Item 1.  Business

General

Kosmos is a full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable exploration program balanced between proven basin infrastructure-led exploration (Equatorial Guinea and U.S. Gulf of Mexico), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Cote d'Ivoire, Namibia and Sao Tome and Principe). Kosmos is listed on the New York Stock Exchange (“NYSE”) and London Stock Exchange ("LSE") 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 disregarded by others in the industry, the Late Cretaceous play systems in West Africa. In its relatively brief history the Company has successfully opened two new hydrocarbon basins through the discovery of the Jubilee field offshore Ghana in 2007 and the Greater Tortue Ahmeyim development (which includes the Ahmeyim and Guembeul-1 discoveries offshore Mauritania and Senegal in 2015 and 2016, respectively). Jubilee was one of the largest oil discoveries worldwide in 2007 and is considered one of the largest finds offshore West Africa during that decade. First oil production was delivered just 42 months after initial discovery, a record for a deepwater development in this water depth in West Africa. The Ahmeyim discovery was one of the largest natural gas discoveries worldwide in 2015 and is believed to be the largest ever gas discovery offshore West Africa.

Over the last two years, our business strategy has evolved to include production enhancing infill drilling and well work as well as infrastructure-led exploration. This strategic evolution was initially enabled by our acquisition of the Ceiba Field and Okume Complex assets offshore Equatorial Guinea in October 2017 together with access to surrounding exploration licenses, and bolstered by the September 2018 acquisition of Deep Gulf Energy (together with its subsidiaries "DGE"), a deepwater company operating in the U.S. Gulf of Mexico, which further enhanced our production, exploitation and infrastructure-led exploration capabilities.    

Our Business Strategy

As a full-cycle E&P company, our mission is to deliver production and free cash flow from a portfolio rich in opportunities through a disciplined allocation of capital and optimal portfolio management for the benefit of our shareholders.

Our business strategy is designed to accomplish this mission by focusing on three key objectives: (1) maximize the value of our producing assets; (2) progress our discovered resources toward project sanction and into proved reserves, production, and cash flow through efficient appraisal and development; and (3) add new resources through a consistently active low cost exploration program. We are focused on increasing production, cash flows and reserves from our producing assets in Equatorial Guinea, Ghana, and the U.S. Gulf of Mexico. In Mauritania and Senegal, we are progressing our Greater Tortue Ahmeyim development with the objective of reaching first gas in the first half of 2022, as well as advancing our other discoveries towards a final investment decision. We also have a large inventory of leads and prospects in our exploration portfolio along the Atlantic Margins, both infrastructure-led and basin opening opportunities, which we plan to continue to mature for future drilling, providing us access to asymmetric growth potential in the coming years.

Grow cash flow, proved reserves and production through exploitation, development, infrastructure-led exploration and basin opening exploration activities

In the near term, we plan to grow cash flow, proved reserves and production by further exploiting our fields offshore Ghana, U.S. Gulf of Mexico, and Equatorial Guinea. In Ghana, we plan to continue drilling additional development and production wells at both the Jubilee and TEN fields in 2019. In the U.S. Gulf of Mexico we plan to continue infill drilling on existing fields, drilling infrastructure-led exploration targets, and progressing the development of the Nearly Headless Nick discovery via subsea tieback to existing infrastructure. In Equatorial Guinea our activity set is expanding beyond production optimization projects utilizing electrical submersible pumps to include infrastructure-led exploration which, if successful, can be brought online quickly via subsea tieback to existing infrastructure. In addition, we have sanctioned the first phase of the Greater Tortue Ahmeyim development offshore Mauritania and Senegal, which defines the timing and path to first gas. Beyond Greater Tortue Ahmeyim, growth could also be realized through the development of all or a portion of our other discoveries in Mauritania and Senegal. Our basin opening exploration efforts continue to be a significant portion of the portfolio. We believe the prospects and leads offshore Mauritania, Senegal, Sao Tome and Principe, Cote d'Ivoire, Namibia, and Suriname provide favorable opportunities to create

substantial future growth and value through exploration drilling. During 2019, we plan to further test the potential of previous discoveries in Mauritania and Senegal and drill five infrastructure-led prospects in Equatorial Guinea and the U.S. Gulf of Mexico. Given the potential size of these prospects and leads, we believe that exploratory and appraisal success in our operating areas could significantly add to our growth profile.

Focus on optimally developing our discoveries to initial production

Our approach to development is designed to deliver first production on an accelerated timeline, leverage early learnings to improve future outcomes and maximize returns. In certain circumstances, we believe a phased approach can be employed to optimize full‑field development. A phased approach 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 phases 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 phases of production to fund a portion of capital costs for subsequent phases.

