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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10‑K
 	 	
(Mark One)	 	
☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the fiscal year ended December 31, 2016	
☐	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

Kosmos Energy Ltd.
(Exact name of registrant as specified in its charter)
 	 	
Bermuda
(State or other jurisdiction of
incorporation or organization)	98‑0686001
(I.R.S. Employer
Identification No.)	
Clarendon House
2 Church Street
Hamilton, Bermuda
(Address of principal executive offices)	HM 11
(Zip Code)	
 
Registrant’s telephone number, including area code: +1 441 295 5950
Securities registered pursuant to Section 12(b) of the Act:
 	 	
Title of each class	Name of each exchange on which registered:	
Common Shares $0.01 par value	New York Stock Exchange	
 
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well‑known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒  No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐  No ☒
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒  No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒  No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. ☒
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b‑2 of the Exchange Act.
 	 	 	 	
Large accelerated filer ☒	Accelerated filer ☐	Non‑accelerated filer ☐
(Do not check if a smaller reporting company)	Smaller reporting company ☐	
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Yes ☐  No ☒
The aggregate market value of the voting and non‑voting common shares held by non‑affiliates, based on the per‑share closing price of the registrant’s common shares as of the last business day of the registrant’s most recently completed second fiscal quarter was $849,378,870.
The number of the registrant’s Common Shares outstanding as of February 16, 2017 was 387,603,985.
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, 2016.
Certain exhibits previously filed with the Securities and Exchange Commission are incorporated by reference into Part IV of this report.

 

 
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TABLE OF CONTENTS
Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its subsidiaries. We have provided definitions for some of the industry terms used in this report in the “Glossary and Selected Abbreviations” beginning on page 2.
 	 	 	
 	 	Page	
 	Glossary and Selected Abbreviations	3 	
 	Cautionary Statement Regarding Forward‑Looking Statements	6 	
 	PART I	 	
Item 1. 	Business	8 	
Item 1A. 	Risk Factors	39 	
Item 1B. 	Unresolved Staff Comments	66 	
Item 2. 	Properties	66 	
Item 3. 	Legal Proceedings	66 	
Item 4. 	Mine Safety Disclosures	66 	
 	PART II	 	
Item 5. 	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	67 	
Item 6. 	Selected Financial Data	69 	
Item 7. 	Management’s Discussion and Analysis of Financial Condition and Results of Operations	71 	
Item 7A. 	Quantitative and Qualitative Disclosures About Market Risk	88 	
Item 8. 	Financial Statements and Supplementary Data	91 	
Item 9. 	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	131 	
Item 9A. 	Controls and Procedures	131 	
Item 9B. 	Other Information	132 	
 	PART III	 	
Item 10. 	Directors, Executive Officers and Corporate Governance	134 	
Item 11. 	Executive Compensation	134 	
Item 12. 	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	134 	
Item 13. 	Certain Relationships and Related Transactions, and Director Independence	134 	
Item 14. 	Principal Accounting Fees and Services	134 	
 	PART IV	 	
Item 15. 	Exhibits, Financial Statement Schedules	135 	
Item 16. 	Form 10-K Summary	139 	

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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”	 	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.	 	
“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 for taking on a portion of the drilling costs of one or more specific wells 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 the drilling costs of one or more specific wells 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 assets, to (y) the aggregate loan amounts outstanding under the Facility less the Resource Bridge, as applicable.	 	
“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 Jubilee Field and certain other fields in Ghana, to (y) the aggregate loan amounts outstanding under the Facility less the Resource Bridge, as applicable.	 	
“Make‑whole redemption price”	 	The “make‑whole redemption price” is equal to the outstanding principal amount of such notes plus the greater of 1) 1% of the then outstanding principal amount of such notes and 2) the present value of the notes at 103.9% and required interest payments thereon through August 1, 2017 at such redemption date.	 	
“MBbl”	 	Thousand barrels of oil.	 	
“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.	 	
“MMcf”	 	Million cubic feet 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).	 	
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“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.	 	
“Reconnaissance contract”	 	A contract in which the owner of hydrocarbons gives an E&P company rights to perform evaluation of existing data or potentially acquire additional data but may not convey an exclusive option to explore for, develop, and/or produce hydrocarbons from the lease area.	 	
“Resource Bridge”	 	Borrowing Base availability attributable to probable reserves and contingent resources from Jubilee Field Future Phases, Tweneboa, Enyenra and Ntomme fields and potentially Mahogany, Teak and Akasa fields.	 	
“Shelf margin”	 	The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.	 	
“Stratigraphy”	 	The study of the composition, relative ages and distribution of layers of sedimentary rock.	 	
“Stratigraphic trap”	 	A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.	 	
“Structural trap”	 	A topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and gas in the strata.	 	
“Structural‑stratigraphic trap”	 	A structural‑stratigraphic trap is a combination trap with structural and stratigraphic features.	 	
“Submarine fan”	 	A fan‑shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.	 	
“Three‑way fault trap”	 	A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.	 	
“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 by the governments of Ghana, Mauritania, Morocco (including Western Sahara), Sao Tome and Principe, Senegal or Suriname (or their respective national oil companies) or any other federal, state or local governments or authorities, to us;	

 	·	 	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 and natural gas 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, including an ongoing maritime boundary demarcation dispute between Cote d’Ivoire and Ghana impacting our operations in the Deepwater Tano Block offshore Ghana;	
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 	·	 	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;	

 	·	 	our vulnerability to severe weather events;	

 	·	 	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 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 leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margins. Our assets include existing production and development projects offshore Ghana, large discoveries and significant further exploration potential offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Sao Tome and Principe, Suriname, Morocco and Western Sahara. Kosmos is listed on the New York Stock Exchange (“NYSE”) and is traded under the ticker symbol KOS.
Kosmos was founded in 2003 to find oil in under‑explored or overlooked parts of West Africa. Members of the management team—who had previously worked together making significant discoveries and developing them in Africa, the Gulf of Mexico, and other areas—established the company on a single geologic concept that previously had been disregarded by others in the industry, the Late Cretaceous play system.
Following our formation, we acquired multiple exploration licenses and proved the geologic concept with the discovery of the Jubilee Field within the Tano Basin in the deep waters offshore Ghana in 2007. This was the first of our discoveries offshore Ghana; it was one of the largest oil discoveries worldwide in 2007 and is considered one of the largest finds offshore West Africa during the last decade. As technical operator of the initial phase of the Jubilee Field, we planned and executed the development. Oil production from the Jubilee Field began in November 2010, just 42 months after initial discovery, a record for a deepwater development in this water depth in West Africa.
Following our Initial Public Offering in 2011, we acquired several new exploration licenses and again proved a new geologic concept with the Ahmeyim discovery (formerly known as Tortue) in the deepwater offshore Mauritania in 2015. 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. We have since demonstrated the extension of this gas discovery into Senegal with the successful Guembeul-1 exploration well, which we collectively call the Greater Tortue discovery. We have now drilled five exploration and appraisal wells offshore Mauritania and Senegal with a 100% success rate, and in aggregate have discovered a gross potential natural gas resource of approximately 25 trillion cubic feet and derisked over 50 trillion cubic feet.
 
In December 2016, we announced a partnership with affiliates of BP p.l.c. (‘‘BP’’) in Mauritania and Senegal following a competitive farm-out process for our interests in our blocks offshore Mauritania and Senegal. We believe BP is the optimal partner to advance the gas developments in these blocks and to move forward a multi-well exploration program to fully exploit the hydrocarbon potential of the basin and test its liquids potential, currently scheduled to commence in the second quarter of 2017. In Mauritania, BP acquired a 62% participating interest in our four Mauritania licenses (C6, C8, C12 and C13). In Senegal, BP acquired a 49.99% interest in Kosmos BP Senegal Limited, our controlled affiliate company which holds a 65% participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks offshore Senegal. The participating interest gives effect to the completion of our exercise in December 2016 of an option to increase our equity in each contract area from 60% to 65% in exchange for carrying Timis Corporation’s paying interest share of a third well in either contract area, subject to a maximum gross cost of $120.0 million. In consideration for these transactions, Kosmos will receive $162 million in cash up front, $221 million exploration and appraisal carry, up to $533 million in a development carry and variable consideration up to $2 per barrel for up to 1 billion barrels of liquids, structured as a production royalty, subject to future liquids discovery and prevailing oil prices. We believe that these transactions will accelerate the development of the discovered gas resources, ensure the execution of an appropriately sized exploration program and strengthen our balance sheet by reducing our capital expenditure requirements and provide funding for our Mauritania and Senegal exploration and development program over the near to medium term.
 
