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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to          
Commission file number: 001-35167
kos_logo.jpg
Kosmos Energy Ltd.
(Exact name of registrant as specified in its charter)
Delaware
 
98-0686001
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
 
 
 
8176 Park Lane
 
 
Dallas,
Texas
 
75231
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code: +1 214 445 9600
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Trading Symbol
 
Name of each exchange on which registered:
Common Stock $0.01 par value
 
KOS
 
New York Stock Exchange
 
 
 
 
London Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well‑known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes   No 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes   No 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   No 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes   No 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b‑2 of the Exchange Act.
Large accelerated filer
 
Accelerated filer
 
 
 
 
 
Non-accelerated filer
 
Smaller reporting company
(Do not check if a smaller reporting company)
 
 
 
 
 
 
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Yes   No 
The aggregate market value of the voting and non‑voting common stock held by non‑affiliates, based on the per‑share closing price of the registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter was $2,220,129,484.
The number of the registrant’s Common Stock outstanding as of February 14, 2020 was 405,098,215.


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DOCUMENTS INCORPORATED BY REFERENCE
Part III, Items 10‑14, is incorporated by reference from the Proxy Statement for the Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2019.
Certain exhibits previously filed with the Securities and Exchange Commission are incorporated by reference into Part IV of this report.
 
 
 
 
 
TABLE OF CONTENTS
Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its subsidiaries. On December 28, 2018, we changed our jurisdiction of incorporation from Bermuda to the State of Delaware, which we refer to herein as the Redomestication. All references to “Kosmos,” “we,” “us” or “the company” on or before December 28, 2018 refer to Kosmos Energy Ltd., an exempted company incorporated pursuant to the laws of Bermuda, and its subsidiaries. All such references after December 28, 2018 refer to Kosmos Energy Ltd., a Delaware corporation, and its subsidiaries. In addition, all references to “common stock” on or before December 28, 2018 refer to the common shares of Kosmos Energy Ltd. prior to the Redomestication, and all such references after December 28, 2018 refer to the common stock of Kosmos Energy Ltd. after the Redomestication. For additional detail, please see “Item 1. Business—Corporate Information.”
In addition, we have provided definitions for some of the industry terms used in this report in the “Glossary and Selected Abbreviations” beginning on page 3.
 
 
Page
 
 
 
 
 
 
 
 
 
 


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KOSMOS ENERGY LTD.
GLOSSARY AND SELECTED ABBREVIATIONS
The following are abbreviations and definitions of certain terms that may be used in this report. Unless listed below, all defined terms under Rule 4‑10(a) of Regulation S‑X shall have their statutorily prescribed meanings.
“2D seismic data”
    
Two‑dimensional seismic data, serving as interpretive data that allows a view of a vertical cross‑section beneath a prospective area.
“3D seismic data”
 
Three‑dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.
"ANP-STP"
 
Agencia Nacional Do Petroleo De Sao Tome E Principe.
“API”
 
A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones.
“ASC”
 
Financial Accounting Standards Board Accounting Standards Codification.
“ASU”
 
Financial Accounting Standards Board Accounting Standards Update.
“Barrel” or “Bbl”
 
A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.
“BBbl”
 
Billion barrels of oil.
“BBoe”
 
Billion barrels of oil equivalent.
“Bcf”
 
Billion cubic feet.
“Boe”
 
Barrels of oil equivalent. Volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.
"BOEM"
 
Bureau of Ocean Energy Management.
“Boepd”
 
Barrels of oil equivalent per day.
“Bopd”
 
Barrels of oil per day.
"BP"
 
BP p.l.c. and related subsidiaries
“Bwpd”
 
Barrels of water per day.
“Debt cover ratio”
 
The “debt cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) total long‑term debt less cash and cash equivalents and restricted cash, to (y) the aggregate EBITDAX (see below) of the Company for the previous twelve months.
“Developed acreage”
 
The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Development”
 
The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.
"DGE"
 
Deep Gulf Energy (together with its subsidiaries).
"DST"
 
Drill stem test.
“Dry hole” or "Unsuccessful well"
 
A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.
"DT"
 
Deepwater Tano.
“EBITDAX”
 
Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity‑based compensation expense, (iv) unrealized (gain) loss on commodity derivatives (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results. The Facility EBITDAX definition includes 50% of the EBITDAX adjustments of Kosmos-Trident International Petroleum Inc for the period it was an equity method investment and includes Last Twelve Months ("LTM") EBITDAX for any acquisitions and excludes LTM EBITDAX for any divestitures.
"ESG"
 
Environmental, social, and governance.
"ESP"
 
Electric submersible pump.
“E&P”
 
Exploration and production.

3

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“FASB”
 
Financial Accounting Standards Board.
“Farm‑in”
 
An agreement whereby a party acquires a portion of the participating interest in a block from the owner of such interest, usually in return for cash and/or for taking on a portion of future costs or other performance by the assignee as a condition of the assignment.
“Farm‑out”
 
An agreement whereby the owner of the participating interest agrees to assign a portion of its participating interest in a block to another party for cash and/or for the assignee taking on a portion of future costs and/or other work as a condition of the assignment.
"FEED"
 
Front End Engineering Design.
“Field life cover ratio”
 
The “field life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) the forecasted net present value of net cash flow through depletion plus the net present value of the forecast of certain capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
"FLNG"
 
Floating liquefied natural gas.
“FPS”
 
Floating production system.
“FPSO”
 
Floating production, storage and offloading vessel.
"Galp"
 
Galp Energia Sao Tome E Principe, Unipessoal, LDA.
"GEPetrol"
 
Guinea Equatorial De Petroleos.
"GHG"
 
Greenhouse gas.
"GJFFDP"
 
Greater Jubilee Full Field Development Plan.
"GNPC"
 
Ghana National Petroleum Corporation.
“Greater Tortue Ahmeyim”
 
Ahmeyim and Guembeul discoveries.
"GTA UUOA"
 
Unitization and Unit Operating Agreement covering the Greater Tortue Ahmeyim Unit.
"Hess"
 
Hess Corporation.
"HLS"
 
Heavy Louisiana Sweet.
"H&M"
 
Hull and Machinery insurance.
"Jubilee UUOA"
 
Unitization and Unit Operating Agreement covering the Jubilee Unit.
"KBSL"
 
Kosmos BP Senegal Limited.
"KTEGI"
 
Kosmos-Trident Equatorial Guinea Inc.
"KTIPI"
 
Kosmos-Trident International Petroleum Inc.
“Interest cover ratio”
 
The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months.
"LNG"
 
Liquefied natural gas.
“Loan life cover ratio”
 
The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of forecasted net cash flow through the final maturity date of the Facility plus the net present value of forecasted capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
"LOPI"
 
Loss of Production Income.
"LSE"
 
London Stock Exchange.
"LTIP"
 
Long Term Incentive Plan.
“MBbl”
 
Thousand barrels of oil.
“MBoe”
 
Thousand barrels of oil equivalent.
“Mcf”
 
Thousand cubic feet of natural gas.
“Mcfpd”
 
Thousand cubic feet per day of natural gas.
“MMBbl”
 
Million barrels of oil.
“MMBoe”
 
Million barrels of oil equivalent.
"MMBtu"
 
Million British thermal units.
“MMcf”
 
Million cubic feet of natural gas.