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. The Greater Tortue Ahmeyim development is also expected to be developed in an accelerated, phased approach consistent with our business strategy. This is anticipated to result in first gas seven years after initial discovery, which feeds the market at a potentially optimal time as demand is expected to outpace supply.

Kosmos Exploration Approach - A balance of basin opening and infrastructure-led

Kosmos’ exploration philosophy, which is traditionally basin opening based, is deeply rooted in a fundamental, geologic approach geared toward the identification of under‑explored or overlooked petroleum systems. 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: (i) long‑term contract durations to enable the “right” exploration program to be executed, (ii) play type diversity to provide multiple exploration concept options, (iii) prospect dependency to enhance the chance of replicating success, and (iv) sufficiently attractive fiscal terms to maximize the commercial viability of discovered hydrocarbons. This type of exploration provides the portfolio with access to asymmetric growth possibilities.

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 for all new areas and is a key strength of Kosmos.

Our exploration approach has evolved to include infrastructure-led exploration. This shorter-cycle approach, which can typically deliver first production in less than 18 months, is aimed at areas where we have existing production and where there is sufficient infrastructure capacity to enable the development of new discoveries via subsea tieback. Acquisitions of the Ceiba Field and Okume Complex in Equatorial Guinea together with access to surrounding exploration licenses and the DGE assets in the Gulf of Mexico have added to the inventory of infrastructure-led exploration given their attractive acreage positions within proximity of existing infrastructure that has excess capacity available. This opens a new growth area with attractive economics in areas with high margin production that complements the basin opening exploration program. It also allows shared learnings across the portfolio.

Build the right strategic partnerships with complementary capabilities

As a full-cycle E&P company, part of our strategy is to optimize our portfolio at appropriate times for our exploration and development projects. One of the ways to accomplish this is to partner with high-quality industry players with world‑class complementary capabilities. This strategy is designed to ensure that the relative 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 strategy by partnering with supermajors including BP PLC ("BP") and Royal Dutch Shell ("Shell") across our exploration portfolio. In addition, bringing in the right strategic partners early in our projects often comes with a financial carry on future expenditures, allowing us to reduce our costs and increase return on investment.

For example, in 2017 we formed an alliance with a subsidiary of BP. This alliance broadened the relationship that previously covered new venture opportunities in Mauritania, Senegal and The Gambia to create an Atlantic Margin explorer-developer partnership. The alliance combines Kosmos' regional exploration knowledge and capability with BP's deepwater development expertise to execute a selective, basin opening exploration strategy in the Atlantic Margin.

During the fourth quarter of 2018, Kosmos entered into an additional strategic exploration alliance with a subsidiary of Shell to jointly explore in Southern West Africa. Initially, the alliance will focus on Namibia where Kosmos has completed a farm-in to Shell's acreage in PEL 39, and Sao Tome & Principe where we have entered into exclusive negotiations for Shell to take an interest in Kosmos’ acreage in Blocks 5, 6, 11 and 12. As part of the alliance, the two companies will also jointly evaluate opportunities in adjacent geographies. This alliance is consistent with Kosmos’ strategy of partnering with supermajors to leverage complementary skill sets. Shell has deep expertise in carbonate plays, while Kosmos brings significant knowledge of the Cretaceous in West Africa. Furthermore, by working with Shell, Kosmos has a partner with the expertise to efficiently move exploration successes through the development stage.

During the first quarter of 2019, Kosmos expanded its relationship with BP to grow Kosmos’ footprint in the deepwater U.S. Gulf of Mexico. The venture includes the evaluation of 18 jointly owned leases in the Garden Banks area and an opportunity to earn an interest in three additional blocks in other areas of the deepwater U.S. Gulf of Mexico. This transaction will allow both companies to leverage complementary skill sets to execute farm-in projects around infrastructure. Kosmos will be designated operator and plans to commence drilling operations on the first well in 2019.

During the first quarter of 2019, Kosmos executed a farm-in agreement with Chevron covering the right to earn an interest in a strategic block in the deepwater U.S. Gulf of Mexico. This agreement allows Kosmos another opportunity to execute its deepwater U.S. Gulf of Mexico strategy of lower risk prospects with the potential for subsea development near existing midstream infrastructure. Kosmos will be designated operator and plans to commence drilling operations in 2019.

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

Our employees 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, developing and producing new fields and optimizing production from existing 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 ideas that create and maximize value and free cash flow.

Maintain Financial Discipline

Execution of our strategy requires us to maintain a conservative financial approach with a strong balance sheet, ample liquidity, a commitment to low leverage and the ability to maintain significant headroom on our debt covenants. Typically, we fund exploration and development activities from a combination of operating cash flows, debt and partner carries.