Our business strategy focuses on achieving four key objectives: (1) maximize the value of our Ghana assets; (2) develop our discovered resources offshore Mauritania and Senegal; (3) continue to explore, appraise and develop the deepwater basin offshore Mauritania and Senegal to further grow value; and (4) increase value further through a high‑impact exploration program which is designed to unlock new petroleum systems. In Ghana, we are focused on increasing production, cash flows and reserves from the Jubilee and Tweneboa‑Enyenra‑Ntomme (“TEN”) fields, and the
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appraisal and development of our other Ghanaian discoveries. In Mauritania and Senegal, we expect to fully appraise and develop our current Greater Tortue discovery with the objective of making a final investment decision during 2018 and producing first gas as soon as 2021, as well as continue to test our inventory of oil and gas prospects. We also have a large inventory of leads and prospects in the remainder of our exploration portfolio which we plan to continue to mature. We plan to test the prospectivity of high impact opportunities in the coming years along the Atlantic Margins.
Our Business Strategy
Grow proved reserves and production through exploration, appraisal and development
In the near‑term we plan to grow proved reserves and production by further developing the Jubilee Field, including incorporating our Mahogany and Teak discoveries into the Greater Jubilee Full Field Development Plan (“GJFFDP”) and by increasing production at TEN through further development after delivering first oil in August 2016 through a second, dedicated FPSO. In the medium-term, growth could also be realized through the development of all or a portion of our new discoveries in Mauritania and Senegal.
Focus on optimally developing our discoveries to initial production
Our development focus is designed to accelerate production, deliver early learnings and maximize returns. In certain circumstances, we believe a phased approach can be employed to optimize full‑field development through a better understanding of dynamic reservoir behavior and enable activities to be performed in a parallel rather than a sequential manner. A phased approach also facilitates refinement of the development plans based on experience gained in initial phases of production and by leveraging existing infrastructure as subsequent phases of development are implemented. Production and reservoir performance from the initial phase are monitored closely to determine the most efficient and effective techniques to maximize the recovery of reserves and returns. Other benefits include minimizing upfront capital costs, reducing execution risks through smaller initial infrastructure requirements, and enabling cash flow from the initial phase of production to fund a portion of capital costs for subsequent phases. In contrast, a traditional development approach consists of full appraisal, conceptual engineering, preliminary engineering, detailed engineering, procurement and fabrication of facilities, development drilling and installation of facilities for the full‑field development, all performed sequentially, before first production is achieved. This approach can considerably lengthen the time from discovery to first production.
For example, post‑discovery in 2007, first oil production from the Jubilee Field commenced in November 2010. This development timeline from discovery to first oil was significantly less than the seven to ten year industry average and set a record for a deepwater development of this size and scale at this water depth in West Africa. This condensed timeline reflects the lessons learned by our experienced team while leading other large scale deepwater developments.
Successfully open and develop our offshore exploration plays
We believe the prospects and leads offshore Mauritania, Senegal, Sao Tome and Principe, Suriname, Morocco and Western Sahara provide favorable opportunities to create substantial value through exploration drilling. Starting in the second quarter of 2017, we plan to resume our exploration drilling to test this potential in Mauritania and Senegal and in other areas starting in 2018. Given the potential size of these prospects and leads, we believe that exploratory success in our operating areas could significantly add to our growth profile.
Identify, access and explore emerging regions and hydrocarbon plays
Our management and exploration teams have demonstrated an ability to identify regions and hydrocarbon plays that have the potential to yield multiple large commercial discoveries. We focus on frontier and emerging areas that have been underexplored yet offer attractive commercial terms as a result of reduced competition and first‑mover advantage. We expect to continue to use our systematic and proven geologically‑focused approach in frontier and emerging petroleum systems where geological data suggests hydrocarbon accumulations are likely to exist, but where commercial discoveries have yet to be made. We believe this focus on poorly understood, under‑explored or otherwise overlooked hydrocarbon basins enables us to unlock significant hydrocarbon potential and create substantial value for shareholders.
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This approach and focus, coupled with a first‑mover advantage and our management and technical teams’ discipline in execution, provide a competitive advantage in identifying and accessing new strategic growth opportunities. We expect to continue seeking new opportunities where hydrocarbons have not been discovered or produced in meaningful quantities by leveraging the reputation and relationships of our experienced technical and management teams. This includes our existing areas of interest as well as selectively expanding our reach into other locations.
In addition to ideas developed organically, farm‑in opportunities may offer a way to participate in new venture opportunities to undertake exploration in emerging basins, new plays and fairways to enhance and optimize our portfolio. Consistent with this strategy, we may also evaluate potential corporate and asset acquisition opportunities as a source of new ventures to support and expand our asset portfolio.
Kosmos Exploration Approach
Kosmos’ exploration philosophy is deeply rooted in a fundamental, geologically‑based approach geared toward the identification of poorly understood, under‑explored or overlooked petroleum systems. This process begins with detailed geologic studies that methodically assess a particular region’s subsurface, with careful consideration given to those attributes that suggest working petroleum systems. The process includes basin modeling to predict oil or gas charge and fluid migration, as well as stratigraphic and structural analysis to identify reservoir/seal pair development and trap definition. This analysis integrates data from previously drilled wells, where available, and seismic data. Importantly, this approach also takes into account a detailed analysis of geologic timing to ensure that we have an appropriate understanding of whether the sequencing of geological events could promote and preserve hydrocarbon accumulations. Once an area is high‑graded based on this play/fairway analysis, geophysical analysis based on new 3D seismic is conducted to identify prospective traps of interest.
Alongside the subsurface analysis, Kosmos performs an analysis of country‑specific risks to gain an understanding of the “above‑ground” dynamics, which may influence a particular country’s relative desirability from an overall oil and natural gas operating and risk‑adjusted return perspective. This process is employed in both areas that have existing oil and natural gas production, as well as those regions that have yet to achieve commercial hydrocarbon production.
Once an area of interest has been identified, Kosmos targets licenses over the particular basin or fairway to achieve an early‑mover or in many cases a first‑mover advantage. In terms of license selection, Kosmos targets specific regions that have sufficient size to manage exploration risks and provide scale should the exploration concept prove successful. Kosmos also looks for long‑term contract duration to enable the “right” exploration program to be executed, play type diversity to provide multiple exploration concept options, prospect dependency to enhance the chance of replicating success and sufficiently attractive fiscal terms to maximize the commercial viability of discovered hydrocarbons.
Apply our entrepreneurial culture, which fosters innovation and creativity, to continue our successful exploration and development program
Our geoscientists and engineers are critical to the success of our business strategy and we have created an environment that enables them to focus their knowledge, skills and experience on finding and developing new fields. Culturally, we have an open, team‑oriented work environment that fosters entrepreneurial, creative and contrarian thinking. This approach enables us to fully consider and understand both risk and reward, as well as deliberately and collectively pursue strategies that create and maximize value. This philosophy and approach was successfully utilized offshore Ghana, Mauritania and Senegal, resulting in the discovery of significant new petroleum systems, which the industry previously did not consider either prospective or commercially viable.
Build the right strategic partnerships with complementary capabilities
We look to partner with high quality, industry players with world‑class complementary capabilities early in our exploration projects. This strategy is designed to ensure that upon successful exploration and appraisal activities, the project can benefit from specific expertise provided by these partners, including exploration, development, production and above-ground capabilities. We have proven we can execute this with BP in Mauritania and Senegal, and Chevron Corporation (“Chevron”) and Hess Corporation (“Hess”) in Suriname and Galp Energia Sao Tome E Principe, Unipessoal, LDA
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(“Galp”) in Sao Tome and Principe. In addition, bringing in the right strategic partners early in our projects, typically comes with a financial carry on future expenditures, allowing us to reduce our cost basis and increase return on investment.
Maintain Financial Discipline
We strive to maintain a conservative financial profile and strong balance sheet with ample liquidity. Typically, we fund exploration and development activities from a combination of operating cash flows, debt or partner carries. As of December 31, 2016, we have approximately $1.2 billion of liquidity available to fund our opportunities. In the fourth quarter of 2016, with growing cash flow from our Ghana assets and reduced capital expenditures as the TEN fields came into production, Kosmos generated positive cash flow from operations which is expected to continue into 2017.
Additionally, we use derivative instruments to partially limit our exposure to fluctuations in oil prices and interest rates. We have an active commodity hedging program where we hedge a portion of our anticipated sales volumes on a two‑to‑three year rolling basis. As of December 31, 2016, we have hedged positions covering 9.9 million barrels of oil in 2017 and 2018 oil production, which provide partial downside protection should Dated Brent oil prices remain below our floor prices. We also maintain insurance to partially protect against loss of production revenues from our Jubilee and TEN assets.
Operations by Geographic Area
We currently have operations in Africa and South America. Currently, all operating revenues are generated from our operations offshore Ghana.
Our Discoveries
Information about our deepwater discoveries is summarized in the following table.
 	 	 	 	 	 	 	 	 	 	
 	    	 	 	Kosmos	 	 	 	 	 	
 	 	 	 	Participating	 	 	 	 	 	
Discoveries	    	License	    	Interest	 	Operator	 	Stage	 	
Ghana	 	 	 	 	 	 	 	 	 	
Jubilee Field Phase 1 and Phase 1A(1)	 	WCTP/DT	(2)	24.1	% (4)	Tullow	 	Production	 	
Jubilee Field subsequent phases	 	WCTP/DT	(2)	24.1	% (4)	Tullow	 	Development	 	
TEN(1)	 	DT	 	17.0	% (5)	Tullow	 	Production	 	
Mahogany	 	WCTP	 	24.1	% (6)	Kosmos	(6)	Appraisal	 	
Teak	 	WCTP	 	24.1	% (6)	Kosmos	(6)	Appraisal	 	
Akasa	 	WCTP	 	30.9	% (6,7)	Kosmos	 	Appraisal	 	
Wawa	 	DT	 	18.0	% (7)	Tullow	 	Appraisal	 	
Mauritania	 	 	 	 	 	 	 	 	 	
Ahmeyim	 	Block C8	(3)	28.0	% (8)	BP	 	Appraisal	 	
Marsouin	 	Block C8	 	28.0	% (8)	BP	 	Appraisal	 	
Senegal	 	 	 	 	 	 	 	 	 	
Guembeul	 	Saint Louis Offshore Profond	(3)	65.0	% (9)	Kosmos BP Senegal Limited	(9)	Appraisal	 	
Teranga	 	Cayar Offshore Profond	 	65.0	% (9)	Kosmos BP Senegal Limited	(9)	Appraisal	 	

 	(1)	 	For information concerning our estimated proved reserves as of December 31, 2016, 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. In order to optimize resource recovery in this field, we entered into the Unitization and Unit Operating Agreement (the “UUOA”) in July 2009 with Ghana National Petroleum Corporation (“GNPC”) and the other block partners of each of these two blocks. The 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.	

 	(3)	 	The Greater Tortue resource, 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.	
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We have entered into a Memorandum of Understanding (“MOU”) signed by Societe des Petroles du Senegal (“PETROSEN”) and Societe Mauritanienne des Hydrocarbures et de Patrimoine Minier (“SMHPM”), the national oil companies of Senegal and Mauritania, respectively, which sets out the principles for an intergovernmental cooperation agreement for the development of the cross-border Greater Tortue resource.	

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

 	(5)	 	Our paying interest on development activities in the TEN fields is 19%.	

 	(6)	 	In September 2015, GNPC exercised its WCTP petroleum contract option, with respect to the Mahogany and Teak discoveries, to acquire an additional paying interest of 2.5%. We signed the Jubilee Field Unit Expansion Agreement with our partners in November 2015. This allows for the Mahogany and Teak discoveries to be included in the GJFFDP. Upon approval of the GJFFDP by Ghana’s Ministry of Energy, (a) the Jubilee Unit will be expanded to include the Mahogany and Teak discoveries, (b) revenues and expenses associated with these discoveries will be at the Jubilee Unit interests, and (c) operatorship of the Mahogany and Teak discoveries will be transferred to Tullow as Jubilee Unit operator. These interest percentages give effect to the exercise of GNPC’s option and approval of the GJFFDP. Our paying interest on development activities in these discoveries is 26.9%. Our participating interest as of December 31, 2016 is 30.0%. Additionally, the WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow after approval of the GJFFDP by Ghana’s Ministry of Energy.	
 
 	(7)	 	GNPC has the option to acquire additional paying interests in a commercial discovery on the WCTP Block and the DT Block of 2.5% and 5.0%, respectively. These interest percentages do not give effect to the exercise of such options.	

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

 	(9)	 	Kosmos BP Senegal Limited is a controlled affiliate of Kosmos in which we own a 50.01% interest and BP owns a 49.99% interest. The participating interest gives effect to the completion of our exercise in December 2016 of an option to increase our equity in each contract area from 60% to 65% in exchange for carrying Timis Corporation’s paying interest share of a third well in either contract area, subject to a maximum gross cost of $120.0 million. 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.	
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Exploration License Areas(1)
 	 	 	 	 	 	
 	 	Operator	 	 	 	
 	 	(Participating	 	 	 	
 	    	Interest)	    	Partners (Participating Interest)	 	
Mauritania	 	 	 	 	 	
Block C6	 	BP (62%)	(2)	Kosmos (28%), SMHPM (10%)	 	
Block C8	 	BP (62%)	(2)	Kosmos (28%), SMHPM (10%)	 	
Block C12	 	BP (62%)	(2)	Kosmos (28%), SMHPM (10%)	 	
Block C13	 	BP (62%)	(2)	Kosmos (28%), SMHPM (10%)	 	
Morocco (including Western Sahara)	 	 	 	 	 	
Boujdour Maritime	 	Kosmos (55%)	 	Cairn (20%), ONHYM (25%)	 	
Essaouira	 	Kosmos (75%)	 	ONHYM (25%)	 	
Sao Tome and Principe	 	 	 	 	 	
Block 5	 	Kosmos (45%)	 	Galp (20%), Equator (20%), ANP (15%),	 	
Block 6	 	Galp (45%)	 	Kosmos (45%), ANP (10%)	 	
Block 11	 	Kosmos (65%)	 	Galp (20%), ANP (15%)	 	
Block 12	 	Kosmos (45%)	 	Galp (20%), Equator (22.5%), ANP (12.5%),	 	
Senegal	 	 	 	 	 	
Cayar Offshore Profond	 	Kosmos BP Senegal Limited (65%)	(3)	Timis (25%), PETROSEN (10%)	 	
Saint Louis Offshore Profond	 	Kosmos BP Senegal Limited (65%)	(3)	Timis (25%), PETROSEN (10%)	 	
Suriname	 	 	 	 	 	
Block 42	 	Kosmos (33%)	 	Chevron (33%), Hess (33%)	 	
Block 45	 	Kosmos (50%)	 	Chevron (50%)	 	

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

 	(2)	 	BP is the operator of record while Kosmos will provide technical exploration operator services.	

