10-K 1 kos-12312018x10k.htm 10-K Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10‑K
(Mark One)
 
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
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_logoa04.jpg
Kosmos Energy Ltd.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
98‑0686001
(I.R.S. Employer
Identification No.)
8176 Park Lane
Dallas, Texas
(Address of principal executive offices)
75231
(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
 
Name of each exchange on which registered:
Common Stock $0.01 par value
 
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 ý  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 ý
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý  No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý  No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, 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 ☐
(Do not check if a smaller reporting company)
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 ý
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 $1,954,943,075.
The number of the registrant’s Common Stock outstanding as of February 15, 2019 was 401,252,135.
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, 2018.
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, 2028 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.
“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.
“Boepd”
 
Barrels of oil equivalent per day.
“Bopd”
 
Barrels of oil per day.
“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.
“Dry hole” or "Unsuccessful well"
 
A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.
“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 and includes Last Twelve Months ("LTM") EBITDAX for any acquisitions and excludes LTM EBITDAX for any divestitures.
“E&P”
 
Exploration and production.
“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.

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“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 liquified natural gas.
“FPS”
 
Floating production system.
“FPSO”
 
Floating production, storage and offloading vessel.
“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.
“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.
"LNG"
 
Liquefied natural gas.
“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.
“MMcfd”
 
Million cubic feet per day of natural gas.
“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.
“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.

4


“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.
“Trap”
 
A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.
“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.

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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 greenhouse gas (“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;

6


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 and Sao Tome and Principe). Kosmos is listed on the New York Stock Exchange (“NYSE”) and London Stock Exchange ("LSE") and is traded under the ticker symbol KOS.
Kosmos was founded in 2003 to find oil in under‑explored or overlooked parts of West Africa. Members of the management team—who had previously worked together making significant discoveries and developing them in Africa, the Gulf of Mexico, and other areas—established the company on a single geologic concept that previously had been disregarded by others in the industry, the Late Cretaceous play systems in West Africa. In its relatively brief history the Company has successfully opened two new hydrocarbon basins through the discovery of the Jubilee field offshore Ghana in 2007 and the Greater Tortue Ahmeyim development (which includes the Ahmeyim and Guembeul-1 discoveries offshore Mauritania and Senegal in 2015 and 2016, respectively). Jubilee was one of the largest oil discoveries worldwide in 2007 and is considered one of the largest finds offshore West Africa during that decade. First oil production was delivered just 42 months after initial discovery, a record for a deepwater development in this water depth in West Africa. The Ahmeyim discovery was one of the largest natural gas discoveries worldwide in 2015 and is believed to be the largest ever gas discovery offshore West Africa.
Over the last two years, our business strategy has evolved to include production enhancing infill drilling and well work as well as infrastructure-led exploration. This strategic evolution was initially enabled by our acquisition of the Ceiba Field and Okume Complex assets offshore Equatorial Guinea in October 2017 together with access to surrounding exploration licenses, and bolstered by the September 2018 acquisition of Deep Gulf Energy (together with its subsidiaries "DGE"), a deepwater company operating in the U.S. Gulf of Mexico, which further enhanced our production, exploitation and infrastructure-led exploration capabilities.    

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

Our business strategy is designed to accomplish this mission by focusing on three key objectives: (1) maximize the value of our producing assets; (2) progress our discovered resources toward project sanction and into proved reserves, production, and cash flow through efficient appraisal and development; and (3) add new resources through a consistently active low cost exploration program. We are focused on increasing production, cash flows and reserves from our producing assets in Equatorial Guinea, Ghana, and the U.S. Gulf of Mexico. In Mauritania and Senegal, we are progressing our Greater Tortue Ahmeyim development with the objective of reaching first gas in the first half of 2022, as well as advancing our other discoveries towards a final investment decision. We also have a large inventory of leads and prospects in our exploration portfolio along the Atlantic Margins, both infrastructure-led and basin opening opportunities, which we plan to continue to mature for future drilling, providing us access to asymmetric growth potential in the coming years.
Grow cash flow, proved reserves and production through exploitation, development, infrastructure-led exploration and basin opening exploration activities
In the near term, we plan to grow cash flow, proved reserves and production by further exploiting our fields offshore Ghana, U.S. Gulf of Mexico, and Equatorial Guinea. In Ghana, we plan to continue drilling additional development and production wells at both the Jubilee and TEN fields in 2019. In the U.S. Gulf of Mexico we plan to continue infill drilling on existing fields, drilling infrastructure-led exploration targets, and progressing the development of the Nearly Headless Nick discovery via subsea tieback to existing infrastructure. In Equatorial Guinea our activity set is expanding beyond production optimization projects utilizing electrical submersible pumps to include infrastructure-led exploration which, if successful, can be brought online quickly via subsea tieback to existing infrastructure. In addition, we have sanctioned the first phase of the Greater Tortue Ahmeyim development offshore Mauritania and Senegal, which defines the timing and path to first gas. Beyond Greater Tortue Ahmeyim, growth could also be realized through the development of all or a portion of our other discoveries in Mauritania and Senegal. Our basin opening exploration efforts continue to be a significant portion of the portfolio. We believe the prospects and leads offshore Mauritania, Senegal, Sao Tome and Principe, Cote d'Ivoire, Namibia, and Suriname provide favorable opportunities to create

8


substantial future growth and value through exploration drilling. During 2019, we plan to further test the potential of previous discoveries in Mauritania and Senegal and drill five infrastructure-led prospects in Equatorial Guinea and the U.S. Gulf of Mexico. Given the potential size of these prospects and leads, we believe that exploratory and appraisal success in our operating areas could significantly add to our growth profile.
Focus on optimally developing our discoveries to initial production
Our approach to development is designed to deliver first production on an accelerated timeline, leverage early learnings to improve future outcomes and maximize returns. In certain circumstances, we believe a phased approach can be employed to optimize full‑field development. A phased approach facilitates refinement of the development plans based on experience gained in initial phases of production and by leveraging existing infrastructure as subsequent phases of development are implemented. Production and reservoir performance from the initial phases are monitored closely to determine the most efficient and effective techniques to maximize the recovery of reserves and returns. Other benefits include minimizing upfront capital costs, reducing execution risks through smaller initial infrastructure requirements, and enabling cash flow from the initial phases of production to fund a portion of capital costs for subsequent phases.
For example, post‑discovery in 2007, first oil production from the Jubilee Field commenced in November 2010. This development timeline from discovery to first oil was significantly less than the seven to ten year industry average and set a record for a deepwater development of this size and scale at this water depth in West Africa. This condensed timeline reflects the lessons learned by our experienced team while leading other large scale deepwater developments. The Greater Tortue Ahmeyim development is also expected to be developed in an accelerated, phased approach consistent with our business strategy. This is anticipated to result in first gas seven years after initial discovery, which feeds the market at a potentially optimal time as demand is expected to outpace supply.
Kosmos Exploration Approach - A balance of basin opening and infrastructure-led
Kosmos’ exploration philosophy, which is traditionally basin opening based, is deeply rooted in a fundamental, geologic approach geared toward the identification of under‑explored or overlooked petroleum systems. Once an area of interest has been identified, Kosmos targets licenses over the particular basin or fairway to achieve an early‑mover or in many cases a first‑mover advantage. In terms of license selection, Kosmos targets specific regions that have sufficient size to manage exploration risks and provide scale should the exploration concept prove successful. Kosmos also looks for: (i) long‑term contract durations to enable the “right” exploration program to be executed, (ii) play type diversity to provide multiple exploration concept options, (iii) prospect dependency to enhance the chance of replicating success, and (iv) sufficiently attractive fiscal terms to maximize the commercial viability of discovered hydrocarbons. This type of exploration provides the portfolio with access to asymmetric growth possibilities.
Alongside the subsurface analysis, Kosmos performs an analysis of country‑specific risks to gain an understanding of the “above‑ground” dynamics, which may influence a particular country’s relative desirability from an overall oil and natural gas operating and risk‑adjusted return perspective. This process is employed for all new areas and is a key strength of Kosmos.
Our exploration approach has evolved to include infrastructure-led exploration. This shorter-cycle approach, which can typically deliver first production in less than 18 months, is aimed at areas where we have existing production and where there is sufficient infrastructure capacity to enable the development of new discoveries via subsea tieback. Acquisitions of the Ceiba Field and Okume Complex in Equatorial Guinea together with access to surrounding exploration licenses and the DGE assets in the Gulf of Mexico have added to the inventory of infrastructure-led exploration given their attractive acreage positions within proximity of existing infrastructure that has excess capacity available. This opens a new growth area with attractive economics in areas with high margin production that complements the basin opening exploration program. It also allows shared learnings across the portfolio.
Build the right strategic partnerships with complementary capabilities
As a full-cycle E&P company, part of our strategy is to optimize our portfolio at appropriate times for our exploration and development projects. One of the ways to accomplish this is to partner with high-quality industry players with world‑class complementary capabilities. This strategy is designed to ensure that the relative project can benefit from specific expertise provided by these partners, including exploration, development, production and above-ground capabilities. We have proven we can execute this strategy by partnering with supermajors including BP PLC ("BP") and Royal Dutch Shell ("Shell") across our exploration portfolio. In addition, bringing in the right strategic partners early in our projects often comes with a financial carry on future expenditures, allowing us to reduce our costs and increase return on investment.

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For example, in 2017 we formed an alliance with a subsidiary of BP. This alliance broadened the relationship that previously covered new venture opportunities in Mauritania, Senegal and The Gambia to create an Atlantic Margin explorer-developer partnership. The alliance combines Kosmos' regional exploration knowledge and capability with BP's deepwater development expertise to execute a selective, basin opening exploration strategy in the Atlantic Margin.
During the fourth quarter of 2018, Kosmos entered into an additional strategic exploration alliance with a subsidiary of Shell to jointly explore in Southern West Africa. Initially, the alliance will focus on Namibia where Kosmos has completed a farm-in to Shell's acreage in PEL 39, and Sao Tome & Principe where we have entered into exclusive negotiations for Shell to take an interest in Kosmos’ acreage in Blocks 5, 6, 11 and 12. As part of the alliance, the two companies will also jointly evaluate opportunities in adjacent geographies. This alliance is consistent with Kosmos’ strategy of partnering with supermajors to leverage complementary skill sets. Shell has deep expertise in carbonate plays, while Kosmos brings significant knowledge of the Cretaceous in West Africa. Furthermore, by working with Shell, Kosmos has a partner with the expertise to efficiently move exploration successes through the development stage.
During the first quarter of 2019, Kosmos expanded its relationship with BP to grow Kosmos’ footprint in the deepwater U.S. Gulf of Mexico. The venture includes the evaluation of 18 jointly owned leases in the Garden Banks area and an opportunity to earn an interest in three additional blocks in other areas of the deepwater U.S. Gulf of Mexico. This transaction will allow both companies to leverage complementary skill sets to execute farm-in projects around infrastructure. Kosmos will be designated operator and plans to commence drilling operations on the first well in 2019.
During the first quarter of 2019, Kosmos executed a farm-in agreement with Chevron covering the right to earn an interest in a strategic block in the deepwater U.S. Gulf of Mexico. This agreement allows Kosmos another opportunity to execute its deepwater U.S. Gulf of Mexico strategy of lower risk prospects with the potential for subsea development near existing midstream infrastructure. Kosmos will be designated operator and plans to commence drilling operations in 2019.
Apply our entrepreneurial culture, which fosters innovation and creativity, to continue our successful exploration and development program
Our employees are critical to the success of our business strategy, and we have created an environment that enables them to focus their knowledge, skills and experience on finding, developing and producing new fields and optimizing production from existing fields. Culturally, we have an open, team‑oriented work environment that fosters entrepreneurial, creative and contrarian thinking. This approach enables us to fully consider and understand both risk and reward, as well as deliberately and collectively pursue ideas that create and maximize value and free cash flow.
Maintain Financial Discipline
Execution of our strategy requires us to maintain a conservative financial approach with a strong balance sheet, ample liquidity, a commitment to low leverage and the ability to maintain significant headroom on our debt covenants. Typically, we fund exploration and development activities from a combination of operating cash flows, debt and partner carries.
As of December 31, 2018, our net leverage ratio was just slightly over 2.0 times, largely the result of borrowing for the Gulf of Mexico acquisition. Our liquidity, after consideration of the additional RBL Facility commitments which became effective in January 2019, was approximately $0.6 billion available to fund our opportunities. When we do increase our net leverage as we did in 2018 with the U.S. Gulf of Mexico acquisition, we develop a well thought out plan to bring leverage back down.
Additionally, we use derivative instruments to partially limit our exposure to fluctuations in oil prices and interest rates. We have an active commodity hedging program where we aim to hedge a portion of our anticipated sales volumes on a two‑to‑three year rolling basis, with the goal to protect against the downside price scenario while still retaining partial exposure to the upside. As of December 31, 2018, we have hedged positions covering 15.6 million barrels of oil production from 2019 through 2020. We also maintain insurance to partially protect against loss of production revenues from our producing assets.

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


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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 U.S. Gulf of Mexico and Ghana. We also have an equity method investment generating revenues with operations offshore Equatorial Guinea. The following table provides a summary of certain key 2018 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
 
10.7

 
58
%
 
$
739,070

 
89.7

 
54
%
U.S. Gulf of Mexico(2)
 
2.6

 
14

 
147,596

 
51.1

 
30

Total Kosmos
 
13.3

 

 
886,666

 
140.8

 

Equatorial Guinea(3)
 
5.2

 
28

 
360,650

 
26.6

 
16

Total
 
18.5

 
100
%
 
1,247,316

 
167.4

 
100
%
______________________________________
(1)
For information concerning our estimated proved reserves as of December 31, 2018, see “—Our Reserves.”
(2)
Represents contributions from the U.S. Gulf of Mexico after the acquisition date.
(3)
Includes our 50% share from our equity method investment in Equatorial Guinea. Under the equity method of accounting, we only recognize our share of the net income of KTIPI as adjusted for our basis differential, which is recorded in (Gain) loss on equity method investments, net in the consolidated statement of operations. Effective as of January 1, 2019, our equity method investment in Equatorial Guinea was converted to an undivided interest in Block G.

11



Information about our deepwater fields is summarized in the following table.
 
 
 
 
 
 
Kosmos
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Participating
 
 
 
 
 
 
 
 
 
License
 
Fields
 
License
 
    
 
Interest
 
 
 
Operator
 
 
 
Stage
 
Expiration
 
Ghana(1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jubilee
 
WCTP/DT
 
(2)
 
24.1
%
 
(2)
 
Tullow
 
 
 
Production
 
2034
 
TEN
 
DT
 
 
 
17.0
%
 
(4)
 
Tullow
 
 
 
Production
 
2036
 
U.S. Gulf of Mexico(1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Barataria
 
MC 521
 
 
 
22.5
%
 
 
 
Kosmos
 
 
 
Production
 
(10)
 
Big Bend
 
MC 697 / 698 / 742
 
 
 
5.3
%
 
 
 
Fieldwood
 
 
 
Production
 
(10)
 
Don Larsen
 
EB 598
 
 
 
20.0
%
 
 
 
Anadarko
 
 
 
Production
 
(10)
 
Gladden
 
MC 800
 
 
 
20.0
%
 
 
 
W&T
 
 
 
Production
 
(10)
 
Kodiak
 
MC 727 / 771
 
 
 
29.1
%
 
 
 
Kosmos
 
 
 
Production
 
(10)
 
Marmalard
 
MC 255 / 300
 
 
 
11.8
%
 
 
 
LLOG
 
 
 
Production
 
(10)
 
Nearly Headless Nick
 
MC 387
 
 
 
22.0
%
 
 
 
LLOG
 
 
 
Development
 
(10)
 
Danny Noonan
 
EC 381
GB 463 / 506
 
 
 
Various

 
(5)
 
Talos
 
 
 
Production
 
(10)
 
Odd Job
 
MC 214 / 215
 
 
 
Various

 
(6)
 
Kosmos
 
 
 
Production
 
(10)
 
Sargent
 
GB 339
 
 
 
50.0
%
 
 
 
Kosmos
 
 
 
Production
 
(10)
 
SOB II
 
MC 431
 
 
 
11.8
%
 
 
 
LLOG
 
 
 
Production
 
(10)
 
S. Santa Cruz
 
MC 563
 
 
 
40.5
%
 
 
 
Kosmos
 
 
 
Production
 
(10)
 
Tornado
 
GC 281
 
 
 
35.0
%
 
 
 
Talos
 
 
 
Production
 
(10)
 
Mauritania
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Tortue Ahmeyim
 
Block C8
 
(3)
 
29.0
%
 
(7)
 
BP
 
 
 
Development
 
2049
(11)
Marsouin
 
Block C8
 
 
 
28.0
%
 
(7)
 
BP
 
 
 
Appraisal
 
2019
(12)
Senegal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greater Tortue Ahmeyim
 
Saint Louis Offshore Profond
 
(3)
 
29.0
%
 
(8)
 
BP
 
(8)
 
Development
 
2044
(11)
Teranga
 
Cayar Offshore Profond
 
 
 
30.0
%
 
(8)
 
BP
 
(8)
 
Appraisal
 
2021
 
Yakaar
 
Cayar Offshore Profond
 
 
 
30.0
%
 
(8)
 
BP
 
(8)
 
Appraisal
 
2021
 
Equatorial Guinea(1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ceiba Field and Okume Complex
 
Block G
 
 
 
40.4
%
 
(9)
 
Trident
 
(9)
 
Production
 
2034
 
______________________________________
(1)
For information concerning our estimated proved reserves as of December 31, 2018, see “—Our Reserves.”
(2)
The Jubilee Field straddles the boundary between the West Cape Three Points (“WCTP”) petroleum contract and the Deepwater Tano (“DT”) petroleum contract offshore Ghana. To optimize resource recovery in this field, we entered into the Unitization and Unit Operating Agreement (the “Jubilee UUOA”) in July 2009 with the Ghana National Petroleum Corporation (“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 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 a Unitization and Unit Operating Agreement ("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 areas.
(4)
Our paying interest on development activities in the TEN fields is 19%.