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“MMcfd”
 
Million cubic feet per day of natural gas.
"MMTPA"
 
Million metric tonnes per annum.
"NAMCOR"
 
National Petroleum Corporation of Namibia.
“Natural gas liquid” or “NGL”
 
Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others.
"NYSE"
 
New York Stock Exchange.
"Ophir"
 
Ophir Energy plc.
"PETROCI"
 
PETROCI Holding.
“Petroleum contract”
 
A contract in which the owner of hydrocarbons gives an E&P company temporary and limited rights, including an exclusive option to explore for, develop, and produce hydrocarbons from the lease area.
“Petroleum system”
 
A petroleum system consists of organic material that has been buried at a sufficient depth to allow adequate temperature and pressure to expel hydrocarbons and cause the movement of oil and natural gas from the area in which it was formed to a reservoir rock where it can accumulate.
“Plan of development” or “PoD”
 
A written document outlining the steps to be undertaken to develop a field.
“Productive well”
 
An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
“Prospect(s)”
 
A potential trap that may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of these fail neither oil nor natural gas may be present, at least not in commercial volumes.
“Proved reserves”
 
Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S‑X 4‑10(a)(2).
“Proved developed reserves”
 
Those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
“Proved undeveloped reserves”
 
Those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.
"RSC"
 
Ryder Scott Company, L.P.
"SEC"
 
Securities and Exchange Commission.
"Senior Notes"
 
7.125% Senior Notes due 2026.
"Senior Secured Notes"
 
7.875% Senior Secured Notes due 2021.
“Shelf margin”
 
The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.
"Shell"
 
Royal Dutch Shell and related subsidiaries.
"SNPC"
 
Société Nationale des Pétroles du Congo.
“Stratigraphy”
 
The study of the composition, relative ages and distribution of layers of sedimentary rock.
“Stratigraphic trap”
 
A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.
“Structural trap”
 
A topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and gas in the strata.
“Structural‑stratigraphic trap”
 
A structural‑stratigraphic trap is a combination trap with structural and stratigraphic features.
“Submarine fan”
 
A fan‑shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.
"TAG GSA"
 
TEN Associated Gas - Gas Sales Agreement.

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"TEN"
 
Tweneboa, Enyenra and Ntomme.
“Three‑way fault trap”
 
A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.
"Tortue Phase 1 SPA"
 
Greater Tortue Ahmeyim Agreement for a Long Term Sale and Purchase of LNG.
“Trap”
 
A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.
"Trident"
 
Trident Energy.
“Undeveloped acreage”
 
Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains discovered resources.
"WCTP"
 
West Cape Three Points.

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Cautionary Statement Regarding Forward‑Looking Statements
This annual report on Form 10‑K contains estimates and forward‑looking statements, principally in “Item 1. Business,” “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our estimates and forward‑looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward‑looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in our annual report on Form 10‑K, may adversely affect our results as indicated in forward‑looking statements. You should read this annual report on Form 10‑K and the documents that we have filed as exhibits hereto completely and with the understanding that our actual future results may be materially different from what we expect. Our estimates and forward‑looking statements may be influenced by the following factors, among others:
our ability to find, acquire or gain access to other discoveries and prospects and to successfully develop and produce from our current discoveries and prospects;
uncertainties inherent in making estimates of our oil and natural gas data;
the successful implementation of our and our block partners’ prospect discovery and development and drilling plans;
projected and targeted capital expenditures and other costs, commitments and revenues;
termination of or intervention in concessions, rights or authorizations granted to us by the governments of the countries in which we operate (or their respective national oil companies) or any other federal, state or local governments or authorities;
our dependence on our key management personnel and our ability to attract and retain qualified technical personnel;
the ability to obtain financing and to comply with the terms under which such financing may be available;
the volatility of oil, natural gas and NGL prices;
the availability, cost, function and reliability of developing appropriate infrastructure around and transportation to our discoveries and prospects;
the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;
other competitive pressures;
potential liabilities inherent in oil and natural gas operations, including drilling and production risks and other operational and environmental risks and hazards;
current and future government regulation of the oil and gas industry or regulation of the investment in or ability to do business with certain countries or regimes;
cost of compliance with laws and regulations;
changes in environmental, health and safety or climate change or GHG laws and regulations or the implementation, or interpretation, of those laws and regulations;
adverse effects of sovereign boundary disputes in the jurisdictions in which we operate;
environmental liabilities;
geological, geophysical and other technical and operations problems including drilling and oil and gas production and processing;
military operations, civil unrest, outbreaks of disease, terrorist acts, wars or embargoes;
the cost and availability of adequate insurance coverage and whether such coverage is enough to sufficiently mitigate potential losses and whether our insurers comply with their obligations under our coverage agreements;

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our vulnerability to severe weather events, including tropical storms and hurricanes in the Gulf of Mexico;
our ability to meet our obligations under the agreements governing our indebtedness;
the availability and cost of financing and refinancing our indebtedness;
the amount of collateral required to be posted from time to time in our hedging transactions, letters of credit, performance bonds and other secured debt;
the result of any legal proceedings, arbitrations, or investigations we may be subject to or involved in;
our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; and
other risk factors discussed in the “Item 1A. Risk Factors” section of this annual report on Form 10‑K.

The words “believe,” “may,” “will,” “aim,” “estimate,” “continue,” “anticipate,” “intend,” “expect,” “plan” and similar words are intended to identify estimates and forward‑looking statements. Estimates and forward‑looking statements speak only as of the date they were made, and, except to the extent required by law, we undertake no obligation to update or to review any estimate and/or forward‑looking statement because of new information, future events or other factors. Estimates and forward‑looking statements involve risks and uncertainties and are not guarantees of future performance. As a result of the risks and uncertainties described above, the estimates and forward‑looking statements discussed in this annual report on Form 10‑K might not occur, and our future results and our performance may differ materially from those expressed in these forward‑looking statements due to, including, but not limited to, the factors mentioned above. Because of these uncertainties, you should not place undue reliance on these forward‑looking statements.