 	(3)	 	Kosmos BP Senegal Limited is a controlled affiliate of Kosmos in which we own a 50.01% interest and BP owns a 49.99% interest. The participating interest gives effect to the completion of our exercise in December 2016 of an option to increase our equity in each contract area from 60% to 65% in exchange for carrying Timis Corporation’s paying interest share of a third well in either contract area, subject to a maximum gross cost of $120.0 million. 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.	
Ghana
The WCTP Block and DT Block are located within the Tano Basin, offshore Ghana. This basin contains a proven world‑class petroleum system as evidenced by our discoveries.
The Tano Basin represents the eastern extension of the Deep Ivorian Basin which resulted from the development of an extensional sedimentary basin caused by tensional forces associated with opening of the Atlantic Ocean, as South America separated from Africa in the Mid‑Cretaceous period. The Tano Basin forms part of the resulting transform margin which extends from Sierra Leone to Nigeria.
The Tano Basin sediments comprise a thick Upper Cretaceous, deepwater turbidite sequence which, in combination with a modest Tertiary section, provided sufficient thickness to mature an early to Mid‑Cretaceous source rock in the central part of the Tano Basin. This well‑defined reservoir and charge fairway forms the play which, when draped over the South Tano high (a structural high dipping into the basin), resulted in the formation of trapping geometries.
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The primary reservoir types consist of well‑imaged Turonian and Campanian aged submarine fans situated along the steeply dipping shelf margin and trapped in an up dip direction by thinning of the reservoir and/or faults. Many of our discoveries have similar trap geometries.
The following is a brief discussion of our discoveries to date on our license areas offshore Ghana.
Jubilee Field
The Jubilee Field was discovered by Kosmos in 2007, with first oil produced in November 2010. Appraisal activities confirmed that the Jubilee discovery straddled the WCTP and DT Blocks. Pursuant to the terms of the UUOA, the discovery area was unitized for purposes of joint development by the WCTP and DT Block partners. Our current unit interest is 24.1%.
The Jubilee Field is a combination structural‑stratigraphic trap with reservoir intervals consisting of a series of stacked Upper Cretaceous Turonian‑aged, deepwater turbidite fan lobe and channel deposits.
The Jubilee Field is located approximately 37 miles offshore Ghana in water depths of approximately 3,250 to 5,800 feet, which led to the decision to implement an FPSO based development. The FPSO is designed to provide water and natural gas injection to support reservoir pressure, to process and store oil and to export gas through a pipeline to the mainland. The Jubilee Field is being developed in a phased approach. The Phase 1 development focused on partial development of certain reservoirs in the Jubilee Field. The Kosmos‑led Integrated Project Team (“IPT”) successfully executed the initial 17 well development plan, which included nine producing wells that produced through subsea infrastructure to the “Kwame Nkrumah” FPSO, six water injection wells and two natural gas injection wells. This initial phase provided subsea infrastructure capacity for additional production and injection wells to be drilled in future phases of development.
The Phase 1A development plan provided further development to the currently producing Jubilee Field reservoirs. The Phase 1A development included the drilling of eight additional wells consisting of five production wells and three water injection wells. Approval was given for an additional well, a gas injector, considered as part of Phase 1A. The Phase 1A Addendum PoD was submitted to the Ministry of Energy in June 2015 and deemed approved in July 2015 to enable drilling and completion of two additional wells consisting of one production well and one water injection well.
In November 2015, we signed the Jubilee Field Unit Expansion Agreement with our partners to allow for the development of the Mahogany and Teak discoveries through the Jubilee FPSO and infrastructure. The expansion of the Jubilee Unit becomes effective upon approval of the GJFFDP by Ghana’s Ministry of Energy. The GJFFDP was submitted to the government of Ghana in December 2015 and is expected to be resubmitted in 2017 to address comments received from the Ministry of Energy. The GJFFDP includes further development of the three producing reservoirs and final development of the two remaining reservoirs to maximize ultimate recovery and asset value.
The Government of Ghana completed the construction and connection of a gas pipeline from the Jubilee Field to transport natural gas to the mainland for processing and sale. In November 2014, the transportation of gas produced from the Jubilee Field commenced through the gas pipeline to the onshore gas plant. However, the uptime of the facility during 2017 and in future periods is not known. In the absence of the continuous export of large quantities of natural gas from the Jubilee Field it is anticipated that we will need to reinject or flare such natural gas. Our inability to continuously export associated natural gas in large quantities from the Jubilee Field could impact our oil production.
In prior years, certain near wellbore productivity issues were identified, impacting several Phase 1 production wells. The Jubilee Unit partners identified a means of successfully mitigating the near wellbore productivity issues with ongoing acid stimulation treatments. We have also experienced mechanical issues in the Jubilee Field, including failures of our water injection facilities on the FPSO and water and gas injection wells. This equipment downtime negatively impacted past oil production. We are in the process of correcting mechanical issues experienced in the Jubilee Field.
In February 2016, the Jubilee Field operator identified an issue with the turret bearing of the FPSO Kwame Nkrumah. This necessitated the FPSO to be shut down for an extended period beginning in March with production resuming in early May. This resulted in the need to implement new operating and offloading procedures, including the use of tug boats for heading control and a dynamically positioned (“DP”) shuttle tanker and storage vessel for offloading.
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These new operating procedures were successfully implemented in April 2016 and are working effectively as evidenced by the fact that 81 parcels have been offloaded from the FPSO since implementation through December 31, 2016. Oil production from the Jubilee Field averaged approximately 73,700 barrels (gross) of oil per day during 2016.
Kosmos and its partners have determined the preferred long-term solution to the turret bearing issue is to convert the FPSO to a permanently spread moored facility, with offloading through a new deepwater Catenary Anchor Leg Mooring (“CALM”) buoy. The partners are now working with the Government of Ghana to amend the field operating philosophy for this field remediation solution. The Jubilee turret remediation work is progressing as planned and the FPSO spread-mooring on its current heading is expected to be completed by March 2017. This will allow the tug boats previously required to hold the vessel on a fixed heading to be removed, significantly reducing the complexity of the current operation. The next phase of the remediation work involves modifications to the turret for long-term spread-moored operations. At present, the partnership is evaluating options to select the optimal long-term orientation and to determine if a rotation of the FPSO is necessary. This evaluation is ongoing amongst the partnership and the Government of Ghana, and final decisions and approvals are expected in the first half of 2017. A facility shutdown of up to 12 weeks may be required during 2017. However, significant efforts are ongoing within the partnership to reduce the duration of the shutdown.
 
A deepwater CALM buoy, anticipated to be installed in 2018, is intended to restore full offloading functionality and remove the need for the DP shuttle and storage tankers and associated operating costs. Market inquiries are currently ongoing to estimate the cost and schedule for the fabrication and installation of this buoy. This phase of work also requires approval of both the Government of Ghana and the Jubilee Unit partners.
 