As of December 31, 2018 , our net leverage ratio was just slightly over 2.0 times, largely the result of borrowing for the Gulf of Mexico acquisition. Our liquidity, after consideration of the additional RBL Facility commitments which became effective in January 2019, was approximately $0.6 billion available to fund our opportunities. When we do increase our net leverage as we did in 2018 with the U.S. Gulf of Mexico acquisition, we develop a well thought out plan to bring leverage back down.

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 aim to hedge a portion of our anticipated sales volumes on a two‑to‑three year rolling basis, with the goal to protect against the downside price scenario while still retaining partial exposure to the upside. As of December 31, 2018 , we have hedged positions covering 15.6 million barrels of oil production from 2019 through 2020. We also maintain insurance to partially protect against loss of production revenues from our producing assets.

During 2018 , Kosmos generated approximately $260.5 million of cash flow from operations.

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

						Kosmos
						Participating											License
Fields		License				Interest					Operator				Stage		Expiration
Ghana(1)
Jubilee		WCTP/DT		(2)		24.1	%		(2)		Tullow				Production		2034
TEN		DT				17.0	%		(4)		Tullow				Production		2036
U.S. Gulf of Mexico(1)
Barataria		MC 521				22.5	%				Kosmos				Production		(10)
Big Bend		MC 697 / 698 / 742				5.3	%				Fieldwood				Production		(10)
Don Larsen		EB 598				20.0	%				Anadarko				Production		(10)
Gladden		MC 800				20.0	%				W&T				Production		(10)
Kodiak		MC 727 / 771				29.1	%				Kosmos				Production		(10)
Marmalard		MC 255 / 300				11.8	%				LLOG				Production		(10)
Nearly Headless Nick		MC 387				22.0	%				LLOG				Development		(10)
Danny Noonan		EC 381 GB 463 / 506				Various			(5)		Talos				Production		(10)
Odd Job		MC 214 / 215				Various			(6)		Kosmos				Production		(10)
Sargent		GB 339				50.0	%				Kosmos				Production		(10)
SOB II		MC 431				11.8	%				LLOG				Production		(10)
S. Santa Cruz		MC 563				40.5	%				Kosmos				Production		(10)
Tornado		GC 281				35.0	%				Talos				Production		(10)
Mauritania
Greater Tortue Ahmeyim		Block C8		(3)		29.0	%		(7)		BP				Development		2049	(11)
Marsouin		Block C8				28.0	%		(7)		BP				Appraisal		2019	(12)
Senegal
Greater Tortue Ahmeyim		Saint Louis Offshore Profond		(3)		29.0	%		(8)		BP		(8)		Development		2044	(11)
Teranga		Cayar Offshore Profond				30.0	%		(8)		BP		(8)		Appraisal		2021
Yakaar		Cayar Offshore Profond				30.0	%		(8)		BP		(8)		Appraisal		2021
Equatorial Guinea(1)
Ceiba Field and Okume Complex		Block G				40.4	%		(9)		Trident		(9)		Production		2034

______________________________________

These interest percentages are subject to redetermination of the participating interests in the Jubilee Field pursuant to the terms of the Jubilee UUOA. Our paying interest on development activities in the Jubilee Field is 26.9%.

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 following is a brief discussion of our discoveries 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 Jubilee UUOA, the discovery area was unitized for purposes of joint development by the WCTP and DT Block partners.

The Jubilee Field is located approximately 60 kilometers offshore Ghana in water depths of approximately 1,000 to 1,800 meters, 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 initial phase provided subsea infrastructure capacity for additional production and injection wells to be drilled in future phases of development.

The GJFFDP was approved by the Government of Ghana in October 2017. This plan, which is expected to increase proved reserves and extend the field production profile, has been optimized to reduce overall capital expenditures to reflect the current oil price market. In November 2015, we signed the Jubilee Field Unit Expansion Agreement with our partners, which became effective upon approval of the GJFFDP, to allow for the development of the Mahogany and Teak discoveries through the Jubilee FPSO and infrastructure, thus reducing their development cost. As a result of the approval of the GJFFDP by the Ministry of Energy in October 2017, operatorship for the Mahogany and Teak discoveries transferred to Tullow. The WCTP partners transferred operatorship of the remaining portions of the WCTP Block, including the Akasa discovery, to Tullow effective February 1, 2018.