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PART I
Item 1.  Business
General

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, Sao Tome and Principe, and South Africa). Kosmos is listed on the NYSE and 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. 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 field in 2015 (which includes the Ahmeyim and Guembeul-1 discovery wells 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 discovered during that decade. First oil production was delivered just 42 months after initial discovery, a record for a deepwater development in West Africa in this water depth. 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 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 safely 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 and stakeholders.

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 an efficient 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 2022, as well as advancing our other discoveries towards a final investment decision. In addition, our exploration portfolio consists of a large inventory of leads and prospects 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 additional growth potential in the coming years. We do not plan on accessing new basin opening oil positions.
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 2020. In the U.S. Gulf of Mexico, we plan to continue development drilling on existing fields and drilling multiple infrastructure-led exploration targets. In Equatorial Guinea, our activity set is expanding beyond production optimization projects, such as 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 the phase 1 development of Greater Tortue Ahmeyim, growth could also be realized through additional development of Greater Tortue Ahmeyim and through the development of all or a portion of our other discoveries in Mauritania and Senegal. Additionally, our basin opening exploration activity include opportunities offshore Equatorial Guinea, Sao Tome and Principe, Cote d'Ivoire, Suriname, Namibia and South Africa. During 2020, we plan to mature development concepts from previous discoveries in Mauritania, Senegal and Equatorial Guinea, drill three infrastructure-led prospects and two development wells in the U.S. Gulf of Mexico, drill two infill wells in Equatorial Guinea and drill one frontier exploration well in Sao Tome and Principe.

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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. Our development of the Jubilee Field is an example of this approach.
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 approximately seven years after initial discovery. Lastly, our approach to discoveries in the U.S. Gulf of Mexico is to develop them via subsea tie-back to existing host facilities with existing spare capacity. This reduces the average timeline to first production.
Kosmos Exploration Approach - A balance of basin opening and infrastructure-led
Kosmos’ philosophy, in new basin opening exploration, 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.
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 utilized for all new areas and is a key strength of Kosmos.
In support of delivering a sustainable, balanced exploration program, our approach has broadened to include infrastructure-led exploration. This shorter-cycle approach 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. Acquisition of the Ceiba Field and Okume Complex in Equatorial Guinea and assets in the U.S. Gulf of Mexico have added high-quality prospectivity to our inventory of infrastructure-led exploration opportunities given their attractive acreage positions within proximity of existing infrastructure with excess capacity available. This opens a potential new growth area with attractive economics in areas with high margin production that complements the basin opening exploration program.
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 way to accomplish this is to partner with high-quality industry players with world‑class complementary capabilities. This strategy is designed to ensure 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 and 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, the alliance formed in 2017 with a subsidiary of BP broadened our relationship to cover new venture opportunities in Mauritania, Senegal and The Gambia to create an Atlantic Margin explorer-developer partnership that leveraged Kosmos' regional exploration knowledge and capability with BP's deepwater development expertise to execute a selective, basin opening exploration strategy in the Atlantic Margin.
Similarly, 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. The alliance initially focused on Namibia where Kosmos had completed a farm-in to Shell's acreage in PEL 39, and Kosmos' Sao Tome & Principe acreage where Shell farmed into Blocks 6 and 11. In September 2019, Shell and Kosmos completed a farm-in agreement whereby Kosmos and Shell obtained interests in the Northern Cape Ultra Deep block offshore the Republic of South Africa. As part of the alliance, the two companies are also

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jointly evaluating opportunities in adjacent geographies. This alliance is consistent with Kosmos’ strategy of partnering with supermajors to leverage complementary skill sets.
During the first quarter of 2019, Kosmos farmed-into 18 BP-owned blocks in the Garden Banks area of the deepwater U.S. Gulf of Mexico. In addition, Kosmos can earn an interest in three BP blocks in other areas of the deepwater U.S. Gulf of Mexico. This should allow Kosmos to execute projects that can be tied back to existing infrastructure. Kosmos is the designated operator.
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.
Secure a premium license to operate through industry-leading ESG performance

Kosmos recognizes that creating long-term shareholder returns can only be achieved by advancing the societies in which we work and operating in a manner that protects the environment. Kosmos focuses on continuously improving its ESG credentials by working with a range of stakeholders, including shareholders, partners, suppliers, host governments and civil society organizations.

The company looks upon the United Nations Sustainable Development Goals as a useful template for evaluating and understanding how our activities promote economic and social progress in host countries. In 2013, we adopted the Kosmos Energy Business Principles to formalize our commitment to act as a force for good. Our Business Principles are supported by more detailed policies, procedures, and management systems. Each year, we report on our environmental, social, and governance practices and performance in our Sustainability Report and on our website.

Most recently, our ESG work has centered on evaluating the costs, benefits, risks, and opportunities that climate change and the global energy transition may present to our business, and integrating them into our business strategy. As part of this effort, we established governance structures to monitor and manage climate-related risks and opportunities; developed a strategy to measure and reduce greenhouse gas emissions from our own operations and mitigate remaining emissions through innovative nature-based solutions. Beginning in 2020, we plan to report on these issues in a manner aligned with the Task Force on Climate-related Disclosure (TCFD) and the Sustainability Accounting Standards Board (SASB) guidelines.

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, 2019, our net leverage ratio was approximately 1.8 times as a result of utilizing our free cash flow generated in 2019 to reduce outstanding borrowings. Likewise, our liquidity increased to approximately $0.8 billion.
Additionally, we use derivative instruments to partially limit our exposure to fluctuations in oil prices. 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, 2019, we have hedged positions covering 16.0 million barrels of oil production from 2020 through 2021. We also maintain insurance to partially protect against loss of production revenues from our producing assets.

During 2019, Kosmos generated approximately $628.2 million of cash flow from operating activities.