The financial impact of lower Jubilee production as well as the additional expenditures associated with the damage to the turret bearing is being mitigated through a combination of the comprehensive Hull and Machinery insurance (“H&M”), procured by the operator, Tullow, on behalf of the Jubilee Unit partners, and the corporate Loss of Production Income (“LOPI”) insurance procured by Kosmos. Both LOPI and H&M insurance coverages have been confirmed by our insurers and payments are being received. Our LOPI coverage for this incident ends in May 2017. 
TEN Fields
The Tweneboa, Enyenra and Ntomme fields (“TEN”) are located in the western and central portions of the DT Block, approximately 30 miles offshore Ghana in water depths of approximately 3,300 to 5,700 feet. In November 2012, we submitted a declaration of commerciality and PoD over the TEN discoveries. In May 2013, the government of Ghana approved the TEN PoD. The discoveries are being jointly developed with shared infrastructure and a single FPSO.
The TEN fields consist of multiple stratigraphic traps with reservoir intervals consisting of a series of stacked Upper Cretaceous Turonian‑aged, deepwater fan lobes and channel deposits.
The TEN fields are being developed in a phased manner. The plan of development for TEN was designed to include an expandable subsea system that would provide for multiple phases. Phase 1 of the TEN fields includes the drilling and completion of up to 17 wells, 11 of which have been completed. Seven additional development wells are expected to be drilled during Phase 2. The remaining Phase 1 and Phase 2 wells are a combination of production wells and water or gas injection wells needed to maximize recovery. The remainder of Phase 1 and all Phase 2 drilling is dependent on the International Tribunal for the Law of the Sea (the “ITLOS”) ruling expected by late 2017. See “Item 1A. Risk Factors—A maritime boundary demarcation between Côte D’Ivoire and Ghana may affect a portion of our license areas offshore Ghana.” for additional information.
Following first oil from the TEN fields in August 2016, oil production and water injection systems were commissioned and are now operational and gas compression and injection commissioning is ongoing. In early January 2017, the capacity of the FPSO was successfully tested at an average rate of 80,000 Bopd during a short-term flow test. Future development of non-associated gas resources at the TEN fields is anticipated before August 2018. However, due to certain issues with managing pressures in the Enyenra reservoir and because no new wells can be drilled until after the previously disclosed ITLOS ruling expected later in 2017, the operator has elected to manage the existing wells in a prudent manner to optimize long-term recovery over the lifetime of the field. Work continues among the project partners to consider ways to increase production. This reservoir management is not expected to negatively impact the ultimate field recovery. The TEN fields are expected to increase towards FPSO capacity of 80,000 Bopd once development progresses.
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The construction and connection of a gas pipeline between the Jubilee and TEN fields to transport natural gas to the mainland for processing and sale is expected to be completed in the first quarter of 2017. However, the uptime of the gas processing facility during 2017 and in future periods is not known. Our inability to continuously export associated natural gas in large quantities from the TEN fields could impact our oil production.
Other Ghana Discoveries
Mahogany is located within the WCTP Block, southeast of the Jubilee Field. The field is approximately 37 miles offshore Ghana in water depths of approximately 4,100 to 5,900 feet. We believe the field is a combination stratigraphic‑structural trap with reservoir intervals contained in a series of stacked Upper Cretaceous Turonian‑aged, deepwater fan lobe and channel deposits.
The Teak discovery is located in the western portion of the WCTP Block, northeast of the Jubilee Field. The field is approximately 31 miles offshore Ghana in water depths of approximately 650 to 3,600 feet. We believe the field is a structural‑stratigraphic trap with an element of four‑way closure.
The Akasa discovery is located in the western portion of the WCTP Block approximately 31 miles offshore Ghana in water depths of approximately 3,200 to 5,050 feet. The discovery is southeast of the Jubilee Field. We believe the target reservoirs are channels and lobes that are stratigraphically trapped. The Akasa‑1 well intersected oil bearing reservoirs in the Turonian zones. Fluid samples recovered from the well indicate an oil gravity of 38 degrees API.
The GJFFDP incorporating the Mahogany and Teak discoveries was submitted to the Ghanaian Ministry of Energy in December 2015. While we are currently in discussions with the government of Ghana, we can give no assurance that approval by the Ministry of Energy will be forthcoming in a timely manner or at all. We signed the Jubilee Field Unit Expansion Agreement with our partners in November 2015. This allows the Mahogany and Teak discoveries to be developed contemporaneously with the Jubilee Field. Upon approval of the GJFFDP by the Ministry of Energy, the Jubilee Unit will be expanded to include the Mahogany and Teak discoveries and revenues and expenses associated with these discoveries will be at the Jubilee Unit interests. We are currently in discussions with the government of Ghana regarding additional technical studies and evaluation that we want to conduct before we are able to make a determination regarding commerciality of the Akasa discovery. Additionally, the WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow after approval of the GJFFDP by Ghana’s Ministry of Energy.
The Wawa discovery is located within the DT Block, north of the TEN fields. The Wawa‑1 exploration well intersected oil and gas‑condensate in a Turonian‑aged turbidite channel system. In April 2016, the Ghana Ministry of Energy approved our request to enlarge the TEN development and production area subject to continued subsurface and development concept evaluation, along with the requirement to integrate the Wawa Discovery into the TEN PoD.
Mauritania
Kosmos holds a 28% participating interest and BP (the operator) holds a 62% participating interest in four offshore blocks, C6, C8, C12 and C13, which are located on the western margin of the Mauritania Salt Basin. These blocks are located in a proven petroleum system, with our primary targets being Cretaceous sands in structural and stratigraphic traps. We believe that the Triassic salt basin formed at the onset of rifting and contains Jurassic, Cretaceous and Tertiary passive margin sequences of limestones, sandstone and shales. Interpretation of available geologic and geophysical data has identified Cretaceous slope channels and basin floor fans in trapping geometries outboard of the Salt Basin as the key exploration objective. Multiple Cretaceous source rocks penetrated by wells and typed to oils and gases in the Mauritania Salt Basin are the same age as those which charge other oil and gas fields in West Africa.
A portion of this acreage is located outboard of the Chinguetti Field and ranges in water depth from 330 to 9,800 feet. These blocks cover an aggregate area of approximately 6.0 million acres. We have acquired approximately 6,300 line-kilometers of 2D seismic data and 15,800 square kilometers of 3D seismic data covering portions of our blocks in Mauritania. Based on these 2D and 3D seismic programs, we have drilled two successful exploration wells and an appraisal well, and have identified numerous additional prospects in our blocks. We continue to integrate the results of our successful drilling program in Mauritania to identify and mature primary targets for drilling. We anticipate drilling two exploration wells in Mauritania during our four well program that commences in the second quarter of 2017.
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Senegal
Kosmos BP Senegal Limited, a controlled affiliate of Kosmos (owned 50.01% by Kosmos and 49.99% by BP) is the operator of the Cayar Offshore Profond and Saint Louis Offshore Profond Blocks offshore Senegal. The blocks are located in the Senegal River Cretaceous petroleum system and range in water depth from 980 to 10,200 feet. The area is an extension of the working petroleum system in the Mauritania Salt Basin. We believe the area has multiple Cretaceous source rocks with Albo‑Cenomanian reservoir sands providing exploration targets. We acquired approximately 7,000 square kilometers of 3D seismic data over the central and eastern portions of the Cayar Offshore Profond and Saint Louis Offshore Profond blocks in January 2015. In February 2016, we completed a 4,500 square kilometer survey over the western portions of both blocks to fully evaluate the prospectivity. We have identified numerous prospects in our blocks and we continue to mature these for drilling. We anticipate drilling two exploration wells in Senegal during our four well program that commences in the second quarter of 2017.
The following is a brief discussion of our discoveries to date offshore Mauritania and Senegal.
Greater Tortue Discovery
The Ahmeyim and Guembeul discoveries (“Greater Tortue”) are significant, play-opening gas discoveries for the outboard Cretaceous petroleum system and are located approximately 75 miles offshore Mauritania and Senegal. The Greater Tortue discovery straddles Block C8 offshore Mauritania and Saint Louis Offshore Profond offshore Senegal.
We have now drilled three wells within the Greater Tortue discovery. The wells penetrated multiple excellent quality gas reservoirs, including the Lower Cenomanian, Upper Cenomanian and underlying Albian. The wells successfully delineated the Ahmeyim and Guembeul gas discoveries and demonstrated reservoir continuity, as well as static pressure communication between the three wells drilled within the Lower Cenomanian reservoir. The discovery ranges in water depths from 8,850 feet to 9,200 feet, with total depths drilled ranging from 16,700 feet to 17,200 feet.
The Tortue-1 discovery well, located in Block C8 offshore Mauritania, intersected approximately 117 meters (383 feet) of net hydrocarbon pay. A single gas pool was encountered in the Lower Cenomanian objective, which is comprised of three reservoirs totaling 88 meters (288 feet) in thickness over a gross hydrocarbon interval of 160 meters (528 feet). A fourth reservoir totaling 19 meters (62 feet) was penetrated within the Upper Cenomanian target over a gross hydrocarbon interval of 150 meters (492 feet). The exploration well also intersected an additional 10 meters (32 feet) of net hydrocarbon pay in the lower Albian section, which is interpreted to be gas.
The Guembeul-1 discovery well, located in the northern part of the Saint Louis Offshore Profond area in Senegal, is located approximately three miles south of the Tortue-1 exploration well in Mauritania. The well encountered 101 meters (331 feet) of net gas pay in two excellent quality reservoirs, including 56 meters (184 feet) in the Lower Cenomanian and 45 meters (148 feet) in the underlying Albian, with no water encountered.
The Ahmeyim-2 appraisal well is located in Block C8 offshore Mauritania, approximately three miles northwest, and 200 meters down-dip of the basin-opening Tortue-1 discovery. The well confirmed significant thickening of the gross reservoir sequences down-dip. The Ahmeyim-2 well encountered 78 meters (256 feet) of net gas pay in two excellent quality reservoirs, including 46 meters (151 feet) in the Lower Cenomanian and 32 meters (105 feet) in the underlying Albian.
 
Other Mauritania and Senegal Discoveries
The BirAllah discovery (formally known as Marsouin), located in Block C8 offshore Mauritania, is a significant, play-extending gas discovery, building on our successful exploration program in the outboard Cretaceous petroleum system offshore Mauritania. The Marsouin-1 well is located approximately 37 miles north of the Ahmeyim discovery and was drilled to a total depth of 16,900 feet in nearly 7,900 feet of water. Based on analysis of drilling results and logging data, Marsouin-1 encountered at least 70 meters (230 feet) of net gas pay in Upper and Lower Cenomanian intervals comprised of excellent quality reservoir sands.
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The Teranga discovery is located in the Cayar Offshore Profond block approximately 40 miles northwest of Dakar, and was our second exploration well offshore Senegal. The Teranga-1 discovery well is located in nearly 5,900 feet of water and was drilled to a total depth of 15,900 feet. The well encountered 31 meters (102 feet) of net gas pay in good quality reservoir in the Lower Cenomanian objective. Well results confirm that a prolific inboard gas fairway extends approximately 125 miles south from the Marsouin-1 well in Mauritania through the Greater Tortue area on the maritime boundary to the Teranga-1 well in Senegal.
We have now drilled five exploration and appraisal wells offshore Mauritania and Senegal with a 100% success rate, which collectively have discovered a gross potential natural gas resource of approximately 25 trillion cubic feet and as such derisked over 50 trillion cubic feet in the basin.
 
Suriname
We are the operator for petroleum contracts covering Block 42 and Block 45 offshore Suriname, which are located within the Guyana Suriname Basin, along the Atlantic transform margin of northern South America. Suriname lies between Guyana to the north and French Guyana to the south. The Guyana-Suriname Basin was formed by tensional forces associated with the opening of the Atlantic Ocean as South America separated from Africa in the Mid Cretaceous period. The Suriname basin is considered similar to the working petroleum systems of the West African transform margin. The emerging petroleum system in Suriname has been proven by the presence of onshore producing fields and most recently by nearby discoveries offshore Guyana, including the Liza-1 well.
Suriname Block 42 and Block 45 are positioned centrally in the Suriname-Guyana Basin, and located to the southeast of the recent play opening Liza-1 oil discovery. Likewise, the blocks are also positioned to the northwest of the French Guyana Basins’ Zaedyus oil discovery.
We believe that there are several independent play types of importance on our operated blocks. Of note are the listric faulted structural stratigraphic play of the lower Cretaceous and the stratigraphically trapped Upper Cretaceous plays similar to those discovered in the Jubilee Field offshore West Africa. The recent oil discovery in Guyana (Liza-1) in the same geologic basin provides a positive point of calibration for the Upper Cretaceous stratigraphic play in Suriname. 
Target reservoirs in our blocks are similar Upper and Middle Cretaceous age basin floor fans and mid slope channel sands. Seismic evidence suggests thick Late Cretaceous and Tertiary reservoir systems may be present in the deep water area demonstrated by Liza-1.
The Tambaredjo and Calcutta Fields onshore Suriname as well as the Liza-1 well discovery offshore Guyana demonstrate that a working petroleum system exists, and geological and geochemical studies suggest the hydrocarbons in these fields were generated from source rocks located in the offshore basin. The source rocks are believed to be similar in age to those which charged some of the fields offshore West Africa.
During 2012, we completed a 3D seismic data acquisition program which covered approximately 3,900 square kilometers over portions of Block 42 and Block 45 offshore Suriname. In August 2013, we completed a 2D seismic program of approximately 1,400 line kilometers over a portion of Block 42, outside of the existing 3D seismic survey. The processing of the seismic data was completed during 2014.
In December 2015, we received an extension of Phase 1 of the Exploration Period for Block 42 offshore Suriname which now expires in September 2018.
In April 2016, we received an extension of Phase 1 of the Exploration Period for Block 45 offshore Suriname which now expires in September 2018.
In January 2017, we completed a 3D seismic survey of approximately 6,500 square kilometers over Block 42 and Block 45 offshore Suriname. Processing of this data is currently underway. We have compiled an initial inventory of prospects on the license areas in Suriname and will continue to refine and assess the prospectivity, integrating this new 3D seismic data, during 2017 with a view to drilling as early as 2018.
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Sao Tome and Principe
During 2015 and 2016, Kosmos acquired acreage in Blocks 5, 6, 11 and 12 offshore Sao Tome and Principe in the Gulf of Guinea. We are the operator of Blocks 5, 11 and 12, and Galp, a wholly owned subsidiary of Petrogal, S.A., is the operator of Block 6. These blocks cover an area of approximately 5.8 million acres in water depth ranging from 7,380 to 9,840 feet and provide an opportunity to pursue the same core Cretaceous theme that was successful for us in Ghana.
Our blocks are adjacent to, and represent an extension of a proven and prolific petroleum system offshore Equatorial Guinea and northern Gabon comprising Early Cretaceous post-rift source rocks and Late Cretaceous reservoirs.
We believe that the southern extent of the West African transform margin in Sao Tome and Principe comprises a series of Albian pull-apart basins formed during the separation of Africa from South America and provides the necessary conditions for the generation, migration and entrapment of hydrocarbons. Early in the basin history, restricted marine conditions prevailed allowing rich source rocks to be deposited. Large sandstone depo-centers were developed at the structural junctions of rift and shear fault trends resulting in the deposition of deep-water slope channels and basin floor fans draping over and around anticlinal highs adjacent to fracture zones. These constitute the main play in the acreage.
We have approximately 1,250 line kilometers of 2D seismic covering portions of our blocks and have identified numerous leads in our Sao Tome and Principe acreage. We intend to further delineate this prospectivity with a 3D seismic acquisition program of approximately 16,000 square kilometers offshore Sao Tome and Principe, during 2017, which will facilitate a detailed geologic evaluation.
In December 2016, we received approval for a two-year extension of Phase 1 for Block 5 offshore Sao Tome and Principe, which now expires in May 2019. Additionally, during the same month we assigned 20% participating interest to Galp in each of Blocks 5, 11 and 12 offshore Sao Tome and Principe. Based on the terms of the agreement, Galp will pay a proportionate share of Kosmos’ past costs in the form of a partial carry on the 3D seismic survey expected to begin in the first quarter of 2017.
Morocco and Western Sahara
Our petroleum contracts in Morocco and Western Sahara include the Boujdour Maritime block, which is within the Aaiun Basin, and the Essaouira Offshore Block, which is within the Agadir Basin. We are the operator of these petroleum contracts.
Aaiun Basin
In May 2016, Kosmos and Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”) executed a petroleum contract with the Office National des Hydrocarbures et des Mines ("ONHYM"), the national oil company of the Kingdom of Morocco, for the Boujdour Maritime block. The Boujdour Maritime petroleum contract largely replaces the acreage covered by the Cap Boujdour petroleum contract which expired in March 2016. Government approval was received in July 2016, making the contract effective. The first phase requires 5,000 – 7,000 square kilometers of 3D seismic and expires in July 2020. 
The Boujdour Maritime block is located within the Aaiun Basin, along the Atlantic passive margin and covers a high‑graded area. Detailed seismic sequence analysis suggests the possible existence of stacked deepwater turbidite systems throughout the region. The scale of the license area has allowed us to identify distinct exploration fairways in this block. The main play elements of the prospectivity within the Boujdour Maritime block consist of a Late Jurassic source rock, charging Early to Mid‑Cretaceous deepwater sandstones trapped in a number of different structural trends. In the inboard area a number of three‑way fault closures are present which contain Early to Mid‑Cretaceous sandstone sequences some of which have been penetrated in wells on the continental shelf. Outboard of these fault trap trends, large four‑way closure and combination structural stratigraphic traps are present in discrete northeast to southwest trending structurally defined fairways.
During 2014, we conducted a new 3D seismic survey of approximately 5,100 square kilometers over the Cap Boujdour Offshore Block. The processing of this seismic data was completed in 2015.
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Drilling of the CB-1 exploration well on the Cap Boujdour Offshore Block was completed in March 2015. The well penetrated approximately 14 meters of net gas and condensate pay in clastic reservoirs over a gross hydrocarbon bearing interval of approximately 500 meters. The discovery was sub-commercial, and the well was plugged and abandoned. However, the well demonstrated a working petroleum system including the presence of a hydrocarbon charge. The results are being integrated with the ongoing geological evaluation to determine future exploration activity.
Kosmos expects to acquire approximately 9,500 square kilometers of 3D seismic in the Boujdour Maritime block, beginning in 2017.  The results of this survey will be integrated with prior surveys and well results to further develop and delineate prospectivity in the basin.
Agadir Basin
The Essaouira Offshore block is located in the Agadir Basin. A working petroleum system has been established in the onshore area of the Agadir Basin based on onshore and shallow offshore wells. Existing well data and geological and geochemical studies have demonstrated the presence of Cretaceous source rocks in the acreage. Onshore production suggests that possible Jurassic source rocks are also present in the offshore Agadir Basin.
In September 2016, we entered into an agreement by which BP agreed to pay Kosmos $30 million in lieu of fulfilling their obligation to fund an exploration well and assigned its 45% participating interest in the Essaouira Offshore Block back to us, and the Moroccan government issued joint ministerial orders approving the assignment in October 2016, making it effective.   During the same month, we received an extension of the first Extension Period of exploration for the Essaouira Offshore petroleum contract, which now expires in November 2018.  This extension included the modification of the minimum work program to replace an exploration well with acquisition and PSTM processing of 3,000 square-kilometers of 3D seismic and a seabed sampling survey for geochemical and heat flow analysis. The $30 million received from BP in January 2017 will be utilized to fund the modified work program.
The petroleum agreements for Tarhazoute Offshore and Foum Assaka Offshore expired in June 2016 and July 2016, respectively.
 