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(5)
Our interests in blocks EC 381, GB 463 and GB 506 are 30%, 15% and 30%, respectively.

(6)
Our interests in blocks MC 214 and MC 215 are 61.1% and 54.9%, respectively.

(7)
SMHPM has the option to acquire up to an additional 4% paying interests in a commercial development on Block C8. These interest percentages do not give effect to the exercise of such option.

(8)
PETROSEN has the option to acquire up to an additional 10% paying interests 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.

(9)
Kosmos owned a 50% interest in KTIPI which held an 85% interest in the Ceiba Field and Okume Complex through its wholly-owned subsidiary, Kosmos-Trident Equatorial Guinea Inc. ("KTEGI"), representing a 40.375% net indirect interest to Kosmos. Kosmos and Trident provided operational management and support to KTEGI, who is operator of the Ceiba Field and Okume Complex. Effective January 1, 2019, our outstanding shares in KTIPI were transferred to Trident Energy ("Trident") in exchange for a 40.375% undivided interest in the Ceiba Field and Okume Complex and Trident became the operator. As a result, our interest in the Ceiba Field and Okume Complex will be accounted for under the proportionate consolidation method of accounting going forward.

(10)
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.

(11)
License expiration date can be extended by an additional ten years subject to certain conditions being met.

(12)
License expiration date can be extended beyond the current exploration period upon completion of required work program and subject to additional work obligations.

Exploration License and Lease Areas
 
 
 
 
Kosmos Average
 
 
 
 
 
License
 
 
 
Number of
 
Participating
 
 
 
 
 
Expiration
 
Country
 
Blocks
 
Interest
 
    
 
Operator(s)
 
Range
 
Cote D'Ivoire
 
5
 
45.0%
 
(1)
 
Kosmos
 
2020
(8)
Equatorial Guinea
 
4
 
40.0%
 
(2)
 
Kosmos
 
2020-2021
(8)
Mauritania
 
5
 
25.4%
 
(3)
 
BP, Total
 
2019-2020
(8)
Namibia
 
1
 
45.0%
 
(4)
 
Shell
 
2019
(8)
Sao Tome and Principe
 
6
 
45.0%
 
(5)
 
Kosmos, BP, Galp
 
2019-2022
(8)
Senegal
 
2
 
30.0%
 
(6)
 
BP
 
2020-2021
 
Suriname
 
2
 
41.7%
 
(7)
 
Kosmos
 
2020-2021
(8)
U.S. Gulf of Mexico
 
22
 
54.0%
 
 
 
Kosmos, Chevron, LLOG, Murphy
 
2019-2028
(9)
______________________________________
(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 acquire a participating interest in the discovery area between 10% and 14% (blocks C8, C12 and C13), 10% and 15% (Block C18) 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 participating interest during the exploration period may continue through first commercial production but must be reimbursed through production.

13


(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.
(6)
PETROSEN has the option to acquire 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)
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.
(8)
License expiration date can be extended beyond the current exploration period upon completion of required work program and subject to additional work obligations.
(9)
Our U.S. Gulf of Mexico blocks can be held by continued operations, and the lease periods extend as long as governmental approved operations continue on the relevant block.

Ghana
The WCTP Block and DT Block are located within the Tano Basin, offshore Ghana. This basin contains a proven world‑class petroleum system as evidenced by our discoveries. The following is a brief discussion of our discoveries on our license areas offshore Ghana.
Jubilee Field
The Jubilee Field was discovered by Kosmos in 2007, with first oil produced in November 2010. Appraisal activities confirmed that the Jubilee discovery straddled the WCTP and DT Blocks. Pursuant to the terms of the Jubilee UUOA, the discovery area was unitized for purposes of joint development by the WCTP and DT Block partners.
The Jubilee Field is located approximately 60 kilometers offshore Ghana in water depths of approximately 1,000 to 1,800 meters, which led to the decision to implement an FPSO based development. The FPSO is designed to provide water and natural gas injection to support reservoir pressure, to process and store oil and to export gas through a pipeline to the mainland. The Jubilee Field is being developed in a phased approach. The initial phase provided subsea infrastructure capacity for additional production and injection wells to be drilled in future phases of development.
The GJFFDP was approved by the Government of Ghana in October 2017. This plan, which is expected to increase proved reserves and extend the field production profile, has been optimized to reduce overall capital expenditures to reflect the current oil price market. In November 2015, we signed the Jubilee Field Unit Expansion Agreement with our partners, which became effective upon approval of the GJFFDP, to allow for the development of the Mahogany and Teak discoveries through the Jubilee FPSO and infrastructure, thus reducing their development cost. As a result of the approval of the GJFFDP by the Ministry of Energy in October 2017, operatorship for the Mahogany and Teak discoveries transferred to Tullow. The WCTP partners transferred operatorship of the remaining portions of the WCTP Block, including the Akasa discovery, to Tullow effective February 1, 2018.
The Government of Ghana completed the construction and connection of a gas pipeline in 2017 from the Jubilee Field to transport natural gas to the mainland for processing and sale. In the absence of continuous export of large quantities of natural gas from the Jubilee Field, it is anticipated that we will need to reinject or flare such natural gas. Our inability to continuously export associated natural gas in large quantities from the Jubilee Field could impact our oil production.
In February 2016, the Jubilee Field operator identified an issue with the turret bearing of the FPSO Kwame Nkrumah. Kosmos and its partners completed the lifting and locking of the main turret bearing, and the rotation of the vessel to its final heading in the second half of 2018. Permanent spread mooring of the vessel is expected to be completed around mid-year 2019.
The financial impact of lower Jubilee production as well as the additional expenditures associated with the damage to the turret bearing is mitigated through a combination of the comprehensive Hull and Machinery insurance (“H&M”), procured by the operator, Tullow, on behalf of the Jubilee Unit partners, and the corporate Loss of Production Income (“LOPI”) insurance procured by Kosmos. Our LOPI coverage for this incident ended in May 2017 and the final cash proceeds were received in August 2017. Oil production from the Jubilee Field averaged approximately 78,000 Bopd gross (18,800 Bopd net) during 2018.

14


Tweneboa, Enyenra and Ntomme ("TEN")
The TEN fields are located in the western and central portions of the DT Block, approximately 48 kilometers offshore Ghana in water depths of approximately 1,000 to 1,700 meters. In November 2012, we submitted a declaration of commerciality and PoD over the TEN discoveries, and in May 2013, the government of Ghana approved the TEN PoD. The discoveries are being jointly developed with shared infrastructure and a single FPSO, the Professor John Evans Atta Mills.
Similar to Jubilee, the TEN fields are being developed in a phased manner. The TEN PoD was designed to include an expandable subsea system that would provide for multiple phases. Phase 1 of the TEN PoD includes the drilling and completion of up to 17 wells, 13 of which have been completed. Seven additional development wells are expected to be drilled during Phase 2. The remaining Phase 1 and Phase 2 wells are a combination of production wells and water or gas injection wells needed to maximize recovery.
First oil from the TEN fields was produced in August 2016. In January 2017, the capacity of the FPSO was successfully tested at an average rate of 80,000 Bopd during a short-term flow test. In September 2017, International Tribunal of the Sea issued its final decision in the previously disclosed maritime boundary dispute between the Governments of Ghana and Cote d'Ivoire, which allowed drilling to resume in early 2018. These additional wells are expected to increase production towards FPSO capacity. Production from TEN in the year ended December 31, 2018 averaged approximately 64,500 Bopd gross (10,400 Bopd net).
The construction and connection of a gas pipeline between the Jubilee and TEN fields to transport natural gas to the mainland for processing and sale was completed in the first quarter of 2017. In December 2017, we signed the TEN Associated-Gas - Gas Sales Agreement ("TAG GSA") and we commenced exporting gas to shore in the fourth quarter of 2018. However, the uptime of the gas processing facility in future periods is unknown. Our inability to continuously export associated natural gas in large quantities from the TEN fields could impact our oil production.

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

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

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

Tornado

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


15


Marmalard

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

Kodiak

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

South Santa Cruz / Barataria

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

Mauritania
The C6, C8, C12, C13 and C18 blocks are located on the western margin of the Mauritania Salt Basin offshore Mauritania and range in water depths from 100 to 3,000 meters. These blocks are located in a proven petroleum system, with our primary targets being Cretaceous sands in structural and stratigraphic traps. Interpretation of available geologic and geophysical data has identified Cretaceous slope channels and basin floor fans in trapping geometries outboard of the Salt Basin as the key exploration objective. Multiple Cretaceous source rocks penetrated by wells and typed to oils and gases in the Mauritania Salt Basin are the same age as those which charge other oil and gas fields in West Africa.
These blocks cover an aggregate area of approximately 6.0 million acres (gross). We have acquired approximately 6,300 line-kilometers of 2D seismic data and 15,800 square kilometers of 3D seismic data covering portions of our blocks in Mauritania. Based on these 2D and 3D seismic programs, we have drilled two successful exploration wells and an appraisal well, and have identified additional prospects in our blocks. We continue to integrate the results of our drilling program in Mauritania.
Senegal
The Senegal Blocks are located in the Senegal River Cretaceous petroleum system and range in water depth from 300 to 3,100 meters. The area is an extension of the working petroleum system in the Mauritania Salt Basin. We believe the area has multiple Cretaceous source rocks with Albian through Cenomanian reservoir sands providing exploration targets. We acquired approximately 7,000 square kilometers of 3D seismic data over the central and eastern portions of the Senegal Blocks in January 2015. In February 2016, we completed a 4,500 square kilometer survey over the western portions of the Senegal Blocks to fully evaluate the prospectivity. We have drilled two successful exploration wells and an appraisal well, and have identified additional prospects in our blocks.
The following is a brief discussion of our discoveries to date offshore Mauritania and Senegal.
Greater Tortue Ahmeyim Development
The Ahmeyim and Guembeul discoveries (collectively “Greater Tortue Ahmeyim”) are significant, play-opening gas discoveries for the outboard Cretaceous petroleum system and are located approximately 120 kilometers offshore Mauritania and Senegal. The Greater Tortue Ahmeyim development straddles Block C8 offshore Mauritania and Saint Louis Offshore Profond offshore Senegal.
We have drilled three wells within the Greater Tortue Ahmeyim development, Tortue-1, Guembeul-1 and Ahmeyim-2. The wells penetrated multiple excellent quality gas reservoirs, including the Lower Cenomanian, Upper Cenomanian and underlying Albian. The wells successfully delineated the Ahmeyim and Guembeul gas discoveries and demonstrated reservoir continuity, as well as static pressure communication between the three wells drilled within the Lower Cenomanian reservoir. The discovery ranges in water depths from approximately 2,700 meters to 2,800 meters, with total depths drilled ranging from approximately 5,100 meters to 5,250 meters.

16


The Tortue-1 discovery well, located in Block C8 offshore Mauritania, intersected approximately 117 meters of net hydrocarbon pay. A single gas pool was encountered in the Lower Cenomanian objective, which is comprised of three reservoirs totaling 88 meters in thickness over a gross hydrocarbon interval of 160 meters. A fourth reservoir totaling 19 meters was penetrated within the Upper Cenomanian target over a gross hydrocarbon interval of 150 meters. The exploration well also intersected an additional 10 meters of net hydrocarbon pay in the lower Albian section, which is interpreted to be gas.
The Guembeul-1 discovery well, located in the northern part of the Saint Louis Offshore Profond area in Senegal, is located approximately five kilometers south of the Tortue-1 exploration well in Mauritania. The well encountered 101 meters of net gas pay in two excellent quality reservoirs, including 56 meters in the Lower Cenomanian and 45 meters in the underlying Albian, with no water encountered.
The Ahmeyim-2 appraisal well is located in Block C8 offshore Mauritania, approximately five kilometers northwest, and 200 meters down-dip of the basin-opening Tortue-1 discovery. The well confirmed significant thickening of the gross reservoir sequences down-dip. The Ahmeyim-2 well encountered 78 meters of net gas pay in two excellent quality reservoirs, including 46 meters in the Lower Cenomanian and 32 meters in the underlying Albian.
In August 2017, we completed the drill stem test ("DST") of the Tortue-1 well, demonstrating that the Tortue field is a world-class resource and confirming key development parameters including well deliverability, reservoir connectivity, and fluid composition. The Tortue-1 well flowed at a sustained, equipment-constrained rate of approximately 60 MMcfd during the main extended flow period, with minimal pressure drawdown, providing confidence in well designs that are each capable of producing approximately 200 MMcfd. The DST results confirmed a connected volume per well consistent with the current development scheme, which together with the high well rate is expected to result in a low number of development wells compared to equivalent schemes. Initial analysis of fluid samples collected during the test indicate Tortue gas is well suited for liquefaction given low levels of liquids and minimal impurities. Data acquired from the DST was used to further optimize field development and to refine process design parameters critical to the front end engineering and design ("FEED") process.

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

Other Mauritania and Senegal Discoveries
The BirAllah discovery (formally known as Marsouin), located in Block C8 offshore Mauritania, is a significant, play-extending gas discovery, building on our successful exploration program in the outboard Cretaceous petroleum system offshore Mauritania. The Marsouin-1 well is located approximately 60 kilometers north of the Ahmeyim discovery and was drilled to a total depth of 5,150 meters in nearly 2,400 meters of water. Based on analysis of drilling results and logging data, Marsouin-1 encountered at least 70 meters of net gas pay in Upper and Lower Cenomanian intervals comprised of excellent quality reservoir sands.
The Teranga discovery is located in the Cayar Offshore Profond block approximately 65 kilometers northwest of Dakar, and was our second exploration well offshore Senegal. The Teranga-1 discovery well is located in nearly 1,800 meters of water and was drilled to a total depth of approximately 4,850 meters. The well encountered 31 meters of net gas pay in good quality reservoir in the Lower Cenomanian objective. Well results confirm that a prolific inboard gas fairway extends approximately 200 kilometers south from the Marsouin-1 well in Mauritania through the Greater Tortue Ahmeyim area on the maritime boundary to the Teranga-1 well in Senegal.
The Yakaar discovery is located in the Cayar Offshore Profond block offshore Senegal, approximately 95 kilometers northwest of Dakar in approximately 2,600 meters of water. The Yakaar-1 discovery well was drilled to a total depth of approximately 4,900 meters. The well intersected a gross hydrocarbon column of 120 meters in three pools within the primary Lower Cenomanian objective and encountered 45 meters of net pay. An appraisal well is planned in 2019.

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

17


2023. The first exploration period consists of two sub-periods of three and two years, respectively. The first exploration sub-period work program included an approximately 6,000 square kilometer 3D seismic acquisition requirement across the blocks, which was completed in November 2018.
 
In June 2018, we closed a farm-in agreement with a subsidiary of Ophir Energy plc ("Ophir") for Block EG-24, offshore Equatorial Guinea, whereby we acquired a 40% non-operated participating interest. As part of the agreement, we reimbursed a portion of Ophir's previously incurred exploration costs and will fully carry Ophir's share of the costs of a planned 3D seismic program as well as pay a disproportionate share of the well commitment should we enter the second exploration sub-period. The petroleum contract covers approximately 3,500 square kilometers, with a first exploration period of three years from the effective date (March 2018) which can be extended up to four additional years at our election subject to fulfilling specific work obligations. The first exploration period work program includes a 3,000 square kilometer 3D seismic acquisition requirement, which was completed in November 2018. In January 2019, we entered into an agreement to acquire Ophir's remaining interest in and operatorship of the block, subject to customary governmental approvals, which will result in Kosmos owning an 80% interest in Block EG-24. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest for all development and production operations.