The Government of Ghana completed the construction and connection of a gas pipeline in 2017 from the Jubilee Field to transport natural gas to the mainland for processing and sale. In the absence of 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 February 2016, the Jubilee Field operator identified an issue with the turret bearing of the FPSO Kwame Nkrumah. Kosmos and its partners completed the lifting and locking of the main turret bearing, and the rotation of the vessel to its final heading in the second half of 2018. Permanent spread mooring of the vessel is expected to be completed around mid-year 2019.

The financial impact of lower Jubilee production as well as the additional expenditures associated with the damage to the turret bearing is 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. Our LOPI coverage for this incident ended in May 2017 and the final cash proceeds were received in August 2017. Oil production from the Jubilee Field averaged approximately 78,000 Bopd gross (18,800 Bopd net) during 2018 .

Tweneboa, Enyenra and Ntomme ("TEN")

The TEN fields are located in the western and central portions of the DT Block, approximately 48 kilometers offshore Ghana in water depths of approximately 1,000 to 1,700 meters. In November 2012, we submitted a declaration of commerciality and PoD over the TEN discoveries, and 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 Professor John Evans Atta Mills.

Similar to Jubilee, the TEN fields are being developed in a phased manner. The TEN PoD was designed to include an expandable subsea system that would provide for multiple phases. Phase 1 of the TEN PoD includes the drilling and completion of up to 17 wells, 13 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.

First oil from the TEN fields was produced in August 2016. In January 2017, the capacity of the FPSO was successfully tested at an average rate of 80,000 Bopd during a short-term flow test. In September 2017, International Tribunal of the Sea issued its final decision in the previously disclosed maritime boundary dispute between the Governments of Ghana and Cote d'Ivoire, which allowed drilling to resume in early 2018. These additional wells are expected to increase production towards FPSO capacity. Production from TEN in the year ended December 31, 2018 averaged approximately 64,500 Bopd gross (10,400 Bopd net).

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 was completed in the first quarter of 2017. In December 2017, we signed the TEN Associated-Gas - Gas Sales Agreement ("TAG GSA") and we commenced exporting gas to shore in the fourth quarter of 2018. However, the uptime of the gas processing facility in future periods is unknown. Our inability to continuously export associated natural gas in large quantities from the TEN fields could impact our oil production.

U.S. Gulf of Mexico

In September 2018, as part of the DGE transaction, Kosmos acquired: (i) a portfolio of producing assets that Kosmos can continue to exploit, (ii) infrastructure-led exploration growth assets, and (iii) a high-quality inventory of exploration prospects across the East Breaks, Garden Banks, Green Canyon and Mississippi Canyon areas. Our U.S. Gulf of Mexico assets averaged approximately 23,700 Boepd (net) (~81% oil) from twelve fields from the acquisition date through the end of 2018. We expanded our inventory through the U.S. Gulf of Mexico Lease Sale 251 in which we were awarded seven new deepwater blocks.

The following is a brief discussion of our key producing fields in the U.S. Gulf of Mexico.

 

Odd Job

The Odd Job field is producing through the Delta House FPS, operated by LLOG. The technical team initially identified the Middle Miocene sands at the Odd Job prospect using attribute analysis of a multi-client 3-D survey. These sands are currently producing through the Odd Job 215 #1 well and the Odd Job 215 #2 well. A third well, the Odd Job 214 #2 well, was drilled in 2018 and will be completed in the fourth quarter of 2019. A fourth exploration target in the field is a deeper Middle Miocene sand and is expected to be tested during the third quarter of 2019. The two currently producing wells achieved peak production of approximately 24,000 Boepd (gross), and net production from the acquisition date through the end of 2018 averaged approximately 5,900 Boepd.

Tornado

The Tornado field is producing from two Pliocene wells through the Helix Producer I, a ship-shaped, dynamically-positioned production platform in the deepwater U.S. Gulf of Mexico, which is operated by Talos Energy. In December 2018, a third well was drilled and logged 130 (true vertical thickness) net feet of pay in the same Pliocene sand. Planned production from the third development well is scheduled for the second quarter of 2019. The two currently producing wells achieved peak production of approximately 30,000 Boepd (gross), and net production from the acquisition date through the end of 2018 averaged approximately 6,000 Boepd.

Marmalard

The Marmalard field produces from four wells, each completed in Middle Miocene sands. These wells are flowing through the Delta House FPS, operated by LLOG. The four wells achieved peak production of approximately 41,000 Boepd (gross), and net production from the acquisition date through the end of 2018 averaged approximately 3,000 Boepd.

Kodiak

The Kodiak field is producing from one well which is completed in the Middle Miocene sands. This well is flowing through the Devils Tower Spar platform, which is operated by ENI. A second development well is scheduled for drilling in the fourth quarter of 2020. The initial well achieved peak production of approximately 23,000 Boepd (gross), and net production from the acquisition date through the end of 2018 averaged approximately 4,000 Boepd.