Portugal
In January 2017, we provided to our co-venturers a notice of withdrawal from the Ameijoa, Camarao, Mexilhao and Ostra Blocks offshore Portugal.
Our Reserves
The following table sets forth summary information about our estimated proved reserves as of December 31, 2016. See “Item 8. Financial Statements and Supplementary Data—Supplemental Oil and Gas Data (Unaudited)” for additional information.
All of our estimated proved reserves as of December 31, 2016, 2015 and 2014 were associated with our Jubilee and the TEN fields in Ghana.
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Summary of Oil and Gas Reserves
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2016 Net Proved Reserves(1)	 	2015 Net Proved Reserves(1)	 	2014 Net Proved Reserves(1)	 	
 	 	Oil,	 	 	 	 	 	Oil,	 	 	 	 	 	Oil,	 	 	 	 	 	
 	 	Condensate,	 	Natural	 	 	 	Condensate,	 	Natural	 	 	 	Condensate,	 	Natural	 	 	 	
 	 	NGLs	 	Gas(2)	 	Total	 	NGLs	 	Gas(2)	 	Total	 	NGLs	 	Gas(2)	 	Total	 	
 	 	(MMBbl)	 	(Bcf)	 	(MMBoe)	 	(MMBbl)	 	(Bcf)	 	(MMBoe)	 	(MMBbl)	 	(Bcf)	 	(MMBoe)	 	
Reserves Category	    	 	    	 	    	 	    	 	    	 	    	 	    	 	    	 	    	 	 	
Proved developed	 	64	 	13	 	66	 	50	 	10	 	52	 	43	 	9	 	45	 	
Proved undeveloped(3)	 	10	 	2	 	11	 	24	 	4	 	25	 	30	 	6	 	31	 	
Total	 	74	 	15	 	77	 	74	 	14	 	76	 	73	 	14	 	75	 	

 	(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.	

 	(2)	 	These reserves represent only the estimated quantities of fuel gas required to operate the Jubilee and TEN FPSOs during normal field operations. No natural gas volumes, outside of the fuel gas reported, have been classified as reserves. If and when a subsequent gas sales agreement is executed for Jubilee, a portion of the remaining gas may be recognized as reserves. If and when a gas sales agreement and the related infrastructure are in place for the TEN fields, a portion of the remaining gas may be recognized as reserves.	

 	(3)	 	All of our proved undeveloped reserves are expected to be developed within five years or less. As of December 31, 2016, we recognized 10.7 MMBoe of proved undeveloped reserves related to the TEN fields, which began first oil production in the third quarter of 2016.	
Changes for the year ended December 31, 2016, include an increase of 8.3 MMBbl in TEN related to a revision resulting from additional technical data and analysis, partially offset by 0.9 MMBbl of net TEN production during 2016, and negative revisions to Jubilee of 1.0 MMBbl due to lower oil prices and 6.2 MMBbl of net Jubilee production during 2016. During the year ended December 31, 2016, we had 14 MMBoe of our proved undeveloped reserves from December 31, 2015 convert to proved developed reserves due to the completion of seven wells in the TEN fields, the initiation of TEN production and 2016 revisions, and we incurred $198.5 million of capital expenditures for TEN.
Changes for the year ended December 31, 2015, include an increase of 11.8 MMBbl of net proved reserves related to Jubilee field performance and in‑fill drilling results, which were partially offset by negative revisions to the TEN fields of 2.1 MMBbl due to lower oil prices and by 8.6 MMBbl of net Jubilee production during 2015. During the year ended December 31, 2015, we had a 6 MMBoe reduction in our proved undeveloped reserves from December 31, 2014. The decrease was a result of an approximately 2 MMBoe negative revision associated with our TEN fields, due to shorter economic life as a result of lower oil price. We incurred $80.6 million of capital expenditures related the drilling and completion of two wells pursuant to the Jubilee Field Phase 1A and 1A addendum developments resulting in the conversion of approximately 3 MMBoe of proved undeveloped reserves to proved developed reserves associated with our Jubilee Field.
Changes for the year ended December 31, 2014, include an increase of 27 MMBbl of net proved reserves related to the initial recognition of reserves associated with the TEN fields. Jubilee net proved oil reserves increased 11 MMBbl as a result of field performance and in‑fill drilling results, which was partially offset by 8.5 MMBbl of net Jubilee production during 2014. During the year ended December 31, 2014, we had a 22 MMBoe increase in our proved undeveloped reserves from December 31, 2013. This increase was primarily the result of the initial recognition of 27 MMBoe in proved undeveloped reserves for the TEN fields offset by the conversion of approximately 6 MMBoe from proved undeveloped reserves to proved developed reserves as we incurred $82.8 million of capital expenditures related to the drilling of the remaining Jubilee Field Phase 1A development wells.
The following table sets forth the estimated future net revenues, excluding derivatives contracts, from net proved reserves and the expected benchmark prices used in projecting net revenues at December 31, 2016. All estimated future net revenues are attributable to projected production from the Jubilee and the TEN fields in Ghana. If we are unable to export associated natural gas in large quantities from the Jubilee and TEN fields then production could be limited and the future net revenues discussed herein will be adversely affected.
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 	 	 	Estimated Future	 	
 	    	 	Net Revenues(4)	 	
 	 	 	(in millions	 	
 	 	 	except $/Bbl)	 	
Estimated future net revenues	 	$	1,111	 	
Present value of estimated future net revenues:	    	 	 	 	
PV-10(1)	 	$	846	 	
Future income tax expense (levied at a corporate parent and intermediate subsidiary level)	 	 	—	 	
Discount of future income tax expense (levied at a corporate parent and intermediate subsidiary level) at 10% per annum	 	 	—	 	
Standardized Measure(2)	 	$	846	 	
 	 	 	 	 	
Benchmark and differential oil price($/Bbl)(3)	 	$	42.96	 	

 	(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 (in our case, future Ghanaian tax expense), using prices based on an average of the first‑day‑of‑the‑months throughout 2016 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 (in our case, the effects of future Ghanaian tax expense). 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 (in our case, future Ghanaian tax expense), 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. However, as we are a tax exempted company incorporated pursuant to the laws of Bermuda, we do not expect to be subject to future income tax expense related to our proved oil and gas reserves levied at a corporate parent level on future net revenues. Therefore, the year‑end 2016 estimate of PV‑10 is equivalent to the Standardized Measure.	

 	(3)	 	The unweighted arithmetic average first‑day‑of‑the‑month prices for the prior 12 months was $42.90 for Dated Brent at December 31, 2016. The price was adjusted for crude handling, transportation fees, quality, and a regional price differential. These adjustments are estimated to include a $0.06 premium relative to Dated Brent for the Jubilee Field. The adjusted price utilized to derive the Jubilee Field PV‑10 is $42.96. As the TEN fields recently started production, we do not have sufficient historical information to estimate the differential. However, we expect the differential to be consistent with the Jubilee Field. Since the Jubilee Field is currently at a premium, we elected to use a $0.00 differential to be conservative for the TEN fields, therefore the price utilized to derive the TEN PV‑10 is $42.90.	