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

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

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

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

Suriname
We are the operator for petroleum contracts covering Block 42 and Block 45 offshore Suriname, which are located within the Guyana Suriname Basin, along the Atlantic transform margin of northern South America. Suriname lies between Guyana to the west and French Guyana to the east. The Guyana-Suriname Basin was formed by tensional forces associated with the opening of the Atlantic Ocean as South America separated from Africa in the Mid Cretaceous period. The Suriname basin is analogous to the working petroleum systems of the West African transform margin. The emerging petroleum system in Suriname has been proven by the presence of onshore producing fields and most recently by nearby discoveries offshore Guyana, including the Liza-1 well.
Suriname Block 42 and Block 45 are positioned centrally in the Suriname-Guyana Basin, and located to the east of the recent play opening Liza-1 oil discovery. Likewise, the blocks are also positioned to the northwest of the French Guyana Basins’ Zaedyus oil discovery.
We believe that there are several independent play types of importance on our operated blocks. Of note are the listric faulted structural stratigraphic play of the Lower Cretaceous and the stratigraphically trapped Upper Cretaceous plays similar to

18


those discovered in the Jubilee Field offshore West Africa. The recent oil discovery in Guyana (Liza-1) in the same geologic basin provides a positive point of calibration for the Upper Cretaceous stratigraphic play in Suriname. 
The Tambaredjo and Calcutta Fields onshore Suriname, as well as the Liza-1 well discovery offshore Guyana, demonstrate that a working petroleum system exists, and geological and geochemical studies suggest the hydrocarbons in these fields were generated from source rocks located in the offshore basin. The source rocks are believed to be analogous in age to those which have charged numerous fields in offshore West Africa.
In June 2018, the Anapai-1A exploration well was drilled to a total depth of approximately 4,600 meters and was designed to test lower Cretaceous reservoirs in a structural trap on the flank of the basin. The prospect was fully tested, encountering high quality reservoirs in the targeted zones, but did not find hydrocarbons. The well has been plugged and abandoned.

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

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

The well results are being integrated into the ongoing evaluation of the remaining prospectivity in our Suriname acreage position.
Sao Tome and Principe
During 2015 and 2016, Kosmos acquired acreage in Blocks 5, 6, 11 and 12 offshore Sao Tome and Principe in the Gulf of Guinea. We are the operator of Blocks 5, 11 and 12, and Galp Energia Sao Tome E Principe, Unipessoal, LDA (“Galp”), a wholly-owned subsidiary of Petrogal, S.A., is the operator of Block 6. In March 2018, as part of our alliance with BP, we entered into petroleum contracts covering Blocks 10 and 13 with the Democratic Republic of Sao Tome and Principe. We presently have a 35% participating interest in the blocks and the operator, BP, holds a 50% participating interest. The national petroleum agency, Agencia Nacional Do Petroleo De Sao Tome E Principe ("ANP STP") has a 15% carried interest in the blocks through exploration. These blocks cover an area of approximately 5.9 million acres (gross) in water depths ranging from 2,250 to 3,000 meters and provide an opportunity to pursue the same core Cretaceous theme that was successful for us in Ghana.
Our blocks are adjacent to, and represent an extension of, a proven and prolific petroleum system offshore Equatorial Guinea and northern Gabon comprising Early Cretaceous post-rift source rocks and Late Cretaceous reservoirs. Kosmos has established an extensive position in the Rio Muni Basin where there is a proven source and reservoir inboard with the Ceiba and Okume discoveries in Equatorial Guinea, which appears to extend outboard into the deepwater in Sao Tome and Principe, where there are oil seeps on both islands. Kosmos has identified large potential structural and stratigraphic traps on early seismic, which is currently being processed.
We believe that the southern extent of the West African transform margin in Sao Tome and Principe comprises a series of Albian pull-apart basins formed during the separation of Africa from South America, providing the necessary conditions for the generation, migration and entrapment of hydrocarbons. Large sandstone depo-centers were developed at the structural junctions of rift and shear fault trends resulting in the deposition of deep-water slope channels and basin floor fans draping over and around anticlinal highs adjacent to fracture zones. These constitute the main play in the acreage.
In December 2016, we received approval for a two-year extension of Phase 1 for Block 5 offshore Sao Tome and Principe, which now expires in May 2019. Additionally, during the same month we assigned 20% participating interest to Galp in each of Blocks 5, 11 and 12 offshore Sao Tome and Principe. Based on the terms of the agreement, Galp has paid a proportionate share of Kosmos’ past costs in the form of a partial carry on the 3D seismic survey.
In August 2017, we completed a 3D seismic survey of approximately 15,800 square kilometers over Blocks 5, 6, 11, and 12 offshore Sao Tome and Principe. Processing has been completed. We are compiling an inventory of prospects on the license areas in Sao Tome and Principe and will continue to refine and assess the prospectivity, integrating this new 3D seismic data into our geological evaluation during 2019 with a view to drilling as early as 2020.

19


In November 2017, we received approval for a one-year extension of Phase 1 for Block 11 offshore Sao Tome and Principe, which now expires in July 2019.
Morocco
In August 2018, we provided to the Office National Des Hydrocarbures et des Mines ("ONHYM") a notice to abandon the Essaouira Offshore block, located offshore Morocco, at the end of the then current exploration phase (November 2018).

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

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

Our Reserves
The following table sets forth summary information about our estimated proved reserves as of December 31, 2018. See “Item 8. Financial Statements and Supplementary Data—Supplemental Oil and Gas Data (Unaudited)” for additional information.
Our estimated proved reserves as of December 31, 2018, were associated with our Jubilee and the TEN fields in Ghana and the U.S. Gulf of Mexico as well as our share of our equity method investment in the Ceiba Field and Okume Complex in Equatorial Guinea. Our estimated proved reserves as of December 31, 2017, were associated with our Jubilee and the TEN fields in Ghana as well as our share of our equity method investment in the Ceiba Field and Okume Complex in Equatorial Guinea. Our estimated proved reserves as of December 31, 2016 were associated with our Jubilee and TEN fields in Ghana.
Summary of Oil and Gas Reserves
 
2018 Net Proved Reserves(1)
 
2017 Net Proved Reserves(1)
 
2016 Net Proved Reserves(1)
 
Oil,
Condensate,
NGLs
 
Natural
Gas(2)
 
Total
 
Oil,
Condensate,
NGLs
 
Natural
Gas(2)
 
Total
 
Oil,
Condensate,
NGLs
 
Natural
Gas(2)
 
Total
 
(MMBbl)
 
(Bcf)
 
(MMBoe)
 
(MMBbl)
 
(Bcf)
 
(MMBoe)
 
(MMBbl)
 
(Bcf)
 
(MMBoe)
Reserves Category
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved developed
82

 
57

 
91

 
59

 
38

 
65

 
64

 
13

 
66

Proved undeveloped(3)
45

 
28

 
50

 
23

 
11

 
24

 
10

 
2

 
11

Total Kosmos
127

 
85

 
141

 
82

 
49

 
89

 
74

 
15

 
77

Equity method investment(4)
24

 
14

 
27

 
19

 
13

 
21

 
 
 
 
 
 
Total reserves
151

 
99

 
167

 
100

 
61

 
110

 
 
 
 
 
 
______________________________________
(1)
Our reserves associated with the Jubilee Field are based on the 54.4%/45.6% redetermination split, between the WCTP Block and DT Block. Totals within the table may not add as a result of rounding.

20


(2)
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 TEN Associated-Gas Gas Sales Agreement ("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.
(3)
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.
(4)
We disclose our share of reserves that are accounted for by the equity method.

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

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

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

21


The following table sets forth the estimated future net revenues, excluding derivatives contracts, from net proved reserves and the expected benchmark prices used in projecting net revenues at December 31, 2018. All estimated future net revenues are attributable to projected production from Ghana, the U.S. Gulf of Mexico and our equity method investment in Equatorial Guinea. If we are unable to export associated natural gas in large quantities from the Jubilee and TEN fields then production could be limited and the future net revenues discussed herein will be adversely affected.
 
Estimated Future Net Revenues(4)
 
(in millions except $/Bbl)
 
Kosmos
 
Equity Method Investment
 
Total
 
 
 
 
 
 
Estimated future net revenues
$
5,487

 
$
774

 
$
6,261

Present value of estimated future net revenues:
 
 
 
 
 
PV-10(1)
$
3,928

 
$
705

 
$
4,633

Future income tax expense (levied at a corporate parent and intermediate subsidiary level)
(1,431
)
 
(416
)
 
(1,847
)
Discount of future income tax expense (levied at a corporate parent and intermediate subsidiary level) at 10% per annum
413

 
102

 
515

Standardized Measure(2)
$
2,910

 
$
391

 
$
3,301

 
 

 
 
 
 
Benchmark Dated Brent oil price($/Bbl)(3)
 
 
 
 
$
71.54

Benchmark HLS oil price($/Bbl)(3)
 
 
 
 
$
70.20

Benchmark Henry Hub gas price($/MMBtu)(3)
 
 
 
 
$
3.10

______________________________________
(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 2018 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, 2018 for the respective benchmark. The benchmark price was adjusted for handling fees, transportation fees, quality, and a regional price differential.

22


(4)
Future net revenues and PV-10 have been adjusted from the reserve report which is based on the entitlements method as we account for oil and gas revenues under the sales method of accounting.
Estimated proved reserves
Unless otherwise specifically identified in this report, the summary data with respect to our estimated net proved reserves for the years ended December 31, 2018, 2017 and 2016 has been prepared by Ryder Scott Company, L.P. (“RSC”), our independent reserve engineering firm for such years, in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to companies involved in oil and natural gas producing activities. These rules require SEC reporting companies to prepare their reserve estimates using reserve definitions and pricing based on 12‑month historical unweighted first‑day‑of‑the‑month average prices, rather than year‑end prices. For a definition of proved reserves under the SEC rules, see the “Glossary and Selected Abbreviations.” For more information regarding our independent reserve engineers, please see “—Independent petroleum engineers” below.
Our estimated proved reserves and related future net revenues, PV‑10 and Standardized Measure were determined using index prices for oil, without giving effect to derivative transactions, and were held constant throughout the life of the assets.
Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations at December 31, 2018 are based on costs in effect at December 31, 2018 and the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the year ended December 31, 2018, adjusted for anticipated market premium, without giving effect to derivative transactions, and are held constant throughout the life of the assets. There can be no assurance that the proved reserves will be produced within the periods indicated or prices and costs will remain constant.
Independent petroleum engineers
Ryder Scott Company, L.P.
RSC, our independent reserve engineers for the years ended December 31, 2018, 2017 and 2016, was established in 1937. For over 80 years, RSC has provided services to the worldwide petroleum industry that include the issuance of reserves reports and audits, appraisal of oil and gas properties including fair market value determination, reservoir simulation studies, enhanced recovery services, expert witness testimony, and management advisory services. RSC professionals subscribe to a code of professional conduct and RSC is a Registered Engineering Firm in the State of Texas.
For the years ended December 31, 2018, 2017 and 2016, we engaged RSC to prepare independent estimates of the extent and value of the proved reserves of certain of our oil and gas properties. These reports were prepared at our request to estimate our reserves and related future net revenues and PV‑10 for the periods indicated therein. Our estimated reserves at December 31, 2018, 2017 and 2016 and related future net revenues and PV‑10 at December 31, 2018, 2017 and 2016 are taken from reports prepared by RSC, in accordance with petroleum engineering and evaluation principles which RSC believes are commonly used in the industry and definitions and current regulations established by the SEC. The December 31, 2018 reserve report was completed on January 13, 2019, and a copy is included as an exhibit to this report.
In connection with the preparation of the December 31, 2018, 2017 and 2016 reserves report, RSC prepared its own estimates of our proved reserves. In the process of the reserves evaluation, RSC did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of RSC which brought into question the validity or sufficiency of any such information or data, RSC did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. RSC independently prepared reserves estimates to conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4‑10(a)(2) of Regulation S‑X. RSC issued a report on our proved reserves at December 31, 2018, based upon its evaluation. RSC’s primary economic assumptions in estimates included an ability to sell hydrocarbons at their respective adjusted benchmark prices and certain levels of future capital expenditures. The assumptions, data, methods and precedents were appropriate for the purpose served by these reports, and RSC used all methods and procedures as it considered necessary under the circumstances to prepare the report.

23


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.

24


Gross and Net Undeveloped and Developed Acreage
The following table sets forth certain information regarding the developed and undeveloped portions of our license and lease areas as of December 31, 2018 for the countries in which we currently operate.
 
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(3)

 

 
2,355

 
942

 
2,355

 
942

Mauritania

 

 
9,275

 
2,172

 
9,275

 
2,172

Namibia

 

 
3,039

 
1,368

 
3,039

 
1,368

Sao Tome and Principe

 

 
9,255

 
4,270

 
9,255

 
4,270

Senegal

 

 
2,116

 
635

 
2,116

 
635

Suriname

 

 
2,793

 
1,142

 
2,793

 
1,142

U.S. Gulf of Mexico
127

 
35

 
131

 
70

 
258

 
105

Total Kosmos
290

 
67

 
33,141

 
12,471

 
33,431

 
12,538

Equity method investment(4)
65

 
28

 

 

 
65

 
28

Total
355

 
95

 
33,141

 
12,471

 
33,496

 
12,566

______________________________________
(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 and TEN 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.
(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)
In January 2019, we entered into an agreement to acquire Ophir's remaining interest in the block, subject to customary governmental approvals, which will result in Kosmos owning an 80% interest in Block EG-24. After completion of this transaction, our net acreage in Equatorial Guinea will be 1,292 thousand acres.
(4)
Represents our 50% interest in KTIPI. Effective as of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.375% undivided interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex will be accounted for under the proportionate consolidation method of accounting going forward.

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, 2018:

25


 
Productive
 
Productive
 
 
 
 
 
Oil Wells
 
Gas Wells
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Ghana
41

 
9.00

 

 

 
41

 
9.00

U.S. Gulf of Mexico
17

 
3.02

 

 

 
17

 
3.02

Kosmos Total(1)
58

 
12.02

 

 

 
58

 
12.02

Equity Method Investment(2)(3)
96

 
38.78

 

 

 
96

 
38.78

Total
154

 
50.80

 

 

 
154

 
50.80

______________________________________
(1)
Of the 58 productive wells, 20 (gross) or 3.53 (net) have multiple completions within the wellbore.
(2)
Represents our 50% interest in KTIPI.
(3)
Of the 96 productive wells, 6 (gross) or 2.42 (net) have multiple completions within the wellbore.
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, 2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ghana

 

 
3

 
0.80

 
3

 
0.80

 
4

 
0.89

 

 

 
4

 
0.89

 
7

 
1.69

U.S. Gulf of Mexico(4)

 

 

 

 

 

 
1

 
0.55

 

 

 
1

 
0.55

 
1

 
0.55

Senegal

 

 
1

 
0.60

 
1

 
0.60

 

 

 

 

 

 

 
1

 
0.60

Suriname

 

 
2

 
1.20

 
2

 
1.20

 

 

 

 

 

 

 
2

 
1.20

Total

 

 
6

 
2.60

 
6

 
2.60

 
5

 
1.44

 

 

 
5

 
1.44

 
11

 
4.04

Year Ended December 31, 2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ghana

 

 

 

 

 

 

 

 

 

 

 

 

 

Mauritania

 

 
2

 
0.56

 
2

 
0.56

 

 

 

 

 

 

 
2

 
0.56

Total

 

 
2

 
0.56

 
2

 
0.56

 

 

 

 

 

 

 
2

 
0.56

Year Ended December 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ghana

 

 

 

 

 

 
7

 
1.19

 

 

 
7

 
1.19

 
7

 
1.19

Total

 

 

 

 

 

 
7

 
1.19

 

 

 
7

 
1.19

 
7

 
1.19

______________________________________
(1)
As of December 31, 2018, seven exploratory and appraisal wells have been excluded from the table until a determination is made if the wells have found proved reserves. Also excluded from the table are 14 development wells awaiting completion. These wells are shown as “Wells Suspended or Waiting on Completion” in the table below.
(2)
A productive well is 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 producing well. Productive wells are included in the table in the year they were determined to be productive, as opposed to the year the well was drilled.
(3)
A dry well is an exploratory or development well that is not a productive well. Dry wells are included in the table in the year they were determined not to be a productive well, as opposed to the year the well was drilled.
(4)
Represents contributions from the U.S. Gulf of Mexico after the acquisition date.



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The following table shows the number of wells that are in the process of being drilled or are in active completion stages, and the number of wells suspended or waiting on completion as of December 31, 2018.
 