South Santa Cruz / Barataria

The South Santa Cruz field is producing from one well in a Late Miocene sand through the Blind Faith tension-leg platform ("TLP"), which is operated by Chevron. The Barataria field is producing from one well in a different Late Miocene sand through the Blind Faith TLP, via South Santa Cruz. A third target in the field is a deeper Late Miocene sand and is expected to be tested during the second quarter of 2020. The two wells achieved peak production of approximately 15,000 Boepd (gross), and net production from the acquisition date through the end of 2018 averaged approximately 2,500 Boepd.

Mauritania

The C6, C8, C12, C13 and C18 blocks are located on the western margin of the Mauritania Salt Basin offshore Mauritania and range in water depths from 100 to 3,000 meters. These blocks are located in a proven petroleum system, with our primary targets being Cretaceous sands in structural and stratigraphic traps. 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.

These blocks cover an aggregate area of approximately 6.0 million acres (gross). 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 additional prospects in our blocks. We continue to integrate the results of our drilling program in Mauritania.

Senegal

The Senegal Blocks are located in the Senegal River Cretaceous petroleum system and range in water depth from 300 to 3,100 meters. 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 Albian through 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 Senegal Blocks in January 2015. In February 2016, we completed a 4,500 square kilometer survey over the western portions of the Senegal Blocks to fully evaluate the prospectivity. We have drilled two successful exploration wells and an appraisal well, and have identified additional prospects in our blocks.

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

Greater Tortue Ahmeyim Development

The Ahmeyim and Guembeul discoveries (collectively “Greater Tortue Ahmeyim”) are significant, play-opening gas discoveries for the outboard Cretaceous petroleum system and are located approximately 120 kilometers offshore Mauritania and Senegal. The Greater Tortue Ahmeyim development straddles Block C8 offshore Mauritania and Saint Louis Offshore Profond offshore Senegal.

We have drilled three wells within the Greater Tortue Ahmeyim development, Tortue-1, Guembeul-1 and Ahmeyim-2. 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 approximately 2,700 meters to 2,800 meters, with total depths drilled ranging from approximately 5,100 meters to 5,250 meters.

The Tortue-1 discovery well, located in Block C8 offshore Mauritania, intersected approximately 117 meters of net hydrocarbon pay. A single gas pool was encountered in the Lower Cenomanian objective, which is comprised of three reservoirs totaling 88 meters in thickness over a gross hydrocarbon interval of 160 meters. A fourth reservoir totaling 19 meters was penetrated within the Upper Cenomanian target over a gross hydrocarbon interval of 150 meters. The exploration well also intersected an additional 10 meters 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 five kilometers south of the Tortue-1 exploration well in Mauritania. The well encountered 101 meters of net gas pay in two excellent quality reservoirs, including 56 meters in the Lower Cenomanian and 45 meters in the underlying Albian, with no water encountered.

The Ahmeyim-2 appraisal well is located in Block C8 offshore Mauritania, approximately five kilometers 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 of net gas pay in two excellent quality reservoirs, including 46 meters in the Lower Cenomanian and 32 meters in the underlying Albian.

In August 2017, we completed the drill stem test ("DST") of the Tortue-1 well, demonstrating that the Tortue field is a world-class resource and confirming key development parameters including well deliverability, reservoir connectivity, and fluid composition. The Tortue-1 well flowed at a sustained, equipment-constrained rate of approximately 60 MMcfd during the main extended flow period, with minimal pressure drawdown, providing confidence in well designs that are each capable of producing approximately 200 MMcfd. The DST results confirmed a connected volume per well consistent with the current development scheme, which together with the high well rate is expected to result in a low number of development wells compared to equivalent schemes. Initial analysis of fluid samples collected during the test indicate Tortue gas is well suited for liquefaction given low levels of liquids and minimal impurities. Data acquired from the DST was used to further optimize field development and to refine process design parameters critical to the front end engineering and design ("FEED") process.

In December 2018, the partners agreed on a final investment decision for Phase 1 of the Greater Tortue Ahmeyim project. The Greater Tortue Ahmeyim project is designed to produce gas from a deepwater subsea system to a mid-water FPSO and then to a FLNG facility at a nearshore hub located on the Mauritania and Senegal maritime border. The FLNG facility for Phase 1 is designed to produce approximately 2.5 million tons per annum on average. The project will provide LNG for global export, as well as make gas available for domestic use in both Mauritania and Senegal. First gas for the project is expected in the first half of 2022. Following a competitive tender process involving all partners and subject to final documentation, BP Gas Marketing has been selected as the buyer for the LNG offtake for Greater Tortue Ahmeyim Phase 1.