 	(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, 2016, 2015 and 2014 has been prepared by Ryder Scott Company, L.P. (“RSC”), our independent reserve engineering firm for such years, in accordance with the rules and regulations of the Securities and
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Exchange Commission (“SEC”) applicable to companies involved in oil and natural gas producing activities. These rules require SEC reporting companies to prepare their reserve estimates using reserve definitions and pricing based on 12‑month historical unweighted first‑day‑of‑the‑month average prices, rather than year‑end prices. For a definition of proved reserves under the SEC rules, see the “Glossary and Selected Abbreviations.” For more information regarding our independent reserve engineers, please see “—Independent petroleum engineers” below.
Our estimated proved reserves and related future net revenues, PV‑10 and Standardized Measure were determined using index prices for oil, without giving effect to derivative transactions, and were held constant throughout the life of the assets.
Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations at December 31, 2016 are based on costs in effect at December 31, 2016 and the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the year ended December 31, 2016, adjusted for anticipated market premium, without giving effect to derivative transactions, and are held constant throughout the life of the assets. There can be no assurance that the proved reserves will be produced within the periods indicated or prices and costs will remain constant.
Independent petroleum engineers
Ryder Scott Company, L.P.
RSC, our independent reserve engineers for the years ended December 31, 2016, 2015 and 2014, was established in 1937. For over 75 years, RSC has provided services to the worldwide petroleum industry that include the issuance of reserves reports and audits, appraisal of oil and gas properties including fair market value determination, reservoir simulation studies, enhanced recovery services, expert witness testimony, and management advisory services. RSC professionals subscribe to a code of professional conduct and RSC is a Registered Engineering Firm in the State of Texas.
For the years ended December 31, 2016, 2015 and 2014, we engaged RSC to prepare independent estimates of the extent and value of the proved reserves of certain of our oil and gas properties. These reports were prepared at our request to estimate our reserves and related future net revenues and PV‑10 for the periods indicated therein. Our estimated reserves at December 31, 2016, 2015 and 2014 and related future net revenues and PV‑10 at December 31, 2016, 2015 and 2014 are taken from reports prepared by RSC, in accordance with petroleum engineering and evaluation principles which RSC believes are commonly used in the industry and definitions and current regulations established by the SEC. The December 31, 2016 reserve report was completed on January 13, 2017, and a copy is included as an exhibit to this report.
In connection with the preparation of the December 31, 2016, 2015 and 2014 reserves report, RSC prepared its own estimates of our proved reserves. In the process of the reserves evaluation, RSC did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of RSC which brought into question the validity or sufficiency of any such information or data, RSC did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. RSC independently prepared reserves estimates to conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4‑10(a)(2) of Regulation S‑X. RSC issued a report on our proved reserves at December 31, 2016, based upon its evaluation. RSC’s primary economic assumptions in estimates included an ability to sell Jubilee field oil and the TEN fields oil at a price of $42.96 and $42.90, respectively, and certain levels of future capital expenditures. The assumptions, data, methods and precedents were appropriate for the purpose served by these reports, and RSC used all methods and procedures as it considered necessary under the circumstances to prepare the report.
Technology used to establish proved reserves
Under the SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term
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“reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have proved effective by actual comparison of production from projects in the same reservoir interval, an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our estimated proved reserves, RSC employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, production and injection data, electrical logs, radioactivity logs, acoustic logs, whole core analysis, sidewall core analysis, downhole pressure and temperature measurements, reservoir fluid samples, geochemical information, geologic maps, seismic data, well test and interference pressure and rate data. Reserves attributable to undeveloped locations were estimated using performance from analogous wells with similar geologic depositional environments, rock quality, appraisal plans and development plans to assess the estimated ultimate recoverable reserves as a function of the original oil in place. These qualitative measures are benchmarked and validated against sound petroleum reservoir engineering principles and equations to estimate the ultimate recoverable reserves volume. These techniques include, but are not limited to, nodal analysis, material balance, and numerical flow simulation.
Internal controls over reserves estimation process
In our Production and Development team, we maintain an internal staff of petroleum engineering and geoscience professionals with significant international experience that contribute to our internal reserve and resource estimates. This team works closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of data furnished in their reserve and resource estimation process. Our Production and Development team is responsible for overseeing the preparation of our reserves estimates and has over 100 combined years of industry experience among them with positions of increasing responsibility in engineering and evaluations. Each member of our team holds a minimum of Bachelor of Science degree in petroleum engineering or geology.
The RSC technical person primarily responsible for preparing the estimates set forth in the RSC reserves report incorporated herein is Mr. Guadalupe Ramirez. Mr. Ramirez has been practicing consulting petroleum engineering at RSC since 1981. Mr. Ramirez is a Licensed Professional Engineer in the State of Texas (No. 48318) and has over 35 years of practical experience in petroleum engineering. He graduated from Texas A&M University in 1976 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Ramirez meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
The Audit Committee provides oversight on the processes utilized in the development of our internal reserve and resource estimates on an annual basis. In addition, our Production and Development team meets with representatives of our independent reserve engineers to review our assets and discuss methods and assumptions used in preparation of the reserve and resource estimates. Finally, our senior management review reserve and resource estimates on an annual basis.
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Gross and Net Undeveloped and Developed Acreage
The following table sets forth certain information regarding the developed and undeveloped portions of our license areas as of December 31, 2016 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	    	 	    	 	    	 	    	 	    	 	    	 	 	
Jubilee Unit	 	27	 	7	 	 —	 	 —	 	27	 	7	 	
TEN	 	111	 	19	 	 —	 	 —	 	111	 	19	 	
West Cape Three Points(2)	 	 —	 	 —	 	101	 	31	 	101	 	31	 	
Deepwater Tano(2)	 	 —	 	 —	 	27	 	4	 	27	 	4	 	
Mauritania	 	 	 	 	 	 	 	 	 	 	 	 	 	
Block C6(3)	 	 —	 	 —	 	1,063	 	957	 	1,063	 	957	 	
Block C8(3)	 	 —	 	 —	 	2,220	 	1,998	 	2,220	 	1,998	 	
Block C12(3)	 	 —	 	 —	 	1,273	 	1,146	 	1,273	 	1,146	 	
Block C13(3)	 	 —	 	 —	 	1,452	 	1,307	 	1,452	 	1,307	 	
Morocco (including Western Sahara)	 	 	 	 	 	 	 	 	 	 	 	 	 	
Boujdour Maritime	 	 —	 	 —	 	8,336	 	4,585	 	8,336	 	4,585	 	
Essaouira	 	 —	 	 —	 	2,171	 	1,628	 	2,171	 	1,628	 	
Sao Tome and Principe	 	 	 	 	 	 	 	 	 	 	 	 	 	
Block 5	 	 —	 	 —	 	703	 	316	 	703	 	316	 	
Block 6	 	 —	 	 —	 	1,241	 	559	 	1,241	 	559	 	
Block 11	 	 —	 	 —	 	2,209	 	1,436	 	2,209	 	1,436	 	
Block 12	 	 —	 	 —	 	1,738	 	782	 	1,738	 	782	 	
Senegal	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cayar Offshore Profond(4)	 	 —	 	 —	 	1,350	 	810	 	1,350	 	810	 	
Saint Louis Offshore Profond(4)	 	 —	 	 —	 	1,650	 	990	 	1,650	 	990	 	
Suriname	 	 	 	 	 	 	 	 	 	 	 	 	 	
Block 42	 	 —	 	 —	 	1,526	 	509	 	1,526	 	509	 	
Block 45	 	 —	 	 —	 	1,267	 	633	 	1,267	 	633	 	
Total	 	138	 	26	 	28,327	 	17,691	 	28,465	 	17,717	 	

 	(1)	 	Net acreage based on Kosmos’ participating interest, before the exercise of any options or back‑in rights, except for our net acreage associated with the Jubilee field, the TEN fields and Mahogany and Teak discoveries in the WCTP Block, 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 2017, we closed a farm-out agreement covering our four license areas in Mauritania with BP. The net acres shown do not reflect the farm-out, as the agreement was not closed as of December 31, 2016. After completing the farm-out agreement, our estimated net acres in Block C6, Block C8, Block C12 and Block C13 are 298 thousand acres, 622 thousand acres, 356 thousand acres and 407 thousand acres, respectively.	

 	(4)	 	In February 2017, we completed a Sale and Purchase Agreement with BP which resulted in BP acquiring a 49.99% interest in Kosmos BP Senegal Limited, which is a controlled affiliate of Kosmos in which we own a 50.01% interest . Kosmos BP Senegal Limited owns a 65% participating interest in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks. This participating interest gives effect to the completion of our exercise in December 2016 of an option to increase our equity in each contract area from 60% to 65% in exchange for carrying Timis Corporation’s paying interest share of a third well in either contract area, subject to a maximum gross cost of $120.0 million. The net acres shown do not reflect these transactions, as the agreement was not closed as of December 31, 2016. After	
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completion of these transactions, our estimated net acres in Cayar Offshore Profond and Saint Louis Offshore Profond are 536 thousand acres and 439 thousand acres, respectively.	
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, 2016:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Productive	 	Productive	 	 	 	 	 	
 	 	Oil Wells	 	Gas Wells	 	Total	 	
 	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	
Ghana—Jubilee Unit	    	26	    	6.24	    	—	    	—	    	26	    	6.24	 	
Ghana—Ten(1)	    	11	    	1.87	    	—	    	—	    	11	    	1.87	 	

 	(1)	 	Of the 11 productive wells, 10 (gross) or 1.70 (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,  2016	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Jubilee Unit	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	
TEN	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	7	 	1.19	 	 —	 	 —	 	7	 	1.19	 	7	 	1.19	 	
Total	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	7	 	1.19	 	 —	 	 —	 	7	 	1.19	 	7	 	1.19	 	
Year Ended December 31,  2015	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	   	 	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Jubilee Unit	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	3	 	0.72	 	 —	 	 —	 	3	 	0.72	 	3	 	0.72	 	
TEN	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	4	 	0.68	 	 —	 	 —	 	4	 	0.68	 	4	 	0.68	 	
Morocco (including Western Sahara)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cap Boujdour	 	 —	 	 —	 	1	 	0.55	 	1	 	0.55	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	1	 	0.55	 	
Total	 	 —	 	 —	 	1	 	0.55	 	1	 	0.55	 	7	 	1.40	 	 —	 	 —	 	7	 	1.40	 	8	 	1.95	 	
Year Ended December 31,  2014	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Jubilee Unit	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	
TEN	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	
Morocco (including Western Sahara)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Foum Assaka	 	 —	 	 —	 	1	 	0.30	 	1	 	0.30	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	1	 	0.30	 	
Total	 	 —	 	 —	 	1	 	0.30	 	1	 	0.30	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	1	 	0.30	 	

 	(1)	 	As of December 31, 2016, 15 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 7 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.	
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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, 2016.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	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	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	2	 	0.48	 	
West Cape Three Points	 	 —	 	 —	 	 —	 	 —	 	9	 	2.78	 	 —	 	 —	 	
TEN	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	5	 	0.85	 	
Deepwater Tano	 	 —	 	 —	 	 —	 	 —	 	1	 	0.18	 	 —	 	 —	 	
Mauritania	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
C8(1)	 	 —	 	 —	 	 —	 	 —	 	3	 	2.70	 	 —	 	 —	 	
Senegal	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Saint Louis Offshore Profond(2)	 	 —	 	 —	 	 —	 	 —	 	1	 	0.60	 	 —	 	 —	 	
Cayar Profond(2)	 	 —	 	 —	 	 —	 	 —	 	1	 	0.60	 	 —	 	 —	 	
Total	 	 —	 	 —	 	 —	 	 —	 	15	 	6.86	 	7	 	1.33	 	

 	(1)	 	In January 2017, we closed a farm-out agreement covering our four license areas in Mauritania with BP. The net wells shown do not reflect the farm-out, as the agreement was not closed as of December 31, 2016. After completing the farm-out agreement, our estimated net wells in Block C8 are 0.84.	