Actively Drilling or
 
Wells Suspended or
 
Completing
 
Waiting on Completion
 
Exploration
 
Development
 
Exploration
 
Development
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Ghana
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jubilee Unit

 

 
1

 
0.24

 

 

 
8

 
1.93

TEN

 

 
2

 
0.34

 

 

 
5

 
0.85

U.S. Gulf of Mexico
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nearly Headless Nick

 

 

 

 
1

 
0.22

 

 

Odd Job 214#2

 

 

 

 

 

 
1

 
0.61

Tornado

 

 
1

 
0.35

 

 

 

 

Mauritania
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
C8

 

 

 

 
3

 
0.84

 

 

Senegal
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Saint Louis Offshore Profond

 

 

 

 
1

 
0.30

 

 

Cayar Profond

 

 

 

 
2

 
0.60

 

 

Total

 

 
4

 
0.93

 
7

 
1.96

 
14

 
3.39

______________________________________

Domestic Supply Requirements
Many of our petroleum contracts or, in some cases, the applicable law governing such agreements, grant a right to the respective host country to purchase certain amounts of oil/gas produced pursuant to such agreements at international market prices for domestic consumption. In addition, in connection with the approval of the Jubilee Phase 1 PoD, the Jubilee Field partners agreed to provide the first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to GNPC at no cost. As of December 31, 2018, 99 Bcf of the 200 Bcf of natural gas has been provided.

Significant License Agreements
Below is a discussion concerning the petroleum contracts governing our current drilling and production operations.
Ghana West Cape Three Points Block
As a result of the approval of the GJFFDP by the Ghana Ministry of Energy in October 2017, operatorship for the Mahogany and Teak discoveries transferred to Tullow in February 2018 and are now included in the Jubilee Unit. Kosmos is required to pay a fixed royalty of 5% and a potential sliding‑scale royalty (“additional oil entitlement”) which comes into effect and escalates as the nominal project rate of return increases above a certain threshold. These royalties are to be paid in‑kind or, at the election of the government of Ghana, in cash. A corporate tax rate of 35% is applied to profits at a country level.
The WCTP petroleum contract has a duration of 30 years from its effective date (July 2004). However, in July 2011, at the end of the seven‑year Exploration Period, parts of the WCTP Block on which we had not declared a discovery area, were not in a development and production area, or were not in the Jubilee Unit, were relinquished (“WCTP Relinquishment Area”). We maintain rights to the Akasa discovery within the WCTP Block as the WCTP petroleum contract remains in effect after the end of the Exploration Period. We and our WCTP Block partners have certain rights to negotiate a new petroleum contract with respect to the WCTP Relinquishment Area. We and our WCTP Block partners, the Ghana Ministry of Energy and GNPC have agreed such WCTP petroleum contract rights to negotiate extend from July 21, 2011 until such time as either a new petroleum contract is negotiated and entered into with us or we decline to match a bona fide third party offer GNPC may receive for the WCTP Relinquishment Area.

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Ghana Deepwater Tano Block
Tullow is the operator of the Deepwater Tano Block. Under the DT petroleum contract, GNPC exercised its option to acquire an additional paying interest of 5% in the commercial discovery with respect to the Jubilee Field development and the TEN Fields development. Kosmos is required to pay a fixed royalty of 5% and a potential additional oil entitlement which comes into effect and escalates as the nominal project rate of return increases above a certain threshold. These royalties are to be paid in‑kind or, at the election of the government of Ghana, in cash. A corporate tax rate of 35% is applied to profits at a country level.
The DT petroleum contract has a duration of 30 years from its effective date (July 2006). However, in 2013, at the end of the seven‑year Exploration Period, parts of the DT Block on which we had not declared a discovery area, were not in a development and production area, or were not in the Jubilee Unit, were relinquished (“DT Relinquishment Area”). Our existing Wawa discovery within the DT Block was not subject to relinquishment upon expiration of the Exploration Period of the DT petroleum contract, as the DT petroleum contract remains in effect after the end of the Exploration Period while commerciality is being determined. Pursuant to our DT petroleum contract, we and our DT Block partners have certain rights to negotiate a new petroleum contract with respect to the DT Relinquishment Area until such time as either a new petroleum contract is negotiated and entered into with us or we decline to match a bona fide third party offer GNPC may receive for the DT Relinquishment Area.
The Ghanaian Petroleum Exploration and Production Law of 1984 (PNDCL 84) (the “1984 Ghanaian Petroleum Law”) and the WCTP and DT petroleum contracts form the basis of our exploration, development and production operations on the WCTP and DT blocks. Pursuant to these petroleum contracts, most significant decisions, including PoDs and annual work programs, for operations other than exploration and appraisal, must be approved by a joint management committee, consisting of representatives of certain block partners and GNPC. Certain decisions require unanimity.
Ghana Jubilee Field Unitization
The Jubilee Field, discovered by the Mahogany‑1 well in June 2007, covers an area within both the WCTP and DT Blocks. It was agreed the Jubilee Field would be unitized for optimal resource recovery. A Pre-Unit Agreement was agreed to between the contractors groups of the WCTP and DT Blocks in 2008, with a more comprehensive unit agreement, the Jubilee UUOA, agreed to in 2009 which governs each party’s respective rights and duties in the Jubilee Unit. Tullow is the Unit Operator, while Kosmos was the Technical Operator for the initial development of the Jubilee Field. The Jubilee Unit holders’ interests are subject to redetermination in accordance with the terms of the Jubilee UUOA. Although the Jubilee Field is unitized, Kosmos’ participating interests in each block outside the boundary of the Jubilee Unit remain the same. Our Jubilee Unit interest is 24.1% subject to redetermination of the participating interests pursuant to the terms of the Jubilee UUOA. Our paying interest on development activities is 26.9%.
Greater Tortue Ahmeyim Unitization
The Greater Tortue/Ahmeyim Field, discovered by the Tortue‑1 well in May 2015, in Mauritania block C8 and by the Guembuel-1 well in January 2016, in the Saint-Louis Offshore Profond block in Senegal covers an area within both the C8 and Saint-Louis Offshore Profond Blocks. Mauritania and Senegal agreed that the Greater Tortue Ahmeyim Field would be unitized for optimal resource recovery in the Inter-State Cooperation Agreement (ICA) signed in February 2018. The GTA UUOA was agreed between the contractor groups of the C8 and Saint-Louis Offshore Profond Blocks and approved by the appropriate Ministers in Mauritania and Senegal in February 2019. BP Mauritania and BP Senegal are co-Unit Operator, and will allocate responsibilities for the initial development of the Greater Tortue Ahmeyim Field. The Greater Tortue Ahmeyim Unit holders’ interests are subject to redetermination in accordance with the terms of the GTA UUOA. Although the Greater Tortue Ahmeyim Field is unitized, Kosmos’ participating interests in each block outside the boundary of the Greater Tortue Ahmeyim Unit remain the same. Our Unit interest is 29%, subject to SMHPM’s right to elect to participate for up to 14% in Block C8 and PETROSEN’s right to increase its participating interest to 20% in the Saint-Louis Offshore Profond Block and subject to redetermination of the participating interests pursuant to the terms of the GTA UUOA. In February 2019, Mauritania and Senegal each issued an exploitation authorization for the Greater Tortue Ahmeyim Unit area covered by the GTA UUOA.

Mauritania Agreements

Effective June 2012, we entered into three petroleum contracts covering offshore Mauritania blocks C8, C12 and C13 with the Islamic Republic of Mauritania. We provide technical exploration services to BP, the operator. The Mauritanian national oil company, SMHPM, currently has a 10% carried participating interest during the exploration period only. Should a commercial discovery be made, SMHPM’s 10% carried interest is extinguished and SMHPM will have an option to acquire a participating interest between 10% and 14%. SMHPM will pay its portion of development and production costs in a commercial development. Cost recovery oil is apportioned to the contractor from up to 55% of total production prior to profit oil being split between the

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government of Mauritania and the contractor. Profit oil is then apportioned based upon “R‑factor” tranches, where the R‑factor is cumulative net revenues divided by the cumulative investment. At the election of the government of Mauritania, the government may receive its share of production in cash or in kind. A corporate tax rate of 27% is applied to profits at the license level. The terms of exploration periods of these Offshore Blocks are all ten years and include an initial exploration period of four years followed by the first extension period of three years and the second extension period of three years. Kosmos is currently in the first extension period of the blocks, expiring in June 2019. In the event of commercial success, we have the right to develop and produce oil for 25 years and gas for 30 years from the grant of an exploitation authorization from the government, which may be extended for an additional period of 10 years under certain circumstances.
    
In October 2016, we entered into a petroleum contract covering Block C6 with the Islamic Republic of Mauritania. As a result of a subsequent farm-out, we have a 28% participating interest and provide technical exploration services to BP, the operator. The Mauritanian national oil company, SMHPM, currently has a 10% carried participating interest during the exploration period. We are currently in the first exploration period, which extends four years from the effective date (October 28, 2016).

In September 2017, we acquired a 15% non-operated participating interest in Block C18 offshore Mauritania. SMHPM currently has a 10% carried participating interest during the exploration period. Should a commercial discovery be made, SMHPM’s 10% carried interest is extinguished and SMHPM will have an option to acquire a participating interest between 10% and 15%. SMHPM will pay its portion of development and production costs in a commercial development. The terms of exploration periods are ten years and include an initial exploration period of seven years from the effective date (June 15, 2012), including extensions received prior to our entry into Block 18. The first exploration phase includes a 7,600 square kilometer 3D seismic requirement, which has been completed.
 
Senegal Agreements
In June 2018, we entered the final renewal of the exploration period for the Senegal Blocks Contract Areas, which lasts for two and one half years, ending in December 2020. This exploration phase of each contract area requires one exploration well in the final period. In the event of commercial success, we have the right to develop and produce oil and/or gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended for at least one additional period of 10 years under certain circumstances.
Equatorial Guinea Exploration Agreements
In March 2018, we entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. We currently have a 40% interest in the blocks. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), currently has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration period of five years from the date of notification of ratification by the President of Equatorial Guinea. The first exploration period consists of two sub-periods of three and two years, respectively, which can be extended up to two additional years at our election, subject to fulfilling specific work obligations. The first exploration sub-period work program includes an approximately 6,000 square kilometer 3D seismic acquisition requirement across the three blocks.
In June 2018, we acquired a 40% non-operated participating interest in Block EG-24 offshore Equatorial Guinea. GEPetrol, currently has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. The petroleum contract covers approximately 3,500 square kilometers, with a first exploration sub-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 sub-period work program includes a 3,000 square kilometer 3D seismic acquisition requirement.

In January 2019, we entered into an agreement to acquire Ophir's remaining interest in the block, subject to customary governmental approvals, which will result in Kosmos owning an 80% interest in Block EG-24.

Sao Tome and Principe Exploration Agreements

Kosmos has interests in petroleum contracts for Blocks 5, 6, 10, 11, 12 and 13 in Sao Tome and Principe.


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In Block 11, ANP-STP has a carried 15% participating interest. The production sharing contract was awarded in July 2014, and provides for an initial exploration period of eight years with possible extensions and includes a first phase exploration period of four years followed by the second phase of two years and the third phase of two years. The block is currently in the first phase, expiring in July 2019 after receiving a one year extension in November 2017. The next exploration phases are subject to fulfillment of specific work obligations. In the event of commercial success, we have the right to develop and produce oil and/or gas for a period of 20 years from the approval of a field development program by ANP-STP, which may be extended for additional periods of five years until all commercial hydrocarbons have been depleted.

In Block 6, ANP-STP has a carried 10% participating interest. The production sharing contract was awarded in October 2015, and provides for an initial exploration period of eight years with possible extensions and includes a first phase exploration period of four years followed by the second phase of two years and the third phase of two years. The block is currently in the first phase, expiring in November 2019. The next exploration phases are subject to fulfillment of specific work obligations. In the event of commercial success, we have the right to develop and produce oil and/or gas for a period of 20 years from the approval of a field development program by ANP-STP, which may be extended for additional periods of five years until all commercial hydrocarbons have been depleted.

In Block 5 and Block 12, ANP-STP has a 15% and 12.5% carried interest, respectively. The production sharing contracts were awarded in May 2012 and February 2016, respectively, and provide for an initial exploration period of eight years with possible extensions and include a first phase exploration period of four years followed by the second phase of two years and the third phase of two years. The blocks are currently in the first phase, expiring in May 2019 and February 2020, respectively (the first phase of Block 5 has been extended twice for a total of 3 years). The next exploration phases are subject to fulfillment of specific work obligations. In the event of commercial success, we have the right to develop and produce oil and/or gas for a period of 20 years from the approval of a field development program by ANP-STP, which may be extended for additional periods of five years until all commercial hydrocarbons have been depleted.

In Block 10 and Block 13, ANP-STP has a 15% carried interest. The production sharing contracts were awarded in March 2018 and include a first phase exploration period of four years followed by the second phase of two years and the third phase of two years. The blocks are currently in the first phase, expiring in 2022. The next exploration phases are subject to fulfillment of specific work obligations. In the event of commercial success, we have the right to develop and produce oil and/or gas for a period of 20 years from the approval of a field development program by ANP-STP, which may be extended for additional periods of five years until all commercial hydrocarbons have been depleted.

Suriname Exploration Agreements

In December 2011, we signed a petroleum contract covering Offshore Block 42 located offshore Suriname and are the operator. Staatsolie Maatschappij Suriname N.V. (“Staatsolie”), Suriname’s national oil company, has the option to back into the contract with an interest of not more than 10% upon approval of a development plan. The Block 42 petroleum contract provides for us to recover our share of expenses incurred (“cost recovery oil”) and our share of remaining oil (“profit oil”). Cost recovery oil is apportioned to the contractor from up to 80% of gross production prior to profit oil being split between the government of Suriname and the contractor. Profit oil is then apportioned based upon “R‑factor” tranches, where the R‑factor is cumulative net revenues divided by cumulative net investment. A corporate tax rate of 36% is applied to profits. We are in the second period of the exploration phase, which ends in September 2021. There is one additional period consisting of two years, and carries a one well drilling obligation. In the event of commercial success, the duration of the contract will be 30 years from the effective date or 25 years from governmental approval of a plan of development, whichever is longer.

In December 2011, we signed a petroleum contract covering Offshore Block 45 located offshore Suriname and are the operator. Staatsolie will be carried through the exploration and appraisal phases and has the option to back into the petroleum contract with an interest of not more than 15% upon approval of a development plan. The Block 45 petroleum contract provides for us to recover our share of expenses incurred (“cost recovery oil”) and our share of remaining oil (“profit oil”). Cost recovery oil is apportioned to the contractor from up to 80% of gross production prior to profit oil being split between the government of Suriname and the contractor. Profit oil is then apportioned based upon “R‑factor” tranches, where the R‑factor is cumulative net revenues divided by cumulative net investment. A corporate tax rate of 36% is applied to profits. We are currently in the second period of the exploration phase, which ends in September 2021. There is one additional period consisting of two years and carries a one well drilling obligation. In the event of commercial success, the duration of the contract will be 30 years from the effective date or 25 years from governmental approval of a plan of development, whichever is longer.


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Cote d'Ivoire Exploration Agreements

In December 2017, we entered into petroleum contracts covering Blocks CI-526, CI-602, CI-603, CI-707 and CI-708 with the Government of Cote d'Ivoire, and we are the operator. The Cote d'Ivoire national oil company, PETROCI Holding ("PETROCI"), currently has a 10% carried interest. The petroleum contracts cover approximately 17,000 square kilometers, with a first exploration period of three years with two possible extensions of three years each. The next exploration phases are subject to fulfillment of specific work programs. The first exploration period work program includes a 12,000 square kilometer 3D seismic acquisition across the five blocks.

Namibia Exploration Agreements

In September 2018, we acquired a 45% non-operated participating interest in PEL 39 offshore Namibia. Based on the terms of the agreement we will carry Shell's share of the costs of a planned 3D seismic program subject to a cap. The Namibian national oil company, National Petroleum Corporation of Namibia ("NAMCOR"), currently has a 10% carried participating interest during the exploration period. The carry of NAMCOR's 10% participation interest may continue through first commercial production but must be reimbursed through production. The petroleum contract covers approximately 12,300 square kilometers, with an initial exploration period and two renewals periods. The block is currently in the first renewal period, which has been extended and expires in August 2019. A second renewal period of two years is available at our election, subject to fulfilling specific work obligations. The first renewal period work program has been completed.