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Operations by Geographic Area
We currently have operations in Africa and the Americas. Presently, our operating revenues are generated from our operations offshore Ghana, Equatorial Guinea, and U.S. Gulf of Mexico. The following tables provide a summary of certain key 2019 data for our geographic areas.
Geographic Area
 
Sales Volumes (Net to Kosmos)
 
Percentage of Total Sales Volumes
 
Revenue
 
Year-End Estimated Proved Reserves(1)
 
Percentage of Total Estimated Proved Reserves
 
 
(in MMboe)
 
 
 
(in thousands)
 
(in MMboe)
 
 
Ghana
 
11.4

 
46
%
 
$
738,909

 
95

 
56
%
Equatorial Guinea
 
4.7

 
19
%
 
300,547

 
28

 
17
%
Mauritania / Senegal(2)
 

 

 

 

 

U.S. Gulf of Mexico
 
8.8

 
35

 
459,960

 
46

 
27

Total
 
24.9

 
100
%
 
$
1,499,416

 
169

 
100
%
______________________________________
(1)
For information concerning our estimated proved reserves as of December 31, 2019, see “—Our Reserves.”
(2)
The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the company's independent reserve auditor Ryder Scott, LP.


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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
 
(8)
 
Big Bend
 
MC 697 / 698 / 742
 
 
 
5.3
%
 
 
 
Fieldwood
 
 
 
Production
 
(8)
 
Don Larsen
 
EB 598
 
 
 
20.0
%
 
 
 
Occidental
 
 
 
Production
 
(8)
 
Gladden
 
MC 800
 
 
 
20.0
%
 
 
 
W&T
 
 
 
Production
 
(8)
 
Kodiak
 
MC 727 / 771
 
 
 
29.1
%
 
 
 
Kosmos
 
 
 
Production
 
(8)
 
Marmalard
 
MC 255 / 300
 
 
 
11.4
%
 
 
 
Murphy
 
 
 
Production
 
(8)
 
Nearly Headless Nick
 
MC 387
 
 
 
21.9
%
 
 
 
Murphy
 
 
 
Production
 
(8)
 
Danny Noonan
 
EC 381 /
GB 506
 
 
 
30.0
%
 
 
 
Talos
 
 
 
Production
 
(8)
 
Odd Job
 
MC 214 / 215
 
 
 
Various

 
(5)
 
Kosmos
 
 
 
Production
 
(8)
 
Sargent
 
GB 339
 
 
 
50.0
%
 
 
 
Kosmos
 
 
 
Production
 
(8)
 
SOB II
 
MC 431
 
 
 
11.4
%
 
 
 
Murphy
 
 
 
Production
 
(8)
 
S. Santa Cruz
 
MC 563
 
 
 
40.5
%
 
 
 
Kosmos
 
 
 
Production
 
(8)
 
Tornado
 
GC 281
 
 
 
35.0
%
 
 
 
Talos
 
 
 
Production
 
(8)
 
Mauritania
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Tortue Ahmeyim
 
Block C8
 
(3)
 
26.8
%
 
 
 
BP
 
 
 
Development
 
2049(9)
 
Marsouin
 
Block C8
 
 
 
28.0
%
 
(6)
 
BP
 
 
 
Appraisal
 
2022
 
Orca
 
Block C8
 
 
 
28.0
%
 
(6)
 
BP
 
 
 
Appraisal
 
2022
 
Senegal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Tortue Ahmeyim
 
Saint Louis Offshore Profond
 
(3)
 
26.7
%
 
 
 
BP
 
 
 
Development
 
2044(10)
 
Teranga
 
Cayar Offshore Profond
 
 
 
30.0
%
 
(7)
 
BP
 
 
 
Appraisal
 
2021
 
Yakaar
 
Cayar Offshore Profond
 
 
 
30.0
%
 
(7)
 
BP
 
 
 
Appraisal
 
2021
 
Equatorial Guinea(1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ceiba Field and Okume Complex
 
Block G
 
 
 
40.4
%
 
 
 
Trident
 
 
 
Production
 
2034
 
______________________________________
(1)
For information concerning our estimated proved reserves as of December 31, 2019, see “—Our Reserves.”
(2)
The Jubilee Field straddles the boundary between the WCTP petroleum contract and the DT petroleum contract offshore Ghana. To optimize resource recovery in this field, we entered into the Jubilee UUOA in July 2009 with the GNPC and the other block partners of each of these two blocks. The Jubilee UUOA governs the interests in and development of the Jubilee Field and created the Jubilee Unit from portions of the WCTP petroleum contract and the DT petroleum contract areas.
These interest percentages are subject to redetermination of the participating interests in the Jubilee Field pursuant to the terms of the Jubilee UUOA. Our current paying interest on development activities in the Jubilee Field is 26.9%.
(3)
The Greater Tortue Ahmeyim Unit, which includes the Ahmeyim discovery in Mauritania Block C8 and the Guembeul discovery in the Senegal Saint Louis Offshore Profond Block, straddles the border between Mauritania and Senegal. To optimize resource recovery in this field, we entered into the GTA UUOA in February 2019 with the governments of Mauritania and Senegal. The GTA UUOA governs interests in and development of the Greater Tortue Ahmeyim Field and created the Greater Tortue Ahmeyim Unit from portions of the Mauritania Block C8 and the Senegal Saint Louis Offshore Profond Block areas.

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These interest percentages are subject to redetermination of the participating interests in the Greater Tortue Ahmeyim Field pursuant to the terms of the GTA UUOA. Our current payment interest on development activities in the Greater Tortue Ahmeyim Unit is 26.7%.
(4)
Our paying interest on development activities in the TEN fields is 19%.
(5)
Our interests in blocks MC 214 and MC 215 are 61.1% and 54.9%, respectively.
(6)
SMHPM has the option to acquire up to an additional 4% participating interest in a commercial development on Block C8. These interest percentages do not give effect to the exercise of such option.
(7)
PETROSEN has the option to acquire up to an additional 10% participating interest in a commercial development on the Saint Louis Offshore Profond and Cayar Offshore Profond Blocks. The interest percentage does not give effect to the exercise of such option.
(8)
Our U.S. Gulf of Mexico blocks are held by production/operations, and the lease periods extend as long as production/governmental approved operations continue on the relevant block.
(9)
License expiration date can be extended by an additional ten years subject to certain conditions being met.
(10)
License expiration date can be extended by an additional twenty years subject to certain conditions being met.