 	(2)	 	In February 2017, we completed a Sale and Purchase Agreement with BP which resulted in BP acquiring a 49.99% interest in Kosmos BP Senegal Limited, which is a controlled affiliate of Kosmos in which we own a 50.01% interest. Kosmos BP Senegal Limited owns a 65% participating interest in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks. This participating interest gives effect to the completion of our exercise in December 2016 of an option to increase our equity in each contract area from 60% to 65% in exchange for carrying Timis Corporation’s paying interest share of a third well in either contract area, subject to a maximum gross cost of $120.0 million. After completion of these transactions, our estimated net wells in Cayar Offshore Profond and Saint Louis Offshore Profond are 0.33 and 0.33, respectively.	
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, 2016, 48 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.
West Cape Three Points Block
Effective July 22, 2004, Kosmos, the E.O. Group Ltd. and GNPC entered into the WCTP petroleum contract covering the WCTP Block offshore Ghana in the Tano Basin. As a result of farm‑out agreements and other sales of partners’ interests for the WCTP Block, Kosmos, Anadarko WCTP Company (“Anadarko”), Tullow Ghana Limited, a subsidiary of Tullow Oil plc (“Tullow”) and PetroSA Ghana Limited (“PetroSA”), a wholly owned subsidiary of Petro S.A., participating interests are 30.9%, 30.9%, 26.4% and 1.8%, respectively. Kosmos is the operator; however, a letter agreement has been executed that obligates the WCTP partners to take the necessary steps to transfer operatorship of the WCTP Block to Tullow after approval of the GJFFDP by the Ministry of Energy. Upon approval of the GJFFDP, our participating interest in Mahogany and Teak will be at the Jubilee Unit interests. GNPC has a 10% participating interest and will be carried through the exploration and development phases. GNPC has the option to acquire additional paying interests in a commercial discovery on the WCTP Block of 2.5%. Under the WCTP petroleum contract, GNPC exercised
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its option to acquire an additional paying interest of 2.5% in the Jubilee Field development (see “—Jubilee Field Unitization”), the Mahogany discovery and the Teak discovery. GNPC is obligated to pay its 2.5% share of all future petroleum costs as well as certain historical development and production costs attributable to its 2.5% additional paying interests in the Jubilee Unit, Mahogany discovery and Teak discovery. Furthermore, it is obligated to pay 10% of the production costs of the Jubilee Field development allocated to the WCTP Block. In August 2009, GNPC notified us and our unit partners of GNPC’s request for the contractor group to pay its 2.5% WCTP Block share of the Jubilee Field development costs and be reimbursed for such costs plus interest out of GNPC’s production revenues under the terms of the WCTP petroleum contract. Kosmos is required to pay a fixed royalty of 5% and a sliding‑scale royalty (“additional oil entitlement”) which escalates as the nominal project rate of return increases. 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 our three existing discoveries within the WCTP Block (Akasa, Mahogany and Teak) 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.
Deepwater Tano Block
Effective July 2006, Kosmos, Tullow and PetroSA’s predecessor, Sabre Oil and Gas Holdings Ltd., entered into the DT petroleum contract with GNPC covering the DT Block offshore Ghana in the Tano Basin. The DT petroleum contract has a duration of 30 years from its effective date of July 19, 2006. As a result of farm‑out agreements and other sales of partners interests for the DT Block, Kosmos, Anadarko, Tullow and PetroSA’s participating interests are 18%, 18%, 50% and 4%, respectively. Tullow is the operator. GNPC has a 10% participating interest and will be carried through the exploration and development phases. GNPC has the option to acquire additional paying interests in a commercial discovery on the DT Block of 5%. 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. GNPC is obligated to pay its 5% of all future petroleum costs, including development and production costs attributable to its 5% additional paying interest. Furthermore, it is obligated to pay 10% of the production costs of the Jubilee Field development allocated to the DT Block. In August 2009, GNPC notified us and our unit partners of GNPC’s request for the contractor group to pay its 5% DT Block share of the Jubilee Field development costs and be reimbursed for such costs plus interest out of a portion of GNPC’s production revenues under the terms of the DT petroleum contract. Kosmos is required to pay a fixed royalty of 5% and an additional oil entitlement which escalates as the nominal project rate of return increases. 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.
In January 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.
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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 UUOA, agreed to in 2009 which govern 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 UUOA. As a result of the initial redetermination process completed in October 2011, the tract participation was determined to be 54.4% for the WCTP Block and 45.6% for the DT Block. Our Unit Interest was increased from 23.5% to 24.1%. The accounting for the Jubilee Unit is in accordance with the redetermined tract participation stated. Although the Jubilee Field is unitized, Kosmos’ participating interests in each block outside the boundary of the Jubilee Unit remain the same. Kosmos remains operator of the WCTP Block outside the Jubilee Unit area.
Morocco (including Western Sahara) Exploration Agreements
In May 2016, Kosmos and Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”) executed a petroleum agreement with the Office National des Hydrocarbures et des Mines ("ONHYM"), the national oil company of the Kingdom of Morocco, for the Boujdour Maritime block. The Boujdour Maritime petroleum agreement largely replaces the acreage covered by the Cap Boujdour petroleum agreement which expired in March 2016. Under the terms of the petroleum agreement, Kosmos is the operator of the Boujdour Maritime block and has a 55% participating interest, Cairn has a 20% participating interest, and ONHYM holds a 25% carried interest in the block through the exploration period. The Boujdour Maritime block is currently in the initial exploration period, which is for four years from its effective date (July 18, 2016) ending in July 2020. The initial exploration period carries a 3D seismic obligation of 5,000 square kilometers. The exploration phase may be extended twice for two years each, for a total duration of eight years at our election and subject to our fulfilling specific work obligations, which includes drilling an exploration well in each of the subsequent periods. In the event of commercial success, the Company has the right to develop and produce oil and/or gas for a period of 25 years from the grant of an exploitation concession from the Government of Morocco, which may be extended for an additional period of 10 years under certain circumstances.
Effective April 2, 2012, we entered into the Essaouria Offshore Petroleum Agreement as operator. During 2016, our partner BP, relinquished their participating interest in the petroleum contract. Our participating interest is 75%. The Moroccan national oil company, ONHYM, has a 25% participating interest and is carried by the block partners proportionately during the exploration phase. We are required to pay a 10% royalty on oil produced in water depths of 200 meters or less (the first 300,000 tons produced are exempt from royalty) and 7% royalty on oil produced in water depths deeper than 200 meters (the first 500,000 tons produced are exempt from royalty). These royalties are to be paid in‑kind or, at the election of the government of Morocco, in cash. A corporate tax rate of 30% is applied to profits at the license level following a 10‑year tax holiday post first production. The term of the Essaouria Offshore Permits, beginning November 8, 2011, is eight years and includes an initial exploration period of two years and six months followed by the first extension period of four years and six months and the second extension period of one year. We are currently in the first extension period of the exploration permit, which as a result of an amendment in October 2016, ends in November 2018. As a result of the same amendment, approved in October 2016, the work program for the first extension period now includes acquisition, pre-stack time migration processing and interpretation of a minimum of 3,000 square kilometers of 3D seismic data and a seabed sampling survey for geochemical and heat flow analysis over the block, replacing our prior exploration well obligation. The extension of the 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 25 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.
Suriname Exploration Agreements
On December 13, 2011, we signed a petroleum contract covering Offshore Block 42 located offshore Suriname. As a result of farm-out agreements we have a one-third participating interest in the block 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. In November 2012, Kosmos closed an agreement with Chevron under which Kosmos assigned half of its interest in Block 42, offshore Suriname, to Chevron. Each party
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had a 50% participating interest in Block 42 and Kosmos remained the operator. In April 2016, we entered into a farm-out agreement with Hess Suriname Exploration Limited, a wholly-owned subsidiary of the Hess Corporation (“Hess”), covering the Block 42 contract area offshore Suriname. Under the terms of the agreement, Hess acquired a one-third non-operated interest in Block 42 from both Chevron and Kosmos. As part of the agreement, Hess will fully fund the cost of acquiring and processing a 6,500 square kilometer 3D seismic survey, subject to a maximum spend, which commenced in the October 2016. Additionally, Hess will disproportionately fund a portion of the first exploration well in the Block 42 contract area, subject to a maximum spend, contingent upon the partnership entering the next phase of the exploration period. The participating interests are one-third to each of Kosmos, Chevron and Hess, respectively. Kosmos will remain the operator. 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 initial period of the exploration phase, which has been extended and ends in September 2018. There are two renewal periods consisting of three years for the first renewal period and two years for the second renewal period. Each renewal period 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. Block 42 comprises approximately 1.5 million acres (approximately 6,176 square kilometers).
On December 13, 2011, we signed a petroleum contract covering Offshore Block 45 located offshore Suriname. We have a 50% participating interest in the block 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. In November 2012, Kosmos closed an agreement with Chevron under which Kosmos assigned half of its interest in Block 45, offshore Suriname, to Chevron. Each party now has a 50% participating interest in Block 45 and Kosmos remains the operator. 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 initial period of the exploration phase, which has been extended and ends in September 2018. Following the initial period, there are two renewal periods consisting of two years each. Each renewal period 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.
Mauritania Exploration Agreements
Effective June 15, 2012, we entered into three petroleum contracts covering offshore Mauritania blocks C8, C12 and C13 with the Islamic Republic of Mauritania. As a result of farm-out agreements 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 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 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. The first extension period carries a seismic obligation and a one well drilling obligation and the second extension period for each block carries an additional one well drilling obligation for each block. Both of these obligations have been met for Block C8 and the seismic obligation has been met for Block C12 with work completed during the initial exploration period. Seismic acquisition to meet the obligation for the current phase for Block C13 was completed in December 2016 as part of an ongoing multi-block 3D seismic survey. 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.
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In March 2015, we closed a farm‑out agreement with Chevron covering the C8, C12 and C13 petroleum contracts offshore Mauritania. Under the terms of the farm‑out agreement, Chevron acquired a 30% non‑operated participating interest in each of the contract areas. As partial consideration for the farm-out, Chevron paid a disproportionate share of the costs of one exploration well, the Marsouin-1 exploration well, as well as its proportionate share of certain previously incurred exploration costs. As a further component of the consideration for the farm-out, Chevron was required to make an election by February 1, 2016, to either farm-in to the Tortue-1 exploration well by paying a disproportionate share of the costs incurred in drilling of the well or, alternatively elect to not farm-in to the Tortue-1 exploration well and pay a disproportionate share of the costs of a second contingent exploration or appraisal well in the contract areas, subject to maximum expenditure caps. Chevron failed to make this mandatory election by the required date. Consequently, pursuant to the terms of the farm-out agreement, Chevron has withdrawn from our Mauritania blocks. Chevron’s 30% non-operated participating interest was reassigned to us.
In October 2016, we entered into a petroleum contract covering Block C6 with the Islamic Republic of Mauritania.  As a result of farm-out agreements with BP 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. 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 18%. 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 four years from the effective date (October 28, 2016) followed by the first extension period of three years and the second extension period of three years. The first exploration phase includes a 2,000 square kilometer 3D seismic requirement, which is currently being acquired.
 
In January 2017, we closed a farm-out agreement with BP covering blocks C6, C8, C12 and C13 offshore Mauritania.
 