Sales and Marketing
As provided under the Jubilee UUOA and the WCTP and DT petroleum contracts, we are entitled to lift and sell our share of the Jubilee and TEN production as are the other Jubilee Unit and TEN partners. We have entered into an agreement with an oil marketing agent to market our share of the Jubilee and TEN fields oil, and we approve the terms of each sale proposed by such agent. We do not anticipate entering into any long term sales agreements at this time.
In December 2017, we signed the TAG GSA and we began exporting TEN associated gas to shore in the fourth quarter of 2018. The TAG GSA provides for an inflation-adjusted sales price of $0.50 per mmbtu.
As provided under the Production Sharing Contract for Block G, we are entitled to lift and sell our share of the Ceiba Field production as are the other Ceiba Field partners. We have entered into an agreement with an oil marketing agent to market our share of the Ceiba Field oil, and we approve the terms of each sale proposed by such agent. We do not anticipate entering into any long term sales agreements at this time.
In the U.S. Gulf of Mexico, we sell crude oil to purchasers typically through monthly contracts, with the sale taking place at multiple points offshore, depending on the particular property. Natural gas is sold to purchasers through monthly contracts, with the sale taking place either offshore or at an onshore gas processing plant after the removal of NGLs. We actively market our crude oil and natural gas to purchasers, and sales prices for purchased oil and natural gas volumes are negotiated with purchasers and are based on certain published indices. Since most of the oil and natural gas contracts are month-to-month, there are very few dedications of production to any one purchaser. We sell the NGLs entrained in the natural gas that we produce. The arrangements to sell these products first requires natural gas to be processed at an onshore gas processing plant. Once the liquids are removed and fractionated (broken into the individual hydrocarbon chains for sale), the products are sold by the processing plant. The residue gas left over is sold to natural gas purchasers as natural gas sales (referenced above). The contracts for NGL sales are with the processing plant. The prices received for the NGLs are either tied to indices or are based on what the processing plant can receive from a third party purchaser. The gas processing and subsequent sales of NGLs are subject to contracts with longer terms and dedications of lease production from the Company’s leases offshore.
There are a variety of factors which affect the market for oil, including the proximity and capacity of transportation facilities, demand for oil both within the local market and beyond, the marketing of competitive fuels and the effects of government regulations on oil production and sales. Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of operations.

Competition
The oil and gas industry is competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring licenses and leases. Many of these competitors have financial and technical resources and staff

31


that are substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses and leases than our financial or personnel resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of lower commodity prices, unsuccessful wells, volatility in financial markets and generally adverse global and industry‑wide economic conditions. These companies may also be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position.
Historically, we have also been affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews. Shortages of, or increasing costs for, experienced drilling crews and equipment and services may restrict our ability to drill wells and conduct our operations.
The oil and gas industry as a whole has experienced continued volatility. Dated Brent crude, the benchmark for our international oil sales, ranged from approximately $50 to $86 per barrel during 2018. HLS crude, the benchmark for our U.S. Gulf of Mexico oil sales, which generally trades at a slight discount to Dated Brent, ranged from approximately $63 to $75 during 2018. Excluding the impact of hedges, our realized price for 2018 was $69.00 per barrel. We believe lower prices will generally result in greater availability of assets and necessary equipment. However, the impacts on the industry from a competitive perspective are not entirely known.

Title to Property
Other than as specified in this annual report on Form 10‑K, we believe that we have satisfactory title to our oil and natural gas assets in accordance with standards generally accepted in the international oil and gas industry. Our licenses and leases are subject to customary royalty and other interests, liens under operating agreements and other burdens, restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of, or affect the carrying value of, our interests.
Environmental Matters
General
We are subject to various stringent and complex international, foreign, federal, state and local environmental, health and safety laws and regulations governing matters including the emission and discharge of pollutants into the ground, air or water; the generation, storage, handling, use and transportation of regulated materials; and the health and safety of our employees. These laws and regulations may, among other things:
require the acquisition of various permits before operations commence;
enjoin some or all of the operations or facilities deemed not in compliance with permits;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;
limit, cap, tax or otherwise restrict emissions of GHG and other air pollutants or otherwise seek to address or minimize the effects of climate change;
limit or prohibit drilling activities in certain locations lying within protected or otherwise sensitive areas; and
require measures to mitigate or remediate pollution, including pollution resulting from our block partners’ or our contractors’ operations.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. Compliance with these laws can be costly; the regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. We cannot assure you that we have been or will be at all times in compliance with such laws, or that environmental laws and regulations will not change or become more stringent in the future in a manner that could have a material adverse effect on our financial condition and results of operations.
Moreover, public interest in the protection of the environment continues to increase. Offshore drilling in some areas has been opposed by environmental groups and, in other areas, has been restricted. Our operations could be adversely affected to the

32


extent laws or regulations are enacted or other governmental action is taken that prohibits or restricts offshore drilling or imposes environmental requirements that increase costs to the oil and gas industry in general, such as more stringent or costly waste handling, disposal or cleanup requirements or financial responsibility and assurance requirements.
Per common industry practice, under agreements governing the terms of use of the drilling rigs contracted by us or our block or lease partners, the drilling rig contractors typically indemnify us and our block partners in respect of pollution and environmental damage originating above the surface of the water and from such drilling rig contractor’s property, including their drilling rig and other related equipment. Furthermore, pursuant to the terms of the operating agreements for our blocks and leases, except in certain circumstances, each block or lease partner is responsible for its share of liabilities in proportion to its participating interest incurred as a result of pollution and environmental damage, containment and clean‑up activities, loss or damage to any well, loss of oil or natural gas resulting from a blowout, crater, fire, or uncontrolled well, loss of stored oil and natural gas, as well as for plugging or bringing under control any well. We maintain insurance coverage typical of the industry in the areas we operate in; these include property damage insurance, loss of production insurance, wreck removal insurance, control of well insurance, general liability including pollution liability to cover pollution from wells and other operations. We also participate in an insurance coverage program for the FPSOs which we own. We believe our insurance is carried in amounts typical for the industry relative to our size and operations and in accordance with our contractual and regulatory obligations.
Capping and Containment (Excluding the U.S. Gulf of Mexico)
We entered into an agreement with a third party service provider for it to supply subsea capping and containment equipment on a global basis (excluding the U.S. Gulf of Mexico). The equipment includes capping stacks, debris removal, subsea dispersant and auxiliary equipment. The equipment meets industry accepted standards and can be deployed by air cargo and other conventional means to suit multiple application scenarios. We also developed an emergency response plan and response organization to prepare and demonstrate our readiness to respond to a subsea well control incident. Capping and containment for the U.S. Gulf of Mexico is detailed in the U.S. Gulf of Mexico (Operated and Non-operated) section below.
Oil Spill Response
To complement our agreement discussed above for subsea capping and containment equipment, we became a charter member of the Global Dispersant Stockpile ("GSD"). The dispersant stockpile, which is managed by Oil Spill Response Limited (“OSRL”) of Southampton, England, an oil spill response contractor, consists of 5,000 cubic meters of dispersant strategically located at OSRL bases around the world. The total volume of the stockpile located at the OSRL bases is calculated to provide members with the ability to respond to a major spill incident. Dispersant from the GSD can be used in the U.S. Gulf of Mexico.
Mauritania and Senegal (Non-operated)
Kosmos transferred operatorship of Mauritania and Senegal operations to BP at the beginning of 2018 for the blocks that were previously operated by Kosmos. Oil spill response equipment in both countries was transferred back to the OSRL Central Stockpile in Southampton, England.
Suriname (Operated)
Kosmos drilled two exploration wells in Suriname in 2018. Kosmos maintained its dispersant spraying capabilities in the field during drilling operations and had additional Tier 2 and Tier 3 equipment from OSRL’s Americas base in Ft Lauderdale, Florida on standby.
Ghana (Non-operated)
Tullow, our partner and the operator of the Jubilee Unit and the TEN fields, maintains Oil Spill Contingency Plans ("OSCP") covering the Jubilee Field and Deepwater Tano Block. Under the OSCPs, emergency response teams may be activated to respond to oil spill incidents. Tullow has access to OSRL’s oil spill response services comprising technical expertise and assistance, including access to response equipment and dispersant spraying systems. Tullow maintains lease agreements with OSRL for Tier 1 and Tier 2 packages of oil spill response equipment.
Equatorial Guinea (Operated and Non-operated)
In 2017, Kosmos entered into a joint venture in Equatorial Guinea through the acquisition KTIPI, which includes the Ceiba Field and Okume Complex. Effective January 1, 2019, Trident became operator of the Ceiba Field and Okume Complex. In addition, Kosmos is operator of four exploration leases in Equatorial Guinea. Current plans call for drilling one exploration well in 2019. Kosmos will bring in additional equipment in country to supplement existing resources as necessary.

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U.S. Gulf of Mexico (Operated and Non-operated)
After the major well control incident and oil release in the U.S. Gulf of Mexico in 2010, the U.S. Department of Interior updated regulations which govern the type, amount and capabilities of response equipment that needs to be available to operators to respond to similar incidents. These regulations also dictate the type and frequency of training that operating personnel need to receive and demonstrate proficiency in. Kosmos also has an Oil Spill Response Plan ("OSRP") which is approved by the Bureau of Safety and Environmental Enforcement ("BSEE"). This OSRP would be activated if needed in the event of an oil spill or containment event in the U.S. Gulf of Mexico. Kosmos joined several cooperatives that were established to meet the requirements of the new regulations. For capping and containment, Kosmos joined the Helix Well Containment Group ("HWCG") consortium whose capabilities include; (i) two dual ram capping stacks rated at 15,000 psi and 10,000 psi respectively, (ii) intervention equipment to cap and contain a well with the mechanical and structural integrity to be shut in at depths up to 10,000 feet, and (iii) the ability to capture and process 130,000 barrels of fluid per day and 220 Mcf of gas per day. Kosmos is also a member of the Clean Gulf Associate ("CGA") Oil Spill Cooperative, which provides oil spill response capabilities to meet regulatory requirements. Equipment and services include a High Volume Open Sea Skimming System ("HOSS"), dedicated oil spill response vessels strategically positioned along the U.S. gulf coast, dispersant and dispersant delivery systems, various types of spill response booms and mobile wildlife rehabilitation equipment. Due to federal regulations, all of the HWCG and CGA equipment is dedicated to U.S. operations and cannot be utilized outside the country.

Employees
As of December 31, 2018, we had approximately 380 employees. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are satisfactory.
Corporate Information
On December 28, 2018, we changed our jurisdiction of incorporation from Bermuda to the State of Delaware, USA. Kosmos Energy Ltd. discontinued as a Bermuda exempted company pursuant to Section 132G of the Companies Act 1981 of Bermuda and, pursuant to Section 265 of the General Corporation Law of the State of Delaware (the “DGCL”), continued its existence under the DGCL as a corporation organized in the State of Delaware. This transaction is referred to as the “Redomestication”. The business, assets and liabilities of the Company and its subsidiaries on a consolidated basis, as well as its principal locations and fiscal year, were the same immediately after the Redomestication as they were immediately prior to the Redomestication. In addition, the directors and executive officers of the Company immediately after the Redomestication were the same individuals who were directors and executive officers, respectively, of the Company immediately prior to the Redomestication.
The Company did not change its name in connection with the Redomestication. In the Redomestication, each of the outstanding common shares of Kosmos Energy Ltd., an exempted company incorporated pursuant to the laws of Bermuda, were automatically converted by operation of law, on a one-for-one basis, into shares of common stock of Kosmos Energy Ltd., a company incorporated pursuant to the laws of Delaware. Consequently, each holder of a Kosmos Energy Ltd. common share now holds a share of Kosmos Energy Ltd.’s common stock in each case representing the same proportional equity interest in the Company as that shareholder held prior to the Redomestication. The number of shares of the Company’s common stock outstanding immediately after the Redomestication was the same as the number of common shares of Kosmos Energy Ltd. outstanding immediately prior to the Redomestication. In connection with the Redomestication, the Company adopted a new certificate of incorporation, bylaws and form of common stock certificate, copies of which are filed herewith as Exhibits 3.1, 3.2 and 4.1, respectively.
We maintain a registered office in Delaware at Corporation Trust Center, 1209 Orange Street, Wilmington, Delaware 19801. Our executive offices are maintained at 8176 Park Lane, Suite 500, Dallas, Texas 75231, and its telephone number is +1 (214) 445 9600.


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Available Information
Kosmos is listed on the New York Stock Exchange and London Stock Exchange and our common stock is traded under the symbol KOS. We file or furnish annual, quarterly and current reports, proxy statements and other information with the SEC as well as the London Stock Exchange's Regulatory News Service ("LSE RNS"). The SEC maintains a website at http://www.sec.gov that contains documents we file electronically with the SEC. The LSE RNS maintains a website at http://www.londonstockexchange.com that contains documents we file electronically with the LSE RNS.
The Company also maintains an internet website under the name www.kosmosenergy.com. The information on our website is not incorporated by reference into this annual report on Form 10‑K and should not be considered a part of this annual report on Form 10‑K. Our website is included as an inactive technical reference only. We make available, free of charge, on our website, our annual report on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC.

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Item 1A.  Risk Factors
You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this report, including the consolidated financial statements and the related notes included in “Item 8. Financial Statements and Supplementary Data.” If any of the following risks actually occurs, our business, business prospects, financial condition, results of operations or cash flows could be materially adversely affected. The risks below are not the only ones we face. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us.

Risks Relating to the Oil and Natural Gas Industry and Our Business
We have limited proved reserves and areas that we decide to drill may not yield oil and natural gas in commercial quantities or quality, or at all.
We have limited proved reserves. A portion of our oil and natural gas assets consists of discoveries without approved PoDs and with limited well penetrations, as well as identified yet unproven prospects based on available seismic and geological information that indicates the potential presence of hydrocarbons. However, the areas we decide to drill may not yield oil or natural gas in commercial quantities or quality, or at all. Many of our current discoveries and all of our prospects are in various stages of evaluation that will require substantial additional analysis and interpretation. Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. Accordingly, we do not know if any of our discoveries or prospects will contain oil or natural gas in sufficient quantities or quality to recover drilling and completion costs or to be economically viable. Even if oil or natural gas is found on our discoveries or prospects in commercial quantities, construction costs of gathering lines, subsea infrastructure and floating production systems and transportation costs may prevent such discoveries or prospects from being economically viable, and approval of PoDs by various regulatory authorities, a necessary step in order to develop a commercial discovery, may not be forthcoming. Additionally, the analogies drawn by us using available data from other wells, more fully explored discoveries or producing fields may not prove valid with respect to our drilling prospects. We may terminate our drilling program for a discovery or prospect if data, information, studies and previous reports indicate that the possible development of a discovery or prospect is not commercially viable and, therefore, does not merit further investment. If a significant number of our discoveries or prospects do not prove to be successful, our business, financial condition and results of operations will be materially adversely affected.
The deepwater offshore Mauritania and Senegal, an area in which we currently focus a substantial amount of our development efforts, has only recently been considered economically viable for hydrocarbon production due to the costs and difficulties involved in drilling and development at such depths and the relatively recent discovery of commercial quantities of hydrocarbons in the region. Likewise, our deepwater offshore Cote d'Ivoire, Namibia, Sao Tome and Principe and Suriname licenses have not yet proved to be economically viable production areas. We have limited proved reserves, and we may not be successful in developing additional commercially viable production from our other discoveries and prospects.
We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects.
In this report we provide numerical and other measures of the characteristics of our discoveries and prospects. These measures may be incorrect, as the accuracy of these measures is a function of available data, geological interpretation and judgment. To date, a limited number of our prospects have been drilled. Any analogies drawn by us from other wells, discoveries or producing fields may not prove to be accurate indicators of the success of developing proved reserves from our discoveries and prospects. Furthermore, we have no way of evaluating the accuracy of the data from analog wells or prospects produced by other parties which we may use.
It is possible that few or none of our wells to be drilled will find accumulations of hydrocarbons in commercial quality or quantity. Any significant variance between actual results and our assumptions could materially affect the quantities of hydrocarbons attributable to any particular prospect.
Drilling wells is speculative, often involving significant costs that may be more than we estimate, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.
Exploring for and developing hydrocarbon reserves involves a high degree of technical, operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services or unanticipated geologic conditions.