Exploration License and Lease Areas
 
 
 
 
Kosmos Average
 
 
 
 
 
Current Phase
 
 
 
Number of
 
Participating
 
 
 
 
 
License
 
Country
 
Blocks
 
Interest
 
    
 
Operator(s)
 
Expiration Range
 
Cote d'Ivoire
 
5
 
45.0%
 
(1)
 
Kosmos
 
2020
(9)
Equatorial Guinea
 
4
 
50.0%
 
(2)
 
Kosmos
 
2020-2021
(9)
Mauritania
 
4
 
28.0%
 
(3)
 
BP
 
2020-2022
(9)
Namibia
 
1
 
45.0%
 
(4)
 
Shell
 
2022
(9)
Sao Tome and Principe
 
6
 
39.0%
 
(5)
 
Kosmos, BP, Galp
 
2020-2022
(9)
Senegal
 
2
 
30.0%
 
(6)
 
BP
 
2021
 
South Africa
 
1
 
45.0%
 
(7)
 
Shell
 
2021
(9)
Suriname
 
2
 
41.5%
 
(8)
 
Kosmos
 
2020-2021
(9)
U.S. Gulf of Mexico
 
79
 
53.0%
 
 
 
Kosmos, Chevron, Murphy, Talos, Fieldwood, Occidental, W&T Offshore
 
through 2029
(10)
______________________________________
(1)
PETROCI has the option to acquire up to an additional 2% paying interests in a commercial development. The interest percentage does not give effect to the exercise of such option.
(2)
Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest for all development and production operations.
(3)
Should a commercial discovery be made, SMHPM’s 10% carried interest is extinguished and SMHPM will have an option to obtain a participating interest in the discovery area between 10% and 14% (blocks C8, C12 and C13) and 10% and 18% (Block C6). SMHPM will pay its portion of development and production costs in a commercial development on the blocks. The interest percentage does not give effect to the exercise of such option.
(4)
Should a commercial discovery be made, NAMCOR's 10% carried interest during the exploration period may continue through first commercial production but must be reimbursed through production.
(5)
ANP-STP's carried interest may be converted to a full participating interest at any time. ANP-STP will reimburse any costs, expenses and any amount incurred on its behalf prior to the election. Formal withdraw notice on STP Block 12 was communicated to partners on December 13, 2019 and was effective January 31, 2020.

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(6)
PETROSEN has the option to obtain up to an additional 10% paying interest in a commercial development on the Saint Louis Offshore Profond and Cayar Offshore Profond Blocks. The interest percentage does not give effect to the exercise of such option.
(7)
The Republic of South Africa has the option to obtain a percentage of the participating interest ("State Option") in accordance with the provisions of the Applicable Laws prevailing at the time of the granting of a Production Right governing State Option requirements.
(8)
Should a commercial discovery be made, Staatsolie has the option to participate up to 10% in Block 42 and up to 15% in Block 45 in each commercial discovery. Staatsolie will pay its portion of development and production costs in a commercial development in which it participates.
(9)
License expiration date can be extended beyond the current exploration period upon completion of required work program and subject to additional work obligations.
(10)
Our U.S. Gulf of Mexico blocks can be held by continued operations, and the lease periods on blocks that are held by continued operations extend as long as governmental approved operations continue on the relevant block. This can extend the license expiration to a date later than 2029.

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 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 as part of the Jubilee Field Unit 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 was completed in 2019. The final phase of the Turret Remediation Project, the installation and commissioning of the catenary anchor leg mooring ("CALM") Buoy, is expected to be completed around mid-year 2020. The financial impact of the additional expenditures associated with the damage to the turret bearing was mitigated through H&M insurance.
Oil production from the Jubilee Field averaged approximately 87,400 Bopd gross (20,000 Bopd net) during 2019.

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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. The discoveries are being jointly developed with shared infrastructure and a single FPSO, with first oil produced in August 2016.
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.
Oil production from TEN averaged approximately 61,100 Bopd gross (9,900 Bopd net) during 2019.
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 TAG GSA. 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. After the acquisition, we have expanded our inventory through the U.S. Gulf of Mexico Federal lease sales and farm-in transactions, including expansion into the Walker Ridge, De Soto Canyon and Keathley Canyon areas of the U.S. Gulf of Mexico. Our U.S. Gulf of Mexico assets averaged approximately 24,100 Boepd (net) (~ 82% oil) from 13 fields during 2019.

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 Murphy. The technical team initially identified the Middle Miocene sands at the Odd Job prospect, and these sands are currently producing. The Odd Job 214 #2 well, the third well in the Odd Job field, was drilled in 2018, and came online in the fourth quarter of 2019. Net production during 2019 averaged approximately 7,200 Boepd.

Tornado

The Tornado field is producing from three 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. A water injection well is expected to be drilled in 2020 to help enhance overall recoveries in the Tornado field. Net production during 2019 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 Murphy. Net production during 2019 averaged approximately 2,800 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 anticipated to be drilled and completed during 2020. Net production during 2019 averaged approximately 3,400 Boepd.

South Santa Cruz / Barataria

The South Santa Cruz field is producing from one well in a Late Miocene sand. The Barataria field is also producing from one well in a Late Miocene sand. Both fields produce through the Blind Faith tension-leg platform, which is operated by Chevron. Net production from these two wells during 2019 averaged approximately 2,400 Boepd.



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Mauritania
The C6, C8, C12, and C13 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.
These blocks cover an aggregate area of approximately 4.9 million acres (gross). We have acquired approximately 6,200 line-kilometers of 2D seismic data and 21,700 square kilometers of 3D seismic data covering portions of our blocks in Mauritania. Based on these 2D and 3D seismic programs, we have drilled three 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.
In the second quarter of 2019, we withdrew from Block C18 offshore 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 acquired approximately 7,500 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 4,600 square kilometer survey over the western portions of the Senegal Blocks to fully evaluate the prospectivity. We have drilled three successful exploration wells and two appraisal wells.
The following is a brief discussion of our discoveries to date offshore Mauritania and Senegal.
Greater Tortue Ahmeyim Development
The Greater Tortue Ahmeyim discoveries 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 Block offshore Senegal.
We have drilled four wells within the Greater Tortue Ahmeyim development, Tortue-1, Guembeul-1, Ahmeyim-2 and Greater Tortue Ahmeyim-1 (GTA-1). 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.
The Greater Tortue Ahmeyim-1 (GTA-1) appraisal well was drilled on the eastern anticline within the unit development area of Greater Tortue Ahmeyim field. The GTA-1 well encountered approximately 30 meters of net gas pay in high quality Albian reservoir. The well was drilled in approximately 2,500 meters of water, approximately 10 kilometers inboard of the Guembeul-1A and Tortue-1 wells, to a total depth of 4,884 meters.

In August 2017, we completed a DST on 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,

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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 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. Additionally, in February 2020 the Tortue Phase 1 SPA was executed.
 