Senegal Exploration Agreements
In August 2014, we entered into a farm‑in agreement with Timis Corporation Limited (“Timis”), whereby we acquired a 60% participating interest and operatorship, covering the Cayar Offshore Profond and Saint Louis Offshore Profond Contract Areas offshore Senegal. In September 2014, the Senegal government issued the requisite approvals for the assignment to us. As part of the agreement, we carried the full costs of a 3D seismic program which was completed in January 2015. Additionally, we carried the full costs of the Guembeul-1 exploration well in the Saint Louis Offshore Profond area and the full costs of the Teranga-1 well in the Cayar Offshore Profond area, subject to a maximum gross cost per well of $120.0 million.
In June 2015, we entered the first renewal of the exploration period for the Cayar Offshore Profond and Saint Louis Offshore Profond Contract Areas, which lasts for three years. The exploration phase of each contract area may be extended to December 2020 at our election subject to our fulfilling specific work obligations including an exploration well in the final period of two and one half years. 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.
In February 2016, we completed a 3D seismic survey of approximately 4,500 square kilometers in the western portions of the Cayar Offshore Profond and Saint Louis Offshore Profond license areas.
 
In February 2017, we completed a Sale and Purchase Agreement with BP which resulted in BP acquiring a 49.99% interest in Kosmos BP Senegal Limited, which is a controlled affiliate of Kosmos in which we own a 50.01% interest. Kosmos BP Senegal Limited owns a 65% participating interest in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks. This participating interest gives effect to the completion of our exercise in December 2016 of an option to increase our equity in each contract area from 60% to 65% in exchange for carrying Timis Corporation’s paying interest share of a third well in either contract area, subject to a maximum gross cost of $120.0 million.
 
Sao Tome and Principe Exploration Agreements
In October 2015, we closed a sale and purchase agreement with ERHC Energy EEZ, LDA. As a result of subsequent farm-outs, we currently have a 65% participating interest and operatorship in Block 11 offshore Sao Tome and Principe. The Agencia Nacional Do Petroleo De Sao Tome E Príncipe ("ANP STP") has a carried 15% participating
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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 2018. The work program for the first phase includes a 2D seismic acquisition obligation and 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 from ANP STP, which may be extended for additional periods of five years until all hydrocarbons have been economically depleted.
In November 2015, we closed a farm-in agreement with Galp to acquire a non-operated 45% participating interest in Block 6 offshore Sao Tome and Principe. The 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 work program for the first phase includes a 2D or 3D seismic acquisition obligation and 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 from ANP STP, which may be extended for additional periods of five years until all hydrocarbons have been economically depleted.
In January and February 2016, we closed farm-in agreements with Equator Exploration Limited (“Equator”), an affiliate of Oando Energy Resources, for Block 5 and Block 12 offshore Sao Tome and Principe. As a result of subsequent farm-outs we currently have a 45% participating interest and operatorship in each block. The national petroleum agency, ANP STP, has a 15% and 12.5% carried interest in Block 5 and Block 12, respectively. The production sharing contracts were awarded in May 2012 and February 2016, respectively, and they 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 of 2019 and February 2020, respectively (the first phase of Block 5 has been extended twice for a total of 3 years).  The work program for the first phases include 2D or 3D seismic acquisition obligations and 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 from ANP STP, which may be extended for additional periods of five years until all hydrocarbons have been economically depleted.
 
In September 2016, Kosmos reached an agreement with a subsidiary of Galp to farm-out a 20% non-operated stake of the Company’s interest in Blocks 5, 11, and 12 offshore Sao Tome and Principe. Based on the terms of the agreement, Galp will pay a proportionate share of Kosmos’ past costs in the form of a partial carry on the 3D seismic survey expected to begin in the first quarter of 2017. Government approval was received and the transaction closed in December 2016. 
 
Sales and Marketing
As provided under the UUOA and the WCTP and DT petroleum contracts, we are entitled to lift and sell our share of the Jubilee and TEN production in conjunction with the 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.
There are a variety of factors which affect the market for oil, including the proximity and capacity of transportation facilities, demand for oil, 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. Many of these competitors have financial and technical resources and staff that are substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and natural
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gas assets, or to evaluate, bid for and purchase a greater number of licenses 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 experienced an extended decline in crude oil prices. Dated Brent crude, the benchmark for our oil sales, ranged from approximately $26-55 per barrel during 2016. Excluding the impact of hedges, our realized price for 2016 was $45.94 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 at this point.
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 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.
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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 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.
Capping and Containment
We entered into an agreement with a third party service provider for it to supply subsea capping and containment equipment on a global basis. 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.
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. The dispersant stockpile, which is managed by Oil Spill Response Limited (“OSRL”) of Southampton, United Kingdom (“UK”), 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.
Mauritania and Senegal (Operated)
Kosmos maintains Oil Spill Contingency Plans (“OSCP”) to support our drilling operations in countries where we operate. The plans are based on the principle of “Tiered Response” to oil spills (“Guide to Tiered Response and Preparedness”, IPIECA Report Series, Volume 14, 2007).  A Tier 1 spill is defined as a small-scale operational incident which can be addressed with resources that are immediately available to us.  A Tier 2 spill is a larger incident which would need to be addressed with regionally based shared resources.  A Tier 3 spill is a large incident which would require assistance from national or world-wide spill co-operatives.  Under OSCPs, emergency response teams may be activated to respond to oil spill incidents.  The OSCPs call for Tier 1 spill equipment at our shorebases in Nouakchott, Mauritania and Dakar, Senegal to respond to a harbor or shoreline incident in the area. We also maintain dispersant spraying capabilities in the field to respond to an offshore incident. We have access to additional Tier 2 and Tier 3 equipment from OSRL’s Southampton, UK location.
Ghana (Non-operated)
Tullow, our partner and the operator of the Jubilee Unit and the TEN fields, maintains an 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. Tier 1 equipment, which is stored in “ready to go trailers” for effective mobilization and deployment, includes booms and ancillaries, recovery systems, pumps and delivery systems, oil storage containers, personal protection equipment, sorbent materials, hand tools, containers and first aid equipment. Tier 2 equipment consists of larger boom and oil recovery systems, pump and delivery systems and auxiliary equipment such as generators and lighting sets, and is also containerized and pre‑packed in trailers and ready for mobilization.
Tullow has additional response capability to handle an offshore Tier 1 response. Further, our membership in the West and Central Africa Aerial Surveillance and Dispersant Spraying Service (“WACAF”) gives us access to aircraft for surveillance and spraying of dispersant, which is administered by OSRL for a Tier 2 offshore response. The aircraft is based at the Kotoka International Airport in Accra, Ghana with a contractual response time, loaded with dispersant, of six hours. Additional stockpiles of dispersant are maintained in Takoradi, Ghana. Although the above arrangement is in place, we can make no assurance that these resources will be available or respond in a timely manner as intended, perform as designed or be able to fully contain or cap any oil spill, blow‑out or uncontrolled flow of hydrocarbons. While a Tier 3 incident is not expected in Ghana, in the case of a Tier 3 incident, Tullow would engage the services of OSRL.
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Per common industry practice, under agreements governing the terms of use of the drilling rigs contracted by us or our block partners, the drilling rig contractors 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 blocks in which we or our block partners are currently drilling, except in certain circumstances, each block 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 Jubilee FPSO. 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.
Other Regulation of the Oil and Gas Industry
Ghana
In 2016, the Government of Ghana passed into law Petroleum (Exploration and Production) Bill, 2016 (the “2016 Ghanaian Petroleum Law”). While the 2016 Ghanaian Petroleum Law now governs the upstream Ghanaian oil and natural gas regulatory regime and sets out the policy and framework for other industry participants beginning in 2016, due to the stabilization clauses contained in the DWT petroleum contract and the WCTP petroleum contract, the 1984 Ghanaian Petroleum Law governs our oil and natural gas operations in Ghana. All petroleum found in its natural state within Ghana is deemed to be national property and is to be developed on behalf of the people of Ghana. GNPC is empowered to carry out exploration and development work either on its own or in association with local or foreign contractors. Companies who wish to gain rights to explore and produce in Ghana can only do so by entering into a petroleum agreement with Ghana and GNPC. The law requires for the terms of the petroleum agreement to be negotiated and agreed between GNPC and oil and gas companies. The Parliament of Ghana has final approval rights over the negotiated petroleum agreement. Ghana’s Ministry of Energy represents the state in its executive capacity. The Petroleum Commission is the regulatory body for the upstream petroleum industry and the advisor to the Ministry of Energy. GNPC has rights to undertake petroleum operations in any acreage declared open by Ghana’s Ministry of Energy. As well, when petroleum operations are undertaken by GNPC under a petroleum contract, GNPC has a carried interest in each petroleum agreement and, following the declaration of any commercial discovery, GNPC’s participating paying interest is typically subject to increase by a certain agreed upon amount at the option of GNPC. Petroleum agreements are required to include certain domestic supply requirements, including the sale to Ghana of oil for consumption in Ghana at international market prices.
The 1984 Ghanaian Petroleum Law and our Ghanaian petroleum agreements contain provisions restricting the direct or indirect assignment or transfer of such petroleum agreements or interests thereunder without the prior written consent of GNPC and the Ministry of Energy. The 1984 Ghanaian Petroleum Law also imposes certain restrictions on the direct or indirect transfer by a contractor of shares of its incorporated company in Ghana to a third party without the prior written consent of Ghana’s Minister of Energy. The Ghanaian Tax Law may impose certain taxes upon the direct or indirect transfer of interests in the petroleum agreements or interests thereunder.
Ghana’s Parliament has enacted a Petroleum Revenue Management Act and the Petroleum Commission Act of 2011. The new Petroleum Revenue Management Act of 2011 pertains primarily to the collection, allocation, and management by the government of Ghana of the petroleum revenue. The Petroleum Commission Act created the Petroleum Commission, whose objective is to regulate and manage the use of petroleum resources and coordinate the policies thereto. The Petroleum Commission became effective in January 2012. Among the Petroleum Commission’s functions are advising the Minister of Energy on matters such as appraisal plans, field development plans, recommending to the Minister national policies related to petroleum, and storing and managing data. We understand the primary purpose of the Petroleum Commission is to fulfill the regulatory functions previously undertaken by GNPC. We currently believe that such laws and the 2016 Ghanaian Petroleum Law will only have prospective application, and as such will not modify the terms of (or interests under) the agreements governing our license interests in Ghana, including the WCTP and DT petroleum contracts (which include stabilization clauses) and the UUOA, and will not impose additional restrictions on the direct or indirect transfer of our license interests, including upon a change of control. The Petroleum (Local Content and Local Participation in Petroleum Activities) Regulations came into effect in February 2014. The Regulations mandate certain levels of local participation in service companies, in‑country manufacturing of goods and the provision of services, and certain reporting requirements.
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Mauritania
The main legislative act in the Islamic Republic of Mauritania relevant to petroleum exploration and production is Law No. 2010‑033 dated July 20, 2010 as amended (the “Hydrocarbon Laws”). The regulatory authority in Mauritania is the Ministry of Petroleum, Energy and Mines and the national oil company acting on its behalf is SMHPM. SMHPM was instituted by Decree No. 2005‑106 of November 7, 2005 and modified by Decree No. 2009‑168 of May 3, 2009 and Decree No. 2014‑01 dated January 6, 2014. Pursuant to the Hydrocarbon Laws, Mauritania or SMHPM may undertake petroleum operations and may authorize other legal entities to undertake petroleum operations under petroleum contracts. The Ministry shall sign petroleum contracts on behalf of Mauritania. Assignments of interests in petroleum contracts also require the consent of the Ministry. The exploration period shall not be more than ten years, subject to certain permitted extensions and the exploitation period shall not be more