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Before a well is spud, we incur significant geological and geophysical (seismic) costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons or is drilled at all. Drilling may be unsuccessful for many reasons, including geologic conditions, weather, cost overruns, equipment shortages and mechanical difficulties or force majeure events. Exploratory wells bear a much greater risk of failure than development wells. In the past we have experienced unsuccessful drilling efforts, having drilled dry holes. Furthermore, the successful drilling of a well does not necessarily result in the commercially viable development of a field or be indicative of the potential for the development of a commercially viable field. A variety of factors, including geologic and market‑related, can cause a field to become uneconomic or only marginally economic. A lack of drilling opportunities or projects that cease production may cause us to incur significant costs associated with an idle rig and/or related services, particularly if we cannot contract out rig slots to other parties. Many of our prospects that may be developed require significant additional exploration, appraisal and development, regulatory approval and commitments of resources prior to commercial development. In addition, a successful discovery would require significant capital expenditure in order to develop and produce oil and natural gas, even if we deemed such discovery to be commercially viable. See “—Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms or at all in the future, which may in turn limit our ability to develop our exploration, appraisal, development and production activities.” In the areas in which we operate, we face higher above‑ground risks necessitating higher expected returns, the requirement for increased capital expenditures due to a general lack of infrastructure and underdeveloped oil and gas industries, and increased transportation expenses due to geographic remoteness, which either require a single well to be exceptionally productive, or the existence of multiple successful wells, to allow for the development of a commercially viable field. See “—Our operations may be adversely affected by political and economic circumstances in the countries in which we operate.” Furthermore, if our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and could be forced to modify our plan of operation.
Development drilling may not result in commercially productive quantities of oil and gas reserves.
Our exploration success has provided us with major development projects on which we are moving forward, and any future exploration discoveries will also require significant development efforts to bring to production. We must successfully execute our development projects, including development drilling, in order to generate future production and cash flow. However, development drilling is not always successful and the profitability of development projects may change over time.
For example, in new development projects available data may not allow us to completely know the extent of the reservoir or choose the best locations for drilling development wells. A development well we drill may be a dry hole or result in noncommercial quantities of hydrocarbons. All costs of development drilling and other development activities are capitalized, even if the activities do not result in commercially productive quantities of hydrocarbon reserves. This puts a property at higher risk for future impairment if commodity prices decrease or operating or development costs increase.
Our identified drilling and infrastructure locations are scheduled out over time, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling or infrastructure installation or modification.
Our management team has identified and scheduled drilling locations and possible infrastructure locations on our license and lease areas over a multi‑year period. Our ability to drill and develop these locations depends on a number of factors, including the availability of equipment and capital, approval by block or lease partners and national and state regulators, seasonal conditions, oil prices, assessment of risks, costs and drilling results. For example, a shutdown of the U.S. federal government could delay the regulatory review and approval process associated with drilling or developmental activities within our license areas in the U.S. Gulf of Mexico. The final determination on whether to drill or develop any of these locations will be dependent upon the factors described elsewhere in this report as well as, to some degree, the results of our drilling and production activities with respect to our established wells and drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled or infrastructure installed or modified within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. As such, our actual drilling and development activities may be materially different from our current expectations, which could adversely affect our results of operations and financial condition.
A substantial or extended decline in both global and local oil and natural gas prices may adversely affect our business, financial condition and results of operations.
The prices that we will receive for our oil and natural gas will significantly affect our revenue, profitability, access to capital and future growth rate. Historically, the oil and natural gas markets have been volatile and will likely continue to be volatile in the future. Oil prices experienced significant and sustained declines in the past few years and will likely continue to be volatile in the future. The prices that we will receive for our production and the levels of our production depend on numerous factors. These factors include, but are not limited to, the following:

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changes in supply and demand for oil and natural gas;
the actions of the Organization of the Petroleum Exporting Countries;
speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;
global economic conditions;
political and economic conditions, including embargoes in oil‑producing countries or affecting other oil‑producing activities, particularly in the Middle East, Africa, Russia and Central and South America;
the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;
the level of global oil and natural gas exploration and production activity;
the level of global oil inventories and oil refining capacities;
weather conditions and natural or man‑made disasters;
technological advances affecting energy consumption;
governmental regulations and taxation policies;
proximity and capacity of transportation facilities;
the development and exploitation of alternative fuels or energy sources;
the price and availability of competitors’ supplies of oil and natural gas; and
the price, availability or mandated use of alternative fuels or energy sources.
Lower oil prices may not only reduce our revenues but also may limit the amount of oil that we can produce economically. A substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
Under the terms of our various petroleum contracts, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to drill these wells or declare any discoveries may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects.
In order to protect our exploration and production rights in our license areas, we must meet various drilling and declaration requirements. In general, unless we make and declare discoveries within certain time periods specified in our various petroleum agreements and licenses, our interests in the undeveloped parts of our license areas may lapse. Should the prospects yield discoveries, we cannot assure you that we will not face delays in the appraisal and development of these prospects or otherwise have to relinquish these prospects. The costs to maintain petroleum contracts over such areas may fluctuate and may increase significantly since the original term, and we may not be able to renew or extend such petroleum contracts on commercially reasonable terms or at all. Our actual drilling activities may therefore materially differ from our current expectations, which could adversely affect our business.
Under these petroleum contracts, we have work commitments to perform exploration and other related activities. Failure to do so may result in our loss of the licenses. As of December 31, 2018, we have unfulfilled drilling obligations in one of our Mauritania petroleum contracts. In certain other petroleum contracts, we are in the initial exploration phase, some of which have certain obligations that have yet to be fulfilled. Over the course of the next several years, we may choose to enter into the next phase of those petroleum contracts which will likely include firm obligations to drill wells. Failure to execute our obligations may result in our loss of the licenses.
The Exploration Period of each of the WCTP and DT petroleum contracts has expired. Pursuant to the terms of such petroleum contracts, while we and our respective block partners have certain rights to negotiate new petroleum contracts with respect to the WCTP Relinquishment Area and DT Relinquishment Area, we cannot assure you that we will determine to enter any such new petroleum contracts. For each of our petroleum contracts, we cannot assure you that any renewals or extensions will

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be granted or whether any new agreements will be available on commercially reasonable terms, or, in some cases, at all. For additional detail regarding the status of our operations with respect to our various petroleum contracts, please see “Item 1. Business—Operations by Geographic Area.”
The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results.
We may be liable for certain costs if third parties who contract with us are unable to meet their commitments under such agreements. We are currently exposed to credit risk through joint interest receivables from our block and/or unit partners. If any of our partners in the blocks or unit in which we hold interests are unable to fund their share of the exploration and development expenses, we may be liable for such costs. In the past, certain of our partners have not paid their share of block costs in the time frame required by the joint operating agreements for these blocks. This has resulted in such party being in default, which in return requires Kosmos and its non‑defaulting block partners to pay their proportionate share of the defaulting party’s costs during the default period. Should a default not be cured, Kosmos could be required to pay its share of the defaulting party’s costs going forward.
In addition, we contract with third parties to conduct drilling and related services on our development projects and exploration prospects. Such third parties may not perform the services they provide us on schedule or within budget. Furthermore, the drilling equipment, facilities and infrastructure owned and operated by the third parties we contract with is highly complex and subject to malfunction and breakdown. Any malfunctions or breakdowns may be outside our control and result in delays, which could be substantial. Any delays in our drilling campaign caused by equipment, facility or equipment malfunction or breakdown could materially increase our costs of drilling and cause an adverse effect on our business, financial position and results of operations.
Our principal exposure to credit risk will be through receivables resulting from the sale of our oil, which we currently sell to an energy marketing company, and to cover our commodity derivatives contracts. The inability or failure of our significant customers or counterparties to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Joint interest receivables arise from our block partners. The inability or failure of third parties we contract with to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We are unable to predict sudden changes in creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited and we could incur significant financial losses.
The unit partners’ respective interests in the Jubilee Unit and Greater Tortue Ahmeyim Unit are subject to redetermination and our interests in such unit may decrease as a result.
The interests in and development of the Jubilee Field are governed by the terms of the Jubilee UUOA. The parties to the Jubilee UUOA, the collective interest holders in each of the WCTP and DT Blocks, initially agreed that interests in the Jubilee Unit will be shared equally, with each block deemed to contribute 50% of the area of such unit. The respective interests in the Jubilee Unit were therefore initially determined by the respective interests in such contributed block interests. Pursuant to the terms of the Jubilee UUOA, the percentage of such contributed interests is subject to a process of redetermination once sufficient development work has been completed in the unit. The initial redetermination process was completed on October 14, 2011. As a result of the initial redetermination process, the tract participation was determined to be 54.4% for the WCTP Block and 45.6% for the DT Block. Our Unit Interest (participating interest in the Jubilee Unit) was increased from 23.5% to 24.1%. An additional redetermination could occur sometime if requested by a party that holds greater than a 10% interest in the Jubilee Unit. We cannot assure you that any redetermination pursuant to the terms of the Jubilee UUOA will not negatively affect our interests in the Jubilee Unit or that such redetermination will be satisfactorily resolved.
The interests in and development of the Greater Tortue Ahmeyim Field are governed by the terms of the GTA UUOA. The parties to the GTA UUOA, the collective interest holders in each of the Mauritania Block C8 and Senegal Saint Louis Offshore Profond blocks, initially agreed that interests in the Greater Tortue Ahmeyim Unit will be shared equally, with each block deemed to contribute 50% of the area of such unit. The respective interests in the Greater Tortue Ahmeyim Unit were therefore initially determined by the respective interests in such contributed block interests. Pursuant to the terms of the GTA UUOA, the percentage of such contributed interests is subject to a process of redetermination once sufficient development work has been completed in the unit. We cannot assure you that any redetermination pursuant to the terms of the GTA UUOA will not negatively affect our interests in the Greater Tortue Ahmeyim Unit or that such redetermination will be satisfactorily resolved.

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We are not, and may not be in the future, the operator on all of our license areas and facilities and do not, and may not in the future, hold all of the working interests in certain of our license areas. Therefore, we have reduced control over the timing of exploration or development efforts, associated costs, and the rate of production of any non‑operated and to an extent, any non‑wholly-owned, assets.
As we carry out our exploration and development programs, we have arrangements with respect to existing license areas and may have agreements with respect to future license areas that result in a greater proportion of our license areas being operated by others. Currently, we are not the operator of the Jubilee Unit, the TEN fields, Ceiba and Okume or certain producing fields in the U.S. Gulf of Mexico and do not hold operatorship in certain other offshore blocks. In addition, our agreements with BP and Chevron contemplate that operatorship will be transitioned fully to these companies in our Cote d'Ivoire (BP) and Suriname (Chevron) acreage upon a commercial discovery. As a result, we may have limited ability to exercise influence over the operations of the discoveries or prospects operated by our block or unit partners, or which are not wholly-owned by us, as the case may be. Dependence on block or unit partners could prevent us from realizing our target returns for those discoveries or prospects. Further, because we do not have majority ownership in all of our properties, we may not be able to control the timing, or the scope, of exploration or development activities or the amount of capital expenditures and, therefore, may not be able to carry out one of our key business strategies of minimizing the cycle time between discovery and initial production. The success and timing of exploration and development activities will depend on a number of factors that will be largely outside of our control, including:
the timing and amount of capital expenditures;
if the activity is operated by one of our block partners, the operator’s expertise and financial resources;
approval of other block partners in drilling wells;
the scheduling, pre‑design, planning, design and approvals of activities and processes;
selection of technology;
the available capacity of processing facilities and related pipelines; and
the rate of production of reserves, if any.
This limited ability to exercise control over the operations on our license areas may cause a material adverse effect on our financial condition and results of operations.
Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is technically complex. It requires interpretations of available technical data and many assumptions, including those relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report. See “Item 1. Business—Our Reserves” for information about our estimated oil and natural gas reserves and the present value of our net revenues at a 10% discount rate (“PV‑10”) and Standardized Measure of discounted future net revenues (as defined herein) as of December 31, 2018.
In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with the SEC requirements, we have based the estimated discounted future net revenues from our proved reserves on the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the preceding twelve months, adjusted for an anticipated market premium, without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas assets will be affected by factors such as:
actual prices we receive for oil and natural gas;
actual cost of development and production expenditures;
derivative transactions;
the amount and timing of actual production; and
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas assets will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates included in this report. Oil prices have recently experienced significant volatility. See “Item 1. Business—Our Reserves.”
We are dependent on certain members of our management and technical team.
Our performance and success largely depend on the ability, expertise, judgment and discretion of our management and the ability of our technical team to identify, discover, evaluate and develop reserves. The loss or departure of one or more members of our management and technical team could be detrimental to our future success. Additionally, a significant amount of shares in Kosmos held by members of our management and technical team has vested. There can be no assurance that our management and technical team will remain in place. If any of these officers or other key personnel retires, resigns or becomes unable to continue in their present roles and is not adequately replaced, our results of operations and financial condition could be materially adversely affected. Our ability to manage our growth, if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.
Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms or at all in the future, which may in turn limit our ability to develop our exploration, appraisal, development and production activities.
We expect our capital outlays and operating expenditures to be substantial as we expand our operations. Obtaining seismic data, as well as exploration, appraisal, development and production activities entail considerable costs, and we may need to raise substantial additional capital through additional debt financing, strategic alliances or future private or public equity offerings if our cash flows from operations, or the timing of, are not sufficient to cover such costs.
Our future capital requirements will depend on many factors, including:
the scope, rate of progress and cost of our exploration, appraisal, development and production activities;
the success of our exploration, appraisal, development and production activities;
oil and natural gas prices;
our ability to locate and acquire hydrocarbon reserves;
our ability to produce oil or natural gas from those reserves;
the terms and timing of any drilling and other production‑related arrangements that we may enter into;
the cost and timing of governmental approvals and/or concessions; and

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the effects of competition by larger companies operating in the oil and gas industry.
We do not currently have any commitments for future external funding beyond the capacity of our commercial debt facility and revolving credit facility. Additional financing may not be available on favorable terms, or at all. Even if we succeed in selling additional equity securities to raise funds, at such time the ownership percentage of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we choose to farm‑out interests in our licenses, we would dilute our ownership interest subject to the farm‑out and any potential value resulting therefrom, and may lose operating control or influence over such license areas.
Assuming we are able to commence exploration, appraisal, development and production activities or successfully exploit our licenses during the exploratory term, our interests in our licenses (or the development/production area of such licenses as they existed at that time, as applicable) could extend beyond the term set for the exploratory phase of the license to a fixed period or life of production, depending on the jurisdiction. If we are unable to meet our well commitments and/or declare commerciality of the prospective areas of our licenses during this time, we may be subject to significant potential forfeiture of all or part of the relevant license interests. If we are not successful in raising additional capital, we may be unable to continue our exploration and production activities or successfully exploit our license areas, and we may lose the rights to develop these areas. See “—Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects.”
All of our proved reserves, oil production and cash flows from operations are currently associated with our licenses offshore Ghana, Equatorial Guinea, and U.S. Gulf of Mexico. Should any event occur which adversely affects such proved reserves, oil production and cash flows from these licenses, including, without limitation, any event resulting from the risks and uncertainties outlined in this “Risk Factors” section, our business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures may be materially and adversely affected.
We may be required to take write‑downs of the carrying values of our oil and natural gas assets as a result of decreases in oil and natural gas prices, and such decreases could result in reduced availability under our corporate revolver and commercial debt facility.
We capitalize costs to acquire, find and develop our oil and natural gas properties under the successful efforts accounting method. Under such method, we are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of appraisal and development plans, production data, oil and natural gas prices, economics and other factors, we may be required to write down the carrying value of our oil and natural gas assets. A write‑down constitutes a non‑cash charge to earnings. As a result of the recent drop in oil and natural gas prices, we may incur future write‑downs and charges should prices remain at low levels.
In addition, our borrowing base under the commercial debt facility is subject to periodic redeterminations. We could be forced to repay a portion of our borrowings under the commercial debt facility due to redeterminations of our borrowing base. Redeterminations may occur as a result of a variety of factors, including oil and natural gas commodity price assumptions, assumptions regarding future production from our oil and natural gas assets, operating costs and tax burdens or assumptions concerning our future holdings of proved reserves. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
We may not be able to commercialize our interests in any natural gas produced from our license areas.
The development of the market for natural gas in our license areas is in its early stages. Currently the infrastructure to transport and process natural gas on commercial terms is limited and the expenses associated with constructing such infrastructure ourselves may not be commercially viable given local prices currently paid for natural gas. Accordingly, there may be limited or no value derived from any natural gas produced from our license areas.
In Ghana, we currently produce associated gas from the Jubilee and TEN fields. A gas pipeline from the Jubilee Field has been constructed to transport such natural gas for processing and sale. However, we granted the Government of Ghana the first 200 Bcf of natural gas exported from the Jubilee Field to shore at zero cost. Through December 31, 2018, the Jubilee partners

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have provided approximately 99 Bcf from the Jubilee Field to Ghana. Thus, in Ghana, it is forecasted to be a few years before we are able to commercialize the Jubilee Field natural gas. We do not currently book proved gas reserves associated with natural gas sales from the Jubilee Field in Ghana. However, we expect to book gas reserves upon finalization and execution of a gas sales agreement for such Jubilee Field natural gas that will have a price associated with it. A gas pipeline from the TEN fields to the Jubilee Field was completed in the first quarter of 2017 to transport associated natural gas as well as non-associated natural gas for processing and sale. We finalized the TAG GSA, and as a result, we booked proved gas reserves for the associated natural gas from the TEN fields in Ghana. 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.

In Mauritania and Senegal, we plan to export the majority of our gas resource to the liquefied natural gas (“LNG”) market. However, that plan is contingent on making final investment decisions on our gas discoveries and constructing the necessary infrastructure to produce, liquefy and transport the gas to the market as well as finding LNG purchasers. Additionally, such plans are contingent upon receipt of required partner and government approvals.

Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production.
Our ability to market our oil and natural gas production will depend substantially on the availability and capacity of processing facilities, oil and LNG tankers and other infrastructure, including FPSOs, owned and operated by third parties. Our failure to obtain such facilities on acceptable terms could materially harm our business. We also rely on continuing access to drilling rigs suitable for the environment in which we operate. The delivery of drilling rigs may be delayed or cancelled, and we may not be able to gain continued access to suitable rigs in the future. We may be required to shut in oil and natural gas wells because of the absence of a market or because access to processing facilities may be limited or unavailable. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market, which could cause a material adverse effect on our financial condition and results of operations. In addition, the shutting in of wells can lead to mechanical problems upon bringing the production back on line, potentially resulting in decreased production and increased remediation costs.
Additionally, the future exploitation and sale of associated and non‑associated natural gas and liquids and LNG will be subject to timely commercial processing and marketing of these products, which depends on the contracting, financing, building and operating of infrastructure by third parties. The Government of Ghana completed the construction and connection of a gas pipeline from the Jubilee Field and the pipeline between the Jubilee and TEN fields to transport such natural gas to the mainland for processing and sale was completed in the first quarter of 2017. However, the uptime of the facility in future periods is not known. In the absence of the continuous removal of large quantities of natural gas it is anticipated that we will either need to flare such natural gas in order to maintain crude oil production or reduce crude oil production. Currently, we have been issued permits from the Ghana EPA to flare natural gas produced from the Jubilee and TEN Fields in limited quantities. If we are unable to resolve potential issues related to the continuous removal of associated natural gas in large quantities, our oil production will be negatively impacted.
We are subject to numerous risks inherent to the exploration and production of oil and natural gas.
Oil and natural gas exploration and production activities involve many risks that a combination of experience, knowledge and interpretation may not be able to overcome. Our future will depend on the success of our exploration and production activities and on the development of an infrastructure that will allow us to take advantage of our discoveries. Additionally, many of our license areas are located in deepwater, which generally increases the capital and operating costs, chances of delay, planning time, technical challenges and risks associated with oil and natural gas exploration and production activities. See “— Our offshore and deepwater operations involve special risks that could adversely affect our results of operation.” As a result, our oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore or develop discoveries, prospects or licenses will depend in part on the evaluation of seismic data through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.
Furthermore, the marketability of expected oil and natural gas production from our discoveries and prospects will also be affected by numerous factors. These factors include, but are not limited to, market fluctuations of prices (such as recent significant declines in oil and natural gas prices), proximity, capacity and availability of drilling rigs and related equipment, qualified personnel and support vessels, processing facilities, transportation vehicles and pipelines, equipment availability, access to markets and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, domestic supply requirements, importing and exporting of oil and natural gas, the ability to flare or vent natural gas, health and

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safety matters, environmental protection and climate change). The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital.
In the event that our currently undeveloped discoveries and prospects are developed and become operational, they may not produce oil and natural gas in commercial quantities or at the costs anticipated, and our projects may cease production, in part or entirely, in certain circumstances. Discoveries may become uneconomic as a result of an increase in operating costs to produce oil and natural gas. Our actual operating costs and rates of production may differ materially from our current estimates. Moreover, it is possible that other developments, such as increasingly strict environmental, climate change, health and safety laws and regulations and enforcement policies thereunder and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities, delays, an inability to complete the development of our discoveries or the abandonment of such discoveries, which could cause a material adverse effect on our financial condition and results of operations.
We are subject to drilling and other operational and environmental risks and hazards.
The oil and natural gas business involves a variety of risks, including, but not limited to:
fires, blowouts, spills, cratering and explosions;
mechanical and equipment problems, including unforeseen engineering complications;
uncontrolled flows or leaks of oil, well fluids, natural gas, brine, toxic gas or other pollutants or hazardous materials;
gas flaring operations;
marine hazards with respect to offshore operations;
formations with abnormal pressures;
pollution, environmental risks, and geological problems; and
weather conditions and natural or man‑made disasters.
These risks are particularly acute in deepwater drilling and exploration. Any of these events could result in loss of human life, significant damage to property, environmental or natural resource damage, impairment, delay or cessation of our operations, lower production rates, adverse publicity, substantial losses and civil or criminal liability. We expect to maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events, whether or not covered by insurance, could have a material adverse effect on our financial position and results of operations.
Our operations may be materially adversely affected by tropical storms and hurricanes.

Tropical storms, hurricanes and the threat of tropical storms and hurricanes often result in the shutdown of operations, particularly in the U.S. Gulf of Mexico, as well as operations within the path and the projected path of the tropical storms or hurricanes. In addition, climate change could result in an increase in the frequency and severity of tropical storms, hurricanes or other extreme weather events. Weather events have caused significant disruption to the operations of offshore and coastal facilities in the U.S. Gulf of Mexico region. In the future, during a shutdown period, we may be unable to access wellsites and our services may be shut down. Additionally, tropical storms or hurricanes may cause evacuation of personnel and damage to our platforms and other equipment, which may result in suspension of our operations. The shutdowns, related evacuations and damage can create unpredictability in activity and utilization rates, as well as delays and cost overruns, which could have a material adverse effect on our business, financial condition and results of operations.

The development schedule of oil and natural gas projects, including the availability and cost of drilling rigs, equipment, supplies, personnel and oilfield services, is subject to delays and cost overruns.
Historically, some oil and natural gas development projects have experienced delays and capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential equipment, supplies, personnel and oilfield services, as well as mechanical and technical issues. The cost to develop our projects has not been fixed and remains dependent upon a number of factors, including the completion of detailed cost estimates and final engineering, contracting and procurement costs. Our construction and operation schedules may not proceed as planned and may experience delays or cost overruns. Any delays may increase the costs of the projects, requiring additional capital, and such capital may not be available in a timely and cost‑effective fashion.

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Our offshore and deepwater operations involve special risks that could adversely affect our results of operations.
Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, sinking, collisions and damage or loss to pipeline, subsea or other facilities or from weather conditions. We could incur substantial expenses that could reduce or eliminate the funds available for exploration, development or license acquisitions, or result in loss of equipment and license interests.

Deepwater exploration generally involves greater operational and financial risks than exploration in shallower waters. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of equipment failure and usually higher drilling costs. In addition, there may be production risks of which we are currently unaware. If we participate in the development of new subsea infrastructure and use floating production systems to transport oil from producing wells, these operations may require substantial time for installation or encounter mechanical difficulties and equipment failures that could result in loss of production, significant liabilities, cost overruns or delays. For example, we have experienced mechanical issues in the Jubilee Field, including failures of its gas and water injection facilities on the FPSO, and are currently working to complete remediation of the turret bearing issue on the FPSO. The equipment downtime caused by these mechanical issues negatively impacted oil production during the year.

In addition, Kosmos and its Jubilee partners determined that the risers of the FPSO have experienced increased levels of stress compared to their original design basis, which may cause these risers to suffer operational fatigue earlier than originally anticipated. The Jubilee partnership has performed remediation work on the water injection risers and additional work may be required on the gas injection riser depending on the analysis of instrumentation data of the risers to make a final determination if operational fatigue has occurred. Such remediation efforts may negatively impact oil production, and/or result in additional expenses.

Furthermore, deepwater operations generally, and operations in Africa and South America, in particular, lack the physical and oilfield service infrastructure present in other regions. As a result, a significant amount of time may elapse between a deepwater discovery and the marketing of the associated oil and natural gas, increasing both the financial and operational risks involved with these operations. Because of the lack and high cost of this infrastructure, further discoveries we may make in Africa and South America may never be economically producible.

In addition, in the event of a well control incident, containment and, potentially, cleanup activities for offshore drilling are costly. The resulting regulatory costs or penalties, and the results of third party lawsuits, as well as associated legal and support expenses, including costs to address negative publicity, could well exceed the actual costs of containment and cleanup. As a result, a well control incident could result in substantial liabilities, and have a significant negative impact on our earnings, cash flows, liquidity, financial position, and stock price.

We have had disagreements with the Republic of Ghana and the Ghana National Petroleum Corporation regarding certain of our rights and responsibilities under the WCTP and DT Petroleum Agreements.
Multiple discovered fields and a significant portion of our proved reserves are located offshore Ghana. The WCTP petroleum contract, the DT petroleum contract and the Jubilee UUOA cover the two blocks and the Jubilee and TEN fields that form the basis of our current operations in Ghana. Pursuant to these petroleum contracts, most significant decisions, including our plans for development and annual work programs, must be approved by GNPC, the Ghanaian Revenue Authority (the “GRA”), the Petroleum Commission and/or Ghana’s Ministry of Energy. We have previously had disagreements with the Ministry of Energy and GNPC regarding certain of our rights and responsibilities under these petroleum contracts, the 1984 Ghanaian Petroleum Law and the Internal Revenue Act, 2000 (Act 592) (the “Ghanaian Tax Law”). These included disagreements over sharing information with prospective purchasers of our interests, pledging our interests to finance our development activities, potential liabilities arising from discharges of small quantities of drilling fluids into Ghanaian territorial waters, the failure to approve the proposed sale of our Ghanaian assets, assertions that could be read to give rise to taxes or other payments payable under the Ghanaian Tax Law, failure to approve PoDs relating to certain discoveries offshore Ghana and the relinquishment of certain exploration areas on our licensed blocks offshore Ghana. The resolution of certain of these disagreements required us to pay agreed settlement costs to GNPC and/or the government of Ghana.
There can be no assurance that future disagreements will not arise with any host government and/or national oil companies that may have a material adverse effect on our exploration or development activities, our ability to operate, our rights under our licenses and local laws or our rights to monetize our interests.
The geographic locations of our licenses in Africa and South America subject us to an increased risk of loss of revenue or curtailment of production from factors specifically affecting those areas.

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A large portion of our current exploration licenses are located in Africa and South America. Some or all of these licenses could be affected should any region experience any of the following factors (among others):
severe weather, natural or man‑made disasters or acts of God;
delays or decreases in production, the availability of equipment, facilities, personnel or services;
delays or decreases in the availability of capacity to transport, gather or process production;
military conflicts, civil unrest or political strife; and/or
international border disputes.
For example, oil and natural gas operations in our license areas in Africa and South America may be subject to higher political and security risks than those operations under the sovereignty of the United States. We plan to maintain insurance coverage for only a portion of the risks we face from doing business in these regions. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss.
Further, as many of our licenses are concentrated in the same geographic area, a number of our licenses could experience the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of licenses.
Our operations may be adversely affected by political and economic circumstances in the countries in which we operate.
Oil and natural gas exploration, development and production activities are subject to political and economic uncertainties (including but not limited to changes in energy policies or the personnel administering them), changes in laws and policies governing operations of foreign‑based companies, expropriation of property, cancellation or modification of contract rights, revocation of consents or approvals, obtaining various approvals from regulators, foreign exchange restrictions, currency fluctuations, royalty increases and other risks arising out of foreign governmental sovereignty, as well as risks of loss due to civil strife, acts of war, guerrilla activities, terrorism, acts of sabotage, territorial disputes and insurrection. In addition, we are subject both to uncertainties in the application of the tax laws in the countries in which we operate and to possible changes in such tax laws (or the application thereof), each of which could result in an increase in our tax liabilities. These risks may be higher in the developing countries in which we conduct a majority of our activities, as it is the case in Ghana, where the GRA previously disputed certain tax deductions we had claimed in prior fiscal years’ Ghanaian tax returns as non‑allowable under the terms of the Ghanaian Petroleum Income Tax Law, as well as non‑payment of certain transactional taxes and other payments.
Our operations in these areas increase our exposure to risks of war, local economic conditions, political disruption, civil disturbance, expropriation, piracy, tribal conflicts and governmental policies that may:
disrupt our operations;
require us to incur greater costs for security;
restrict the movement of funds or limit repatriation of profits;
lead to U.S. government or international sanctions; or
limit access to markets for periods of time.
Some countries in the geographic areas where we operate have experienced political instability in the past or are currently experiencing instability. Disruptions may occur in the future, and losses caused by these disruptions may occur that will not be covered by insurance. Consequently, our exploration, development and production activities may be substantially affected by factors which could have a material adverse effect on our results of operations and financial condition. Furthermore, in the event of a dispute arising from non‑U.S. operations, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjecting non‑U.S. persons to the jurisdiction of courts in the United States or international arbitration, which could adversely affect the outcome of such dispute.
Our operations may also be adversely affected by laws and policies of the jurisdictions, including the jurisdictions where our oil and gas operating activities are located as well as the United Kingdom and the Cayman Islands and other jurisdictions in which we do business, that affect foreign trade and taxation. Changes in any of these laws or policies or the implementation thereof could materially and adversely affect our financial position, results of operations and cash flows.

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More comprehensive and stringent regulation in the U.S. Gulf of Mexico has significantly increased costs and delays in offshore oil and natural gas exploration and production operations.

In the U.S. Gulf of Mexico, there have been a series of regulatory initiatives developed and implemented at the federal level to address the direct impact of the incident and to prevent similar incidents in the future. Beginning in 2010 and continuing through the present, the Department of Interior (“DOI”) through the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”), has issued a variety of regulations and Notices to Lessees and Operators (“NTLs”), intended to impose additional safety, permitting and certification requirements applicable to exploration, development and production activities in the U.S. Gulf of Mexico. These regulatory initiatives effectively slowed down the pace of drilling and production operations in the U.S. Gulf of Mexico as adjustments were being made in operating procedures, certification requirements and lead times for inspections, drilling applications and permits, and exploration and production plan reviews, and as the federal agencies evolved into their present day bureaus. On April 17, 2015, BSEE published a proposed rule that would impose more stringent standards on blowout preventers (“BOP”). In April 2016, BSEE issued a final version of this rule effective July 2016, though some requirements of the rule have delayed compliance deadlines. The final rule addresses the full range of systems and equipment associated with well control operations, focusing on requirements for BOPs, well design, well control casing, cementing, real-time monitoring and subsea containment. Key features of the well control regulations include requirements for BOPs, double shear rams, third-party reviews of equipment, real time monitoring data, safe drilling margins, centralizers, inspections and other reforms related to well design and control, casing, cementing and subsea containment. On March 28, 2017, President Trump signed an executive order (the “March 2017 Executive Order”) directing federal agencies to initiate rulemakings to suspend, revise or rescind certain regulations relating to the energy industry as necessary to ensure consistency with the goals of energy independence, economic growth and cost-effective environmental regulation. In response to the March 2017 Executive Order and a subsequent executive order issued by President Trump in April 2017 focusing on offshore energy development, in May 2018, BSEE published a proposal to relax certain requirements of the July 2016 rule. The proposed rule’s comment period expired on August 6, 2018, but a final rule has not yet been published; this rule is likely to be subject to legal challenges.

In addition to the array of new or revised safety, permitting and certification requirements developed and implemented by the DOI in the past few years, there have been a variety of proposals to change existing laws and regulations that could affect offshore development and production, such as, for example, a proposal to significantly increase the minimum financial responsibility demonstration required under the Oil Pollution Act of 1990. To the extent the existing regulatory initiatives implemented and pursued over the past few years or any future restrictions, whether through legislative or regulatory means or increased or broadened permitting and enforcement programs, foster uncertainties or delays in our offshore oil and natural gas development or exploration activities, then such conditions may have a material adverse effect on our business, financial condition and results of operations.

The oil and gas industry, including the acquisition of exploratory licenses, is intensely competitive and many of our competitors possess and employ substantially greater resources than us.
The international oil and gas industry is highly competitive in all aspects, including the exploration for, and the development of, new license areas. We operate in a highly competitive environment for acquiring exploratory licenses and hiring and retaining trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than us, which can be particularly important in the areas in which we operate. These companies may be better able to withstand the financial pressures of unsuccessful drilling efforts, sustained periods of volatility in financial markets and generally adverse global and industry‑wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which could adversely affect our competitive position. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable licenses and to consummate transactions in a highly competitive environment. Also, there is substantial competition for available capital for investment in the oil and gas industry. As a result of these and other factors, we may not be able to compete successfully in an intensely competitive industry, which could cause a material adverse effect on our results of operations and financial condition.