Other Mauritania and Senegal Discoveries
BirAllah and Orca 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 Orca-1 well, located in Block C8 offshore Mauritania, was drilled in October 2019 and delivered a major gas discovery. The Orca-1 well, which targeted a previously untested Albian play, encountered 36 meters of net gas pay in excellent quality reservoirs. In addition, the well extended the Cenomanian play fairway by confirming 11 meters of net gas pay in a down-structure position relative to the original Marsouin-1 discovery well. The location of the Orca-1 well proved both the structural and stratigraphic components of the trap are working, thereby proving a significant volume. The Orca-1 well was drilled in approximately 2,510 meters of water to a total measured depth of around 5,266 meters.

In total, we believe that Orca-1 and Marsouin-1 have de-risked more than sufficient resource to support a world-scale LNG project from the Cenomanian and Albian plays in the BirAllah area.

Yakaar and Teranga Discoveries

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. In September 2019, we completed the Yakaar-2 appraisal well, which encountered approximately 30 meters of net gas pay. The Yakaar-2 well was drilled approximately nine kilometers from the Yakaar-1 exploration well and further delineated the southern extension of the field.

The results of the Yakaar-2 well underpin our view that the Yakaar-Teranga resource base is world-scale and has the potential to support an LNG project that provides significant volumes of natural gas to both domestic and export markets. Development of Yakaar-Teranga is being considered in a phased approach with Phase 1 providing domestic gas and data to optimize the development of future phases. It could also support the country’s “Plan Emergent Senegal” launched by the President of Senegal in 2014.

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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 for Block EG-24, offshore Equatorial Guinea, whereby we acquired a 40% non-operated participating interest. 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 the first quarter of 2019, we acquired Ophir's remaining interest in and operatorship of the block, which results 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 is being interpreted with the objective of high grading prospects for future drilling as early as 2021.

Ceiba Field and Okume Complex
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, which held 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 owned 50% of Hess International Petroleum Inc. Hess International Petroleum Inc. was subsequently renamed 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.

Effective as of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.4% undivided participating interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex is accounted for under the proportionate consolidation method of accounting going forward. Oil production from the Ceiba Field and Okume Complex averaged approximately 38,300 Bopd gross (12,100 Bopd net) of oil per day during 2019.

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

Asam Discovery

In October 2019, the S-5 exploration well was drilled to a total depth of 4,400 meters offshore Equatorial Guinea, encountering 39 meters of net oil pay in good-quality Santonian reservoir. The well is located within tieback range of the Ceiba FPSO and work is currently ongoing to establish the scale of the discovered resource and evaluate the optimum development solution.

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 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 the nearby Maka Central-1 discovery offshore Suriname Block 58, as well as the discoveries offshore Guyana, including the Liza-1 well.

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Suriname Block 42 and Block 45 are positioned centrally in the Suriname-Guyana Basin, and located to the east of the play opening Liza-1 oil discovery. Likewise, the blocks are also positioned to the northeast of the Maka Central-1 discovery offshore Suriname. Of note are the stratigraphically trapped Upper Cretaceous plays similar to the discoveries in Guyana (Liza-1) and Suriname (Maka Central-1), and a carbonate reef play analagous to the Ranger-1 discovery in Guyana. These plays are located in the same geologic basin providing positive points of calibration for the prospectivity in Suriname Block 42. 
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 in Block 45 to a total depth of approximately 4,600 meters and 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 in Block 42 to a total depth of approximately 6,200 meters and 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.

Recent well results are being integrated into the ongoing evaluation of the remaining prospectivity in our Suriname acreage position, with the objective of high-grading a prospect for drilling in 2021.
Sao Tome and Principe
We are operator for petroleum contracts covering Blocks 5 and 11 and maintain a non-operated position in Blocks 6, 10 and 13 offshore Sao Tome and Principe in the Gulf of Guinea. Galp, a wholly-owned subsidiary of Petrogal, S.A., is the operator of Block 6. BP is the operator of Blocks 10 and 13. These blocks cover an area of approximately 8.5 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 basins formed during the separation of Africa from South America, providing the necessary conditions for the generation, migration and entrapment of hydrocarbons. Large deep-water slope channels and basin floor fans draping over and around anticlinal highs adjacent to fracture zones constitute the main play in the acreage.
In August 2017, we completed a 3D seismic survey of approximately 15,800 square kilometers 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. We plan to drill an exploration well in Block 6 offshore Sao Tome and Principe in late 2020.
In the fourth quarter of 2019, formal withdrawal notice from Block 12 offshore Sao Tome and Principe was communicated to partners with an effective date of January 31, 2020.

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 approximately 150 kilometers west of our TEN discoveries in Ghana in water depth from 450 to 4,500 meters. We believe the area has multiple Cretaceous source rocks with Cenomanian

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through Maastrichtian reservoir sands providing the potential for exploration targets. We are compiling an inventory of prospects on the license areas in Cote d'Ivoire and will continue to refine and assess the prospectivity, integrating the 3D seismic data acquired in May 2018 into our geological evaluation. Following evaluation, a decision will be made on future exploration plans prior to the expiry of the current exploration phase in December 2020.

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 with reservoir sands sourced from the Orange River. In January 2019, we completed a 3D seismic survey covering approximately 7,400 square kilometers. Processing of this data is complete. We are compiling an inventory of prospects on the license and continue to refine and assess the prospectivity and petroleum systems analysis while integrating the new 3D seismic data in our geological evaluation with a view to drilling in early 2021.

Republic of South Africa
In September 2019, we completed a farm-in agreement with OK Energy to acquire a 45% non-operated interest in the Northern Cape Ultra Deep block offshore the Republic of South Africa. Shell owns 45% of the block and is the operator and OK Energy retained 10%. The petroleum contract covers approximately 6,930 square kilometers at water depths ranging from 2,500 to 3,100 meters and has an initial exploration phase of two years. We believe this block contains Cretaceous deepwater sand systems and the same Aptian Kudu source rock proven by discoveries north of this block, in Namibia. During 2020, we will design a 2D seismic survey to be acquired during 2021 in order to high-grade areas for a potential 3D seismic survey in the future.

Republic of Congo
In March 2019, we entered into a petroleum contract covering the offshore Marine XXI block with the Republic of the Congo, subject to governmental approvals. Upon approval, we will hold an 85% participating interest and be the operator. The Congolese national oil company, SPNC, has a 15% carried participating interest during the exploration period. Should a commercial discovery be made, SNPC's 15% carried interest will convert to a participating interest of at least 15%. The petroleum contract covers approximately 2,350 square kilometers, with a first exploration period of four years and includes a work program to acquire and interpret 2,200 square kilometers of 3D seismic. There are two optional exploration phases, each for a period of three years, which are subject to additional work program commitments.