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 60 kilometers north of the Ahmeyim discovery and was drilled to a total depth of 5,150 meters in nearly 2,400 meters of water. Based on analysis of drilling results and logging data, Marsouin-1 encountered at least 70 meters 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 65 kilometers northwest of Dakar, and was our second exploration well offshore Senegal. The Teranga-1 discovery well is located in nearly 1,800 meters of water and was drilled to a total depth of approximately 4,850 meters. The well encountered 31 meters of net gas pay in good quality reservoir in the Lower Cenomanian objective. Well results confirm that a prolific inboard gas fairway extends approximately 200 kilometers south from the Marsouin-1 well in Mauritania through the Greater Tortue Ahmeyim area on the maritime boundary to the Teranga-1 well in Senegal.

The Yakaar discovery is located in the Cayar Offshore Profond block offshore Senegal, approximately 95 kilometers northwest of Dakar in approximately 2,600 meters of water. The Yakaar-1 discovery well was drilled to a total depth of approximately 4,900 meters. The well intersected a gross hydrocarbon column of 120 meters in three pools within the primary Lower Cenomanian objective and encountered 45 meters of net pay. An appraisal well is planned in 2019.

Equatorial Guinea

In October 2017, we entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration period expiring in March

2023. The first exploration period consists of two sub-periods of three and two years, respectively. The first exploration sub-period work program included an approximately 6,000 square kilometer 3D seismic acquisition requirement across the blocks, which was completed in November 2018.

 

In June 2018, we closed a farm-in agreement with a subsidiary of Ophir Energy plc ("Ophir") for Block EG-24, offshore Equatorial Guinea, whereby we acquired a 40% non-operated participating interest. As part of the agreement, we reimbursed a portion of Ophir's previously incurred exploration costs and will fully carry Ophir's share of the costs of a planned 3D seismic program as well as pay a disproportionate share of the well commitment should we enter the second exploration sub-period. The petroleum contract covers approximately 3,500 square kilometers, with a first exploration period of three years from the effective date (March 2018) which can be extended up to four additional years at our election subject to fulfilling specific work obligations. The first exploration period work program includes a 3,000 square kilometer 3D seismic acquisition requirement, which was completed in November 2018. In January 2019, we entered into an agreement to acquire Ophir's remaining interest in and operatorship of the block, subject to customary governmental approvals, which will result in Kosmos owning an 80% interest in Block EG-24. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest for all development and production operations.

In November 2018, we completed a 3D seismic survey of approximately 9,500 square kilometers over blocks EG-21, EG-24, S and W offshore Equatorial Guinea, and approximately 200 square kilometers over Block G. The seismic data will be processed with the objective of high grading prospects for drilling in 2019.

Ceiba Field and Okume Complex - Equity Method Investment

In the fourth quarter of 2017, through a joint venture with an affiliate of Trident, we acquired all of the equity interest of Hess International Petroleum Inc., a subsidiary of Hess Corporation ("Hess"), which holds an  85%  paying interest ( 80.75%  revenue interest) in the Ceiba Field and Okume Complex assets. Under the terms of the agreement, Kosmos and Trident each own  50%  of Hess International Petroleum Inc. Hess International Petroleum Inc. was subsequently renamed Kosmos-Trident International Petroleum Inc. ("KTIPI"). Kosmos is primarily responsible for exploration and subsurface evaluation while Trident is primarily responsible for production operations and optimization. The transaction expands our position in the Gulf of Guinea and provides immediate cash flow through existing production with potential to increase existing production through exploration opportunities with potential low cost tie-backs through the existing infrastructure. The gross acquisition price was  $650 million  effective as of January 1, 2017. After post closing entries Kosmos paid net cash of approximately  $231 million . The transaction was accounted for as an equity method investment. Oil production from the Ceiba Field and Okume Complex averaged approximately 44,000 barrels gross (28,000 barrels net) of oil per day during 2018 .

Effective as of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.375% undivided interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex will be accounted for under the proportionate consolidation method of accounting going forward.

In May 2018, we signed a farm-out agreement with a subsidiary of Trident covering blocks S, W and EG-21 offshore Equatorial Guinea. Under the terms of the agreement, Trident acquired a 40% non-operated participating interest in the blocks and Kosmos remains the operator. In August 2018, we completed the farm-out agreement covering blocks S, W and EG-21 offshore Equatorial Guinea resulting in a $7.7 million gain.

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 west and French Guyana to the east. 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 analogous 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 east 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. 

