest of Dakar, and was our second exploration well offshore Senegal. The Teranga-1 discovery well is located in nearly 5,900 feet of water and was drilled to a total depth of 15,900 feet. The well encountered 31 meters (102 feet) of net gas pay in good quality reservoir in the Lower Cenomanian objective. Well results confirm that a prolific inboard gas fairway extends approximately 125 miles south from the Marsouin-1 well in Mauritania through the Greater Tortue area on the maritime boundary to the Teranga-1 well in Senegal.

We have now drilled five exploration and appraisal wells offshore Mauritania and Senegal with a 100% success rate, which collectively have discovered a gross potential natural gas resource of approximately 25 trillion cubic feet and as such derisked over 50 trillion cubic feet in the basin.

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 to the north and French Guyana to the south. The Guyana-Suriname Basin was formed 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 most recently by nearby discoveries offshore Guyana, including the Liza-1 well.

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’ Zaedyus oil discovery.

We believe that there are several independent play types of importance on 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 in the Jubilee Field offshore West Africa. 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 in Suriname. 

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 may be 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.

In April 2016, we received an extension of Phase 1 of the Exploration Period for Block 45 offshore Suriname which now expires in September 2018.

In January 2017, we completed a 3D seismic survey of approximately 6,500 square kilometers over Block 42 and Block 45 offshore Suriname. Processing of this data is currently underway. We have compiled an initial inventory of prospects on the license areas in Suriname and will continue to refine and assess the prospectivity, integrating this new 3D seismic data, during 2017 with a view to drilling as early as 2018.

Sao Tome and Principe

During 2015 and 2016, Kosmos acquired acreage in Blocks 5, 6, 11 and 12 offshore Sao Tome and Principe in the Gulf of Guinea. We are the operator of Blocks 5, 11 and 12, and Galp, a wholly owned subsidiary of Petrogal, S.A., is the operator of Block 6. These blocks cover an area of approximately 5.8 million acres in water depth ranging from 7,380 to 9,840 feet and provide an opportunity to pursue the same core Cretaceous theme that was successful for us in Ghana.

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

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 entrapment 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 3D seismic acquisition program of approximately 16,000 square kilometers offshore Sao Tome and Principe, during 2017, which will facilitate a detailed geologic evaluation.

In December 2016, we received approval for a two-year extension of Phase 1 for Block 5 offshore Sao Tome and Principe, which now expires in May 2019. Additionally, during the same month we assigned 20% participating interest to Galp in each of Blocks 5, 11 and 12 offshore Sao Tome and Principe. Based on the terms of the agreement, Galp will pay a proportionate share of Kosmos’ past costs in the form of a partial carry on the 3D seismic survey expected to begin in the first quarter of 2017.

Morocco and Western Sahara

Our petroleum contracts in Morocco and Western Sahara include the Boujdour Maritime block, which is within the Aaiun Basin, and the Essaouira Offshore Block, which is within the Agadir Basin. We are the operator of these petroleum contracts.

Aaiun Basin

In May 2016, Kosmos and Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”) executed a petroleum contract with the Office National des Hydrocarbures et des Mines ("ONHYM"), the national oil company of the Kingdom of Morocco, for the Boujdour Maritime block. The Boujdour Maritime petroleum contract largely replaces the acreage covered by the Cap Boujdour petroleum contract which expired in March 2016. Government approval was received in July 2016, making the contract effective. The first phase requires 5,000 – 7,000 square kilometers of 3D seismic and expires in July 2020. 

The Boujdour Maritime block is located within the Aaiun Basin, along the Atlantic passive margin and covers a high‑graded area. 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 Boujdour Maritime 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.

Kosmos expects to acquire approximately 9,500 square kilometers of 3D seismic in the Boujdour Maritime block, beginning in 2017.  The results of this survey will be integrated with prior surveys and well results to further develop and delineate prospectivity in the basin.

Agadir Basin

The Essaouira Offshore block is 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.

In September 2016, we entered into an agreement by which BP agreed to pay Kosmos $30 million in lieu of fulfilling their obligation to fund an exploration well and assigned its 45% participating interest in the Essaouira Offshore Block back to us, and the Moroccan government issued joint ministerial orders approving the assignment in October 2016, making it effective.   During the same month, we received an extension of the first Extension Period of exploration for the Essaouira Offshore petroleum contract, which now expires in November 2018.  This extension included the modification of the minimum work program to replace an exploration well with acquisition and PSTM processing of 3,000 square-kilometers of 3D seismic and a seabed sampling survey for geochemical and heat flow analysis. The $30 million received from BP in January 2017 will be utilized to fund the modified work program.

The petroleum agreements for Tarhazoute Offshore and Foum Assaka Offshore expired in June 2016 and July 2016, respectively.

Portugal

In January 2017, we provided to our co-venturers a notice of withdrawal from the Ameijoa, Camarao, Mexilhao and Ostra Blocks offshore Portugal.

Our Reserves

The following table sets forth summary information about our estimated proved reserves as of December 31, 2016. 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, 2016, 2015 and 2014 were associated with our Jubilee and the TEN fields in Ghana.

Changes for the year ended December 31, 2016, include an increase of 8.3 MMBbl in TEN related to a revision resulting from additional technical data and analysis, partially offset by 0.9 MMBbl of net TEN production during 2016, and negative revisions to Jubilee of 1.0 MMBbl due to lower oil prices and 6.2 MMBbl of net Jubilee production during 2016. During the year ended December 31, 2016, we had 14 MMBoe of our proved undeveloped reserves from December 31, 2015 convert to proved developed reserves due to the completion of seven wells in the TEN fields, the initiation of TEN production and 2016 revisions, and we incurred $198.5 million of capital expenditures for TEN.

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 fields 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 had a 6 MMBoe reduction in our proved undeveloped reserves from December 31, 2014. The decrease was a result of an approximately 2 MMBoe negative revision associated with our TEN fields, due to shorter economic life as a result of lower oil price. We incurred $80.6 million of capital expenditures related the drilling and completion of two wells pursuant to the Jubilee Field Phase 1A and 1A addendum developments resulting in the conversion of approximately 3 MMBoe of proved undeveloped reserves to proved developed reserves associated with our Jubilee Field.

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 fields. 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 had a 22 MMBoe increase in our proved undeveloped reserves from December 31, 2013. This increase was primarily the result of the initial recognition of 27 MMBoe in proved undeveloped reserves for the TEN fields offset by the conversion of approximately 6 MMBoe from proved undeveloped reserves to proved developed reserves as we incurred $82.8 million of capital expenditures related to the drilling of the remaining Jubilee Field Phase 1A development wells.

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, 2016. All estimated future net revenues are attributable to projected production from the Jubilee and the TEN fields in Ghana. If we are unable to export associated natural gas in large quantities from the Jubilee and TEN fields 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, 2016, 2015 and 2014 has been prepared by Ryder Scott Company, L.P. (“RSC”), 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, 2016 are based on costs in effect at December 31, 2016 and the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the year ended December 31, 2016, 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, 2016, 2015 and 2014, was established in 1937. For over 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, 2016, 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, 2016, 2015 and 2014 and related future net revenues and PV‑10 at December 31, 2016, 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, 2016 reserve report was completed on January 13, 2017, and a copy is included as an exhibit to this report.

In connection with the preparation of the December 31, 2016, 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, 2016, based upon its evaluation. RSC’s primary economic assumptions in estimates included an ability to sell Jubilee field oil and the TEN fields oil at a price of $42.96 and $42.90, 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.

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 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.

Drilling activity

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