Our Reserves
The following table sets forth summary information about our estimated proved reserves as of December 31, 2019. 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, 2019, were associated with our fields in Ghana, Equatorial Guinea, and the U.S. Gulf of Mexico. Our estimated proved reserves as of December 31, 2018, were associated with our 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 fields in Ghana as well as our share of our equity method investment in the Ceiba Field and Okume Complex in Equatorial Guinea.

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Summary of Oil and Gas Reserves
 
2019 Net Proved Reserves(1)
 
2018 Net Proved Reserves(1)
 
2017 Net Proved Reserves(1)
 
Oil,
Condensate,
NGLs
 
Natural
Gas(3)
 
Total
 
Oil,
Condensate,
NGLs
 
Natural
Gas(3)
 
Total
 
Oil,
Condensate,
NGLs
 
Natural
Gas(3)
 
Total
 
(MMBbl)
 
(Bcf)
 
(MMBoe)
 
(MMBbl)
 
(Bcf)
 
(MMBoe)
 
(MMBbl)
 
(Bcf)
 
(MMBoe)
Reserves Category
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved developed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ghana(2)
47

 
31

 
52

 
48

 
33

 
54

 
59

 
38

 
65

Equatorial Guinea(4)
23

 
12

 
25

 

 

 

 

 

 

Mauritania/Senegal(5)

 

 

 

 

 

 

 

 

U.S. Gulf of Mexico
34

 
28

 
39

 
33

 
25

 
37

 

 

 

Total proved developed
104

 
71

 
116

 
82

 
57

 
91

 
59

 
38

 
65

Proved undeveloped
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ghana(2)
41

 
14

 
43

 
34

 
14

 
36

 
23

 
11

 
24

Equatorial Guinea(4)
3

 

 
3

 

 

 

 

 

 

Mauritania/Senegal(5)

 

 

 

 

 

 

 

 

U.S. Gulf of Mexico
6

 
7

 
7

 
12

 
13

 
14

 

 

 

Total proved undeveloped(6)
50

 
21

 
53

 
45

 
28

 
50

 
23

 
11

 
24

Total Kosmos proved reserves
154

 
92

 
169

 
127

 
85

 
141

 
82

 
49

 
89

Equity method investment(4)
 
 
 
 
 
 
24

 
14

 
27

 
19

 
13

 
21

Total proved reserves


 


 


 
151

 
99

 
167

 
100

 
61

 
110

______________________________________
(1)
Totals within the table may not add as a result of rounding.
(2)
Our reserves associated with the Jubilee Field are based on the 54.4%/45.6% redetermination split between the WCTP Block and DT Block.
(3)
These reserves include the estimated quantities of fuel gas required to operate the Jubilee and TEN FPSOs during normal field operations and the associated gas forecasted to be exported from TEN. This volume of associated gas is included as of December 31, 2017 as a result of the finalization of the TAG GSA. If and when a subsequent gas sales agreement is executed for Jubilee, a portion of the remaining Jubilee gas may be recognized as reserves. If and when a gas sales agreement and the related infrastructure are in place for the TEN fields non-associated gas, a portion of the remaining gas may be recognized as reserves.
(4)
We disclosed our share of reserves that were accounted for by the equity method. Effective of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.4% undivided participating interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex is accounted for under the proportionate consolidation method of accounting going forward.
(5)
The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the company's independent reserve auditor Ryder Scott, LP.
(6)
All of our proved undeveloped reserves are expected to be developed within six years or less. Proved undeveloped reserves expected to be developed beyond five years are related to long-term projects which will be completed under a continuous drilling program.

Changes at Jubilee include a positive revision of 8.2 MMBbl related to positive drilling results and increased original oil in place, and optimized development plan, partially offset by net Jubilee production of 7.6 MMBbl. Changes at TEN include an increase of 8.8 MMBoe related to original oil in place adjustments based on updated static modeling and development plan updates, partially offset by net TEN production of 3.8 MMBoe. Changes at Equatorial Guinea include an increase of 6.3 MMBbl due to production optimization plans and plans for new drilling, which was offset by 4.7 MMBbl of net production. Changes at the U.S. Gulf of Mexico include an increase of 2.9 MMBoe related to strong performance of certain fields and the Gladden Deep discovery, offset by net U.S. Gulf of Mexico production of 8.8 MMBoe.

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During the year ended December 31, 2019, we had an addition of 16.1 MMBoe of proved undeveloped reserves as a result of several factors, including updated original oil in place due to positive drilling results and improved static models in Jubilee and TEN, plans for one new well to be drilled in TEN and three new wells to be drilled in the Okume Complex.
We converted a total of 13.7 MMBoe of proved undeveloped reserves to proved developed due to completions of three new wells in Jubilee, two new wells in TEN, and three new wells in the U.S. Gulf of Mexico with a combined cost of $176.7 million. We spent $41.6 million to convert 4.0 MMBbl of proved undeveloped reserves in Jubilee and $12.8 million to convert 2.5 MMBoe proved undeveloped reserves in TEN; and $122.3 million spent to convert 7.2 MMBoe of proved undeveloped reserves in the U.S. Gulf of Mexico.
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 of 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 reserves in TEN incurring $9.7 million drilling a new well. We added 12.9 MMBbl of proved undeveloped reserves in Jubilee as a result of several factors, including additional data 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 the Mahogany area that is now part of the Greater Jubilee Unit. We incurred $27.2 million in drilling the two Jubilee wells, however, we note that we did not have a net migration of proved undeveloped reserves to proved developed reserves due to negative revisions in Jubilee proved developed reserves, which more than offset the effects of drilling two wells during the year.

Changes for the year ended December 31, 2017, include an increase of 15.6 MMBbl in Jubilee related to the approval of the 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.


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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, 2019. All estimated future net revenues are attributable to projected production from Ghana, Equatorial Guinea and the U.S. Gulf of Mexico. 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 could be adversely affected.
 