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 analogous in age to those which have charged numerous fields in offshore West Africa.

In June 2018, the Anapai-1A exploration well was drilled to a total depth of approximately 4,600 meters and was designed to test lower Cretaceous reservoirs in a structural trap on the flank of the basin. The prospect was fully tested, encountering high quality reservoirs in the targeted zones, but did not find hydrocarbons. The well has been plugged and abandoned.

In July 2018, we entered into the second exploration phase in blocks 42 and 45, which now expires in September 2021. The second phase carried a one well commitment per block that has been met for both blocks with the Anapai-1A and Pontoenoe-1 exploration wells.

In October 2018, the Pontoenoe-1 exploration well was drilled to a total depth of approximately 6,200 meters and was designed to test late Cretaceous reservoirs in a structural trap charged from oil mature Albian and Cenomanian-Turonian source kitchens. The prospect was fully tested but did not discover commercial hydrocarbons. High-quality reservoir was encountered, but the primary exploration objective proved to be water bearing. The well has been plugged and abandoned.

The well results are being integrated into the ongoing evaluation of the remaining prospectivity in our Suriname acreage position.

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 Energia Sao Tome E Principe, Unipessoal, LDA (“Galp”), a wholly-owned subsidiary of Petrogal, S.A., is the operator of Block 6. In March 2018, as part of our alliance with BP, we entered into petroleum contracts covering Blocks 10 and 13 with the Democratic Republic of Sao Tome and Principe. We presently have a 35% participating interest in the blocks and the operator, BP, holds a 50% participating interest. The national petroleum agency, Agencia Nacional Do Petroleo De Sao Tome E Principe ("ANP STP") has a 15% carried interest in the blocks through exploration. These blocks cover an area of approximately 5.9 million acres (gross) in water depths ranging from 2,250 to 3,000 meters 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. Kosmos has established an extensive position in the Rio Muni Basin where there is a proven source and reservoir inboard with the Ceiba and Okume discoveries in Equatorial Guinea, which appears to extend outboard into the deepwater in Sao Tome and Principe, where there are oil seeps on both islands. Kosmos has identified large potential structural and stratigraphic traps on early seismic, which is currently being processed.

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, providing the necessary conditions for the generation, migration and entrapment of hydrocarbons. 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.

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 has paid a proportionate share of Kosmos’ past costs in the form of a partial carry on the 3D seismic survey.

In August 2017, we completed a 3D seismic survey of approximately 15,800 square kilometers over Blocks 5, 6, 11, and 12 offshore Sao Tome and Principe. Processing has been completed. We are compiling an inventory of prospects on the license areas in Sao Tome and Principe and will continue to refine and assess the prospectivity, integrating this new 3D seismic data into our geological evaluation during 2019 with a view to drilling as early as 2020.

In November 2017, we received approval for a one-year extension of Phase 1 for Block 11 offshore Sao Tome and Principe, which now expires in July 2019.

Morocco

In August 2018, we provided to the Office National Des Hydrocarbures et des Mines ("ONHYM") a notice to abandon the Essaouira Offshore block, located offshore Morocco, at the end of the then current exploration phase (November 2018).

Cote d'Ivoire

In December 2017, as part of our Alliance with BP, we entered into petroleum contracts as operator for five Offshore Blocks, CI-526, CI-602, CI-603, CI-707 and CI-708, which are located in a Cenomanian-Turonian petroleum system and range in water depth from 450 to 4,500 meters. The area is located approximately 150 kilometers west of our TEN discoveries in Ghana. We believe the area has multiple Cretaceous source rocks with Cenomanian through Maastrichtian reservoir sands providing exploration targets. In May 2018, we completed a 3D seismic survey covering approximately 12,000 square kilometers over blocks CI-526, CI-602, CI-603, CI-707 and CI-708 offshore Cote d'Ivoire.

Namibia

In September 2018, we acquired a 45% non-operated participating interest in PEL 39 offshore Namibia, which later became part of a larger strategic alliance with Shell to jointly explore in Southern West Africa. The block covers an area of approximately 3.1 million acres in water depth ranging from 250 to 3,000 meters. The blocks provide for multiple plays targeting Cretaceous deepwater systems. We believe the area is positioned within the interpreted oil mature window of the Aptian source rock with reservoir sands sourced from the Orange River. In January 2019, we completed a 3D seismic survey covering approximately 6,000 square kilometers. Processing of this data is currently underway. We are compiling an initial inventory of prospects on the license are as will continue to refine and assess the prospectivity and petroleum systems analysis while integrating the new 3D seismic data in our geological evaluation during 2019 with a view to drilling as early as 2020.