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Participants in the oil and gas industry are subject to numerous laws, regulations, and other legislative instruments that can affect the cost, manner or feasibility of doing business.
Exploration and production activities in the oil and gas industry are subject to local laws and regulations. We may be required to make large expenditures to comply with governmental laws and regulations, particularly in respect of the following matters:
licenses for drilling operations;
tax increases, including retroactive claims;
unitization of oil accumulations;
local content requirements (including the mandatory use of local partners and vendors); and
safety, health and environmental requirements, liabilities and obligations, including those related to remediation, investigation or permitting.
Under these and other laws and regulations, we could be liable for personal injuries, property damage and other types of damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change, or their interpretations could change, in ways that could substantially increase our costs. These risks may be higher in the developing countries in which we conduct a majority of our operations, where there could be a lack of clarity or lack of consistency in the application of these laws and regulations. Any resulting liabilities, penalties, suspensions or terminations could have a material adverse effect on our financial condition and results of operations.
For example, Ghana’s Parliament has enacted the Petroleum Revenue Management Act, the Petroleum Commission Act of 2011, and the 2016 Ghanaian Petroleum Law. There can be no assurance that these laws will not seek to retroactively, either on their face or as interpreted, modify the terms of the agreements governing our license interests in Ghana, including the WCTP and DT petroleum contracts and the Jubilee UUOA, require governmental approval for transactions that effect a direct or indirect change of control of our license interests or otherwise affect our current and future operations in Ghana. Any such changes may have a material adverse effect on our business. We also cannot assure you that government approval will not be needed for direct or indirect transfers of our petroleum agreements or interests thereunder based on existing legislation.
We are subject to numerous health, safety and environmental laws and regulations which may result in material liabilities and costs.
We are subject to various international, foreign, federal, state and local health, safety and environmental laws and regulations governing, among other things, the emission and discharge of pollutants into the ground, air or water, the generation, storage, handling, use, transportation and disposal of regulated materials and the health and safety of our employees, contractors and communities in which our assets are located. We are required to obtain environmental permits from governmental authorities for our operations, including drilling permits for our wells. We have not been or may not be at all times in complete compliance with these permits and laws and regulations to which we are subject, and there is a risk such requirements could change in the future or become more stringent. If we violate or fail to comply with such requirements, we could be fined or otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or termination of our operations. If we fail to obtain, maintain or renew permits in a timely manner or at all (due to opposition from partners, community or environmental interest groups, governmental delays or other reasons), or if we face additional requirements imposed as a result of changes in or enactment of laws or regulations, such failure to obtain, maintain or renew permits or such changes in or enactment of laws or regulations could impede or affect our operations, which could have a material adverse effect on our results of operations and financial condition.
We, as an interest owner or as the designated operator of certain of our past, current and future interests, discoveries and prospects, could be held liable for some or all health, safety and environmental costs and liabilities arising out of our actions and omissions as well as those of our block partners, third‑party contractors, predecessors or other operators. To the extent we do not address these costs and liabilities or if we do not otherwise satisfy our obligations, our operations could be suspended or terminated. We have contracted with and intend to continue to hire third parties to perform services related to our operations. There is a risk that we may contract with third parties with unsatisfactory health, safety and environmental records or that our contractors may be unwilling or unable to cover any losses associated with their acts and omissions. Accordingly, we could be held liable for all costs and liabilities arising out of their acts or omissions, which could have a material adverse effect on our results of operations and financial condition.

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We are not fully insured against all risks and our insurance may not cover any or all health, safety or environmental claims that might arise from our operations or at any of our license areas. If a significant accident or other event occurs and is not covered by insurance, such accident or event could have a material adverse effect on our results of operations and financial condition.
Releases of regulated substances may occur and can be significant. Under certain environmental laws, we could be held responsible for all of the costs relating to any contamination at our current or former facilities and at any third party waste disposal sites used by us or on our behalf. In addition, offshore oil and natural gas exploration and production involves various hazards, including human exposure to regulated substances, which include naturally occurring radioactive, and other materials. As such, we could be held liable for any and all consequences arising out of human exposure to such substances or for other damage resulting from the release of any regulated or otherwise hazardous substances to the environment, property or to natural resources, or affecting endangered species.
In addition, we expect continued and increasing attention to climate change issues and emissions of GHGs, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of oil and natural gas combustion). For example, in April 2016, 195 nations, including Ghana, Mauritania, Sao Tome and Principe, Senegal, Suriname and the U.S., signed and officially entered into an international climate change accord (the “Paris Agreement”). The Paris Agreement calls for signatory countries to set their own GHG emissions targets, make these emissions targets more stringent over time and be transparent about the GHG emissions reporting and the measures each country will use to achieve its GHG targets. A long-term goal of the Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the pre-industrial era. The Paris Agreement is in effect a successor to the Kyoto Protocol, an international treaty aimed at reducing emissions of GHGs, to which various countries and regions, including Ghana, Mauritania, Sao Tome and Principe, Senegal and Suriname, are parties. The Kyoto Protocol has been extended by amendment until 2020. It cannot be determined at this time what effect the Paris Agreement, and any related GHG emissions targets, regulations or other requirements, will have on our business, results of operations and financial condition. It also cannot be determined what impact the U.S.'s announced withdrawal from the Paris Agreement will have on international climate change regulation. This regulatory uncertainty, however, could result in a disruption to our business or operations. The physical impacts of climate change in the areas in which our assets are located or in which we otherwise operate, including through increased severity and frequency of storms, floods and other weather events, could adversely impact our operations or disrupt transportation or other process‑related services provided by our third‑party contractors.
Health, safety and environmental laws are complex, change frequently and have tended to become increasingly stringent over time. Our costs of complying with current and future climate change, health, safety and environmental laws, the actions or omissions of our block partners and third party contractors and our liabilities arising from releases of, or exposure to, regulated substances may adversely affect our results of operations and financial condition. See “Item 1. Business—Environmental Matters” for more information.
We face various risks associated with increased activism against oil and gas exploration and development activities.
Opposition toward oil and gas drilling and development activity has been growing globally. Companies in the oil and gas industry are often the target of activist efforts from both individuals and non‑governmental organizations regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti‑development activists are working to, among other things, delay or cancel certain operations such as offshore drilling and development.
Future activist efforts could result in the following:
delay or denial of drilling permits;
shortening of lease terms or reduction in lease size;
restrictions or delays on our ability to obtain additional seismic data;
restrictions on installation or operation of gathering or processing facilities;
restrictions on the use of certain operating practices;
legal challenges or lawsuits;
damaging publicity about us;
increased regulation;

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increased costs of doing business;
reduction in demand for our products; and
other adverse effects on our ability to develop our properties and/or undertake production operations.
Activism worldwide may increase if the Trump administration in the U.S. is perceived to be following, or actually follows, through on President Trump’s campaign commitments to promote increased fossil fuel exploration and production in the U.S. Our need to incur costs associated with responding to these initiatives or complying with any resulting new legal or regulatory requirements resulting from these activities that are substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations.
We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act and other anti‑corruption laws, and any determination that we violated the U.S. Foreign Corrupt Practices Act or other such laws could have a material adverse effect on our business.
We are subject to the U.S. Foreign Corrupt Practices Act (“FCPA”) and other laws that prohibit improper payments or offers of payments to foreign government officials and political parties for the purpose of obtaining or retaining business or otherwise securing an improper business advantage. In addition, the United Kingdom has enacted the Bribery Act of 2010, and we may be subject to that legislation under certain circumstances. We do business and may do additional business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials. We face the risk of unauthorized payments or offers of payments by one of our employees, contractors or consultants. Our existing safeguards and any future improvements may prove to be less than effective in preventing such unauthorized payments, and our employees and consultants may engage in conduct for which we might be held responsible. Violations of the FCPA may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition. In addition, the U.S. government may seek to hold us liable for successor liability for FCPA violations committed by companies in which we invest in (for example, by way of acquiring equity interests in, participating as a joint venture partner with, acquiring the assets of, or entering into certain commercial transactions with) or that we acquire.
Deterioration in the credit or equity markets could adversely affect us.
We have exposure to different counterparties. For example, we have entered or may enter into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, investment funds, and other institutions. These transactions expose us to credit risk in the event of default by our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill existing obligations to us and their willingness to enter into future transactions with us. We may have exposure to these financial institutions through any derivative transactions we have or may enter into. Moreover, to the extent that purchasers of our future production, if any, rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to us if such purchasers were unable to access the credit or equity markets for an extended period of time.
We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage.
We intend to maintain insurance against certain risks in the operation of the business we plan to develop and in amounts in which we believe to be reasonable. Such insurance, however, may contain exclusions and limitations on coverage or may not be available at a reasonable cost or at all. For example, we are not insured against political or terrorism risks. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition and results of operations. Further, even in instances where we maintain adequate insurance coverage, potential delays related to receipt of insurance proceeds as well as delays associated with the repair or rebuilding of damaged facilities could also materially and adversely affect our business, financial condition and results of operations.
We operate in a litigious environment.
Some of the jurisdictions within which we operate have proven to be litigious environments. Oil and gas companies, such as us, can be involved in various legal proceedings, such as title or contractual disputes, in the ordinary course of business.

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From time to time, we may become involved in various legal and regulatory proceedings arising in the normal course of business. We cannot predict the occurrence or outcome of these proceedings with certainty, and if we are unsuccessful in these disputes and any loss exceeds our available insurance, this could have a material adverse effect on our results of operations.
Because we maintain a diversified portfolio of assets overseas, the complexity and types of legal procedures with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. If we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows. Legal proceedings could result in a substantial liability and/or negative publicity about us and adversely affect the price of our common stock. In addition, legal proceedings distract management and other personnel from their primary responsibilities.
We face various risks associated with global populism.
Globally, certain individuals and organizations are attempting to focus public attention on income distribution, wealth distribution, and corporate taxation levels, and implement income and wealth redistribution policies. These efforts, if they gain political traction, could result in increased taxation on individuals and/or corporations, as well as, potentially, increased regulation on companies and financial institutions. Our need to incur costs associated with responding to these developments or complying with any resulting new legal or regulatory requirements, as well as any potential increased tax expense, could increase our costs of doing business, reduce our financial flexibility and otherwise have a material adverse effect on our business, financial condition and results of our operations.
Slower global economic growth rates may materially adversely impact our operating results and financial position.
Market volatility and reduced consumer demand may increase economic uncertainty. Many developed countries are constrained by long term structural government budget deficits and international financial markets and credit rating agencies are pressing for budgetary reform and discipline. This need for fiscal discipline is balanced by calls for continuing government stimulus and social spending as a result of the impacts of the global economic crisis. As major countries implement government fiscal reform, such measures, if they are undertaken too rapidly, could further undermine economic recovery, reducing demand and slowing growth. Impacts of the crisis have spread to China and other emerging markets, which have fueled global economic development in recent years, slowing their growth rates, reducing demand, and resulting in further drag on the global economy.
Global economic growth drives demand for energy from all sources, including hydrocarbons. A lower future economic growth rate is likely to result in decreased demand growth for our crude oil and natural gas production. A decrease in demand, notwithstanding impacts from other factors, could potentially result in lower commodity prices, which would reduce our cash flows from operations, our profitability and our liquidity and financial position.
Increased costs of capital could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
Our derivative activities could result in financial losses or could reduce our income.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we have and may in the future enter into derivative arrangements for a portion of our oil and natural gas production, including, but not limited to, puts, collars and fixed‑price swaps. In addition, we may in the future, hold swaps designed to hedge our interest rate risk. We do not currently designate any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.
Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:
production is less than the volume covered by the derivative instruments;

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the counter‑party to the derivative instrument defaults on its contract obligations; or
there is an increase in the differential between the underlying price and actual prices received in the derivative instrument.
In addition, these types of derivative arrangements may limit the benefit we could receive from increases in the prices for oil and natural gas or beneficial interest rate fluctuations and may expose us to cash margin requirements.
Our commercial debt facility, revolving credit facility and indenture governing the Senior Notes contain certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.
Our commercial debt facility, revolving credit facility and indenture governing the Senior Notes include certain covenants that, among other things, restrict:
our investments, loans and advances and certain of our subsidiaries’ payment of dividends and other restricted payments;
our incurrence of additional indebtedness;
the granting of liens, other than liens created pursuant to the commercial debt facility, revolving credit facility or the indenture governing the Senior Notes and certain permitted liens;
mergers, consolidations and sales of all or a substantial part of our business or licenses;
the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities;
the sale of assets (other than production sold in the ordinary course of business); and
in the case of the commercial debt facility and the revolving credit facility, our capital expenditures that we can fund with the proceeds of our commercial debt facility, and revolving credit facility.
Our commercial debt facility, revolving credit facility and letter of credit facility require us to maintain certain financial ratios, such as debt service coverage ratios and cash flow coverage ratios. All of these restrictive covenants may limit our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our commercial debt facility, revolving credit facility and indenture governing the Senior Notes may be impacted by changes in economic or business conditions, our results of operations or events beyond our control. The breach of any of these covenants could result in a default under our commercial debt facility, revolving credit facility and indenture governing the Senior Notes, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under our commercial debt facility, revolving credit facility and indenture governing the Senior Notes, together with accrued interest, to be due and payable and, in the case of the letter of credit facility, the breach of any of the applicable covenants could result in a default, in which case the cash collateral we are required to maintain under the letter of credit facility would increase from 75% to 100% of all outstanding letters of credit, and if such additional cash is not posted, the lenders thereunder could elect to declare all amounts outstanding thereunder, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders, successors or assignees could proceed against their collateral. If the indebtedness under our commercial debt facility, revolving credit facility, letter of credit facility and indenture governing the Senior Notes were to be accelerated, our assets may not be sufficient to repay in full such indebtedness. In addition, the limitations imposed by the commercial debt facility, the revolving credit facility, the letter of credit facility and the indenture governing the Senior Notes on our ability to incur additional debt and to take other actions might significantly impair our ability to obtain other financing.
Provisions of our Senior Notes could discourage an acquisition of us by a third party.
Certain provisions of the indenture governing the Senior Notes could make it more difficult or more expensive for a third party to acquire us, or may even prevent a third party from acquiring us. For example, upon the occurrence of a “change of control triggering event” (as defined in the indenture governing the Senior Notes), holders of the notes will have the right, at their option, to require us to repurchase all of their notes or any portion of the principal amount of such notes. By discouraging an acquisition of us by a third party, these provisions could have the effect of depriving the holders of our common stock of an opportunity to sell their common stock at a premium over prevailing market prices.

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Our level of indebtedness may increase and thereby reduce our financial flexibility.
At December 31, 2018, we had $1,325.0 million outstanding and $375.0 million of committed undrawn capacity, which includes the $200 million in additional commitments secured in the fourth quarter of 2018, under our commercial debt facility, subject to borrowing base availability. As of December 31, 2018, we had $325 million outstanding under the Corporate Revolver and the undrawn availability was $75.0 million. As of December 31, 2018, there were seven outstanding letters of credit totaling $14.4 million under the letter of credit facility agreement and $525.0 million principal amount of Senior Notes outstanding. We also currently have, and may in the future incur, significant off balance sheet obligations. In the future, we may incur significant indebtedness in order to make investments or acquisitions or to explore, appraise or develop our oil and natural gas assets.
Our level of indebtedness could affect our operations in several ways, including the following:
a significant portion or all of our cash flows, when generated, could be used to service our indebtedness;
a high level of indebtedness could increase our vulnerability to general adverse economic and industry conditions;
the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;
a high level of indebtedness may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness could prevent us from pursuing;
our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
additional hedging instruments may be required as a result of our indebtedness;
a high level of indebtedness may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then‑outstanding bank borrowings; and
a high level of indebtedness may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.
A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, risks associated with exploring for and producing oil and natural gas, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our indebtedness and future working capital, borrowings or equity financing may not be available to pay or refinance such indebtedness. Factors that will affect our ability to raise cash through an offering of our equity securities or a refinancing of our indebtedness include financial market conditions, the value of our assets and our performance at the time we need capital.
We are a holding company and our ability to make payments on our outstanding indebtedness, including our Senior Notes and our commercial debt facility, is dependent upon the receipt of funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise.
We are a holding company, and our subsidiaries own all of our assets and conduct all of our operations. Accordingly, our ability to make payments of interest and principal on the Senior Notes and commercial debt facility will be dependent on the generation of cash flow by our subsidiaries and their ability to make such cash available to us, by dividend, debt repayment or otherwise. Unless they are guarantors, our subsidiaries will not have any obligation to pay amounts due on the notes or to make funds available for that purpose. Our subsidiaries may not be able to, or may not be permitted to, make distributions to enable us to make payments in respect of the Senior Notes or the commercial debt facility. Each subsidiary is a distinct legal entity and, under certain circumstances, legal and contractual restrictions may limit our ability to obtain cash from our subsidiaries. The indenture governing the Senior Notes limits the ability of our subsidiaries to incur consensual encumbrances or restrictions on their ability to pay dividends or make other intercompany payments to us, with significant qualifications and exceptions. In addition, the terms of the commercial debt facility limit the ability of the obligors thereunder, including our material operating subsidiaries that hold interests in our assets located offshore Ghana and Equatorial Guinea and their intermediate parent companies (other than Kosmos Energy Holdings) to provide cash to us through dividend, debt repayment or intercompany lending. In the event that we

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do not receive distributions from our subsidiaries, we may be unable to make required principal and interest payments on our indebtedness, including the Senior Notes and commercial debt facility.
We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.
We periodically evaluate acquisitions of prospects and licenses, reserves and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of these assets or businesses requires an assessment of several factors, including:
recoverable reserves;
future oil and natural gas prices and their appropriate differentials;
development and operating costs; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject assets that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the assets to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We may not be entitled to contractual indemnification for environmental liabilities and could acquire assets on an “as is” basis. Significant acquisitions and other strategic transactions may involve other risks, including:
diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those