Estimated Future Net Revenues
 
(in millions except $/Bbl)
 
Ghana
Equatorial Guinea
Mauritania / Senegal(4)
U.S Gulf of Mexico
Total
Estimated future net revenues
$
3,127

$
575

$

$
1,500

$
5,202

Present value of estimated future net revenues:
 
 
 
 

PV-10(1)
$
2,103

$
526

$

$
1,184

$
3,813

Future income tax expense (levied at a corporate parent and intermediate subsidiary level)
(1,026
)
(317
)

$
(123
)
$
(1,466
)
Discount of future income tax expense (levied at a corporate parent and intermediate subsidiary level) at 10% per annum
349

85


38

472

Standardized Measure(2)
$
1,426

$
294

$

$
1,099

$
2,819

 
 
 
 
 
 
Benchmark Dated Brent oil price($/Bbl)(3)
 
 
 
 
$
62.69

Benchmark HLS oil price($/Bbl)(3)
 
 
 
 
$
61.31

Benchmark Henry Hub gas price($/MMBtu)(3)
 
 
 
 
$
2.58

______________________________________
(1)
PV‑10 represents the present value of estimated future revenues to be generated from the production of proved oil and natural gas reserves, net of future development and production costs, royalties, additional oil entitlements and future tax expense levied at an asset level, using prices based on an average of the first‑day‑of‑the‑months throughout 2019 and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non‑property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10% to reflect the timing of future cash flows. PV‑10 is a non‑GAAP financial measure and often differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of future income tax expense related to proved oil and gas reserves levied at a corporate parent level on future net revenues. However, it does include the effects of future tax expense levied at an asset level. Neither PV‑10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas assets. PV‑10 should not be considered as an alternative to the Standardized Measure as computed under GAAP; however, we and others in the industry use PV‑10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific corporate tax characteristics of such entities.
(2)
Standardized Measure represents the present value of estimated future cash inflows to be generated from the production of proved oil and natural gas reserves, net of future development and production costs, future income tax expense related to our proved oil and gas reserves levied at a corporate parent and intermediate subsidiary level, royalties, additional oil entitlements and future tax expense levied at an asset level, without giving effect to hedging activities, non‑property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10% to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV‑10. Standardized Measure often differs from PV‑10 because Standardized Measure includes the effects of future income tax expense related to our proved oil and gas reserves levied at a corporate parent level on future net revenues.
(3)
This amount represents the unweighted arithmetic average first‑day‑of‑the‑month prices for the prior 12 months at December 31, 2019 for the respective benchmark. The benchmark price was adjusted for handling fees, transportation fees, quality, and a regional price differential.
(4)
The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the company's independent reserve auditor Ryder Scott, LP.

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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, 2019, 2018 and 2017 has been prepared by RSC, our independent reserve engineering firm for such years, in accordance with the rules and regulations of the 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 in accordance with SEC rules for proved reserves.
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, 2019 are based on costs in effect at December 31, 2019 and the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the year ended December 31, 2019, 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, 2019, 2018 and 2017, 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, 2019, 2018 and 2017, 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, 2019, 2018 and 2017 and related future net revenues and PV‑10 at December 31, 2019, 2018 and 2017 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, 2019 reserve report was completed on January 13, 2020, and a copy is included as an exhibit to this report.
In connection with the preparation of the December 31, 2019, 2018 and 2017 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, 2019, 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.

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Technology used to establish proved reserves
Under the SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have proved effective by actual comparison of production from projects in the same reservoir interval, an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our estimated proved reserves, 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.

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Table of Contents

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, 2019 for the countries in which we currently operate.
 
Developed Area
 
Undeveloped Area
 
 
 
 
 
(Acres)
 
(Acres)
 
Total Area (Acres)
 
Gross
 
Net(1)
 
Gross
 
Net(1)
 
Gross
 
Net(1)
 
 
 
 
 
 
 
 
 
 
 
 
 
(In thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Ghana(2)
163

 
32

 
34

 
7

 
197

 
39

Cote d'Ivoire

 

 
4,143

 
1,865

 
4,143

 
1,865

Equatorial Guinea
65

 
26

 
2,355

 
1,292

 
2,420

 
1,318

Mauritania

 

 
4,944

 
1,383

 
4,944

 
1,383

Namibia

 

 
3,039

 
1,368

 
3,039

 
1,368

South Africa

 

 
1,712

 
770

 
1,712

 
770

Sao Tome and Principe(3)

 

 
8,524

 
3,159

 
8,524

 
3,159

Senegal

 

 
2,116

 
631

 
2,116

 
631

Suriname

 

 
2,793

 
1,142

 
2,793

 
1,142

U.S. Gulf of Mexico
92

 
26

 
338

 
211

 
430

 
237

Total
320

 
84

 
29,998

 
11,828

 
30,318

 
11,912

______________________________________
(1)
Net acreage based on Kosmos’ participating interests, before the exercise of any options or back‑in rights, except for our net acreage associated with the Jubilee, TEN, and Greater Tortue Ahmeyim fields, which are after the exercise of options or back‑in rights. Our net acreage in Ghana may be affected by any redetermination of interests in the Jubilee Unit and our net acreage in Mauritania and Senegal may be affected by any redetermination of interests in the Greater Tortue Ahmeyim Unit.
(2)
The Exploration Period of the WCTP petroleum contract and DT petroleum contract has expired. The undeveloped area reflected in the table above represents acreage within our discovery areas that were not subject to relinquishment on the expiry of the Exploration Period.
(3)
Formal withdrawal notice on STP Block 12 was communicated to partners on December 13, 2019 and will be effective January 31, 2020.

Productive Wells
Productive wells consist of producing wells and wells capable of production, including wells awaiting connections. For wells that produce both oil and gas, the well is classified as an oil well. The following table sets forth the number of productive oil and gas wells in which we held an interest at December 31, 2019:
 
Productive
 
Productive
 
 
 
 
 
Oil Wells
 
Gas Wells
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Ghana
46

 
10.08

 

 

 
46

 
10.08

Equatorial Guinea
82

 
33.13

 

 

 
82

 
33.13

U.S. Gulf of Mexico
21

 
5.93

 

 

 
21

 
5.93

Total(1)
149

 
49.14

 

 

 
149

 
49.14

______________________________________
(1)
Of the 149 productive wells, 37 (gross) or 8.70 (net) have multiple completions within the wellbore.

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Drilling activity
The results of oil and natural gas wells drilled and completed for each of the last three years were as follows:
 
Exploratory and Appraisal Wells(1)
 
Development Wells(1)
 
 
 
 
 
Productive(2)
 
Dry(3)
 
Total
 
Productive(2)
 
Dry(3)
 
Total
 
Total
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Year Ended December 31, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ghana

 

 

 

 

 

 
4

 
0.89

 

 

 
4

 
0.89

 
4

 
0.89

Equatorial Guinea

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S. Gulf of Mexico
2