Our Reserves

The following table sets forth summary information about our estimated proved reserves as of December 31, 2018 . See “Item 8. Financial Statements and Supplementary Data—Supplemental Oil and Gas Data (Unaudited)” for additional information.

Our estimated proved reserves as of December 31, 2018 , were associated with our Jubilee and the TEN fields in Ghana and the U.S. Gulf of Mexico as well as our share of our equity method investment in the Ceiba Field and Okume Complex in Equatorial Guinea. Our estimated proved reserves as of December 31, 2017 , were associated with our Jubilee and the TEN fields in Ghana as well as our share of our equity method investment in the Ceiba Field and Okume Complex in Equatorial Guinea. Our estimated proved reserves as of December 31, 2016 were associated with our Jubilee and TEN fields in Ghana.

Summary of Oil and Gas Reserves

Changes for the year ended December 31, 2018, include an addition of 51.1 MMBoe as a result of the acquisition of DGE. Changes at Greater Jubilee include a revision of 9.4 MMBbl related to strong field performance, positive drilling results and increased original oil in place, partially offset by 6.4 MMBbl of net Jubilee production during 2018. Changes at TEN include a positive revision 4.2 MMBbl due to original oil in place adjustments, new drilling and development plan updates, and a negative revision of 3.1 MMBbl due to recovery factor adjustment from dynamic modeling, which in total were offset by 3.7 MMBoe of net production. Changes at Equatorial Guinea include an increase of 11.0 MMBbl, which comprises 0.7 MMBbl of revision due to economic modeling, 3.9 MMBbl of revision due to strong field performance at both Ceiba and Okume Complex, and 6.4 MMBbl of revision due to reservoir management strategies (re-opening shut-in wells, stimulations, surface/subsurface equipment installation), all of which was partially offset by 5.4 MMBbl of net production. During the year ended December 31, 2018, we had an addition of 13.9 MMBoe of proved undeveloped reserves as a result of the DGE acquisition, we converted 2.0 MMBbl of proved undeveloped reserves to proved developed due to the completion of a new well in TEN, and we added 12.9 MMBbl of proved undeveloped reserves in Jubilee as a result of several factors, including positive results from drilling two new wells, increased oil-in-place due to improved static model utilizing new seismic and petrophysics data, and upgrading volumes associated with Mahogany area that is now part of the Greater Jubilee Unit.

Changes for the year ended December 31, 2017, include an increase of 15.6 MMBbl in Jubilee related to the approval of the Greater Jubilee Full Field Development Plan ("GJFFDP"), partially offset by 7.7 MMBbl of net Jubilee production during 2017. Changes at TEN include an increase of 7.2 MMBoe as a result of positive Ntomme performance and the finalization of the TAG GSA, which was partially offset by 3.3 MMBbl of net TEN production during 2017. As a result of the approval of the GJFFDP, we now have 10.4 MMBbl of proved undeveloped reserves in the Greater Jubilee area, representing future infill drilling plans. Changes for 2017 also include the initial certification of proved volumes in Equatorial Guinea, representing the reserves associated with our equity method investment.

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.

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, 2018 . All estimated future net revenues are attributable to projected production from Ghana, the U.S. Gulf of Mexico and our equity method investment in Equatorial Guinea. 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, 2018 , 2017 and 2016 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, 2018 are based on costs in effect at December 31, 2018 and the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the year ended December 31, 2018 , 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, 2018 , 2017 and 2016 , was established in 1937. For over 80 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, 2018 , 2017 and 2016 , 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, 2018 , 2017 and 2016 and related future net revenues and PV‑10 at December 31, 2018 , 2017 and 2016 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, 2018 reserve report was completed on January 13, 2019 , and a copy is included as an exhibit to this report.

In connection with the preparation of the December 31, 2018 , 2017 and 2016 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, 2018 , based upon its evaluation. RSC’s primary economic assumptions in estimates included an ability to sell hydrocarbons at their respective adjusted benchmark prices 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 Reservoir Engineering 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 Reservoir Engineering 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 a 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. Tosin Famurewa. Mr. Famurewa has been practicing consulting petroleum engineering at RSC since 2006. Mr. Famurewa is a Licensed Professional Engineer in the State of Texas (No. 100569) and has over 18 years of practical experience in petroleum engineering. He graduated from University of California at Berkeley in 2000 with Bachelor of Science Degrees in Chemical Engineering and Material Science Engineering, and he received a Master of Science degree in Petroleum Engineering from University of Southern California in 2007. Mr. Famurewa 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 Reservoir Engineering 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 reviews 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 and lease areas as of December 31, 2018 for the countries in which we currently operate.

Drilling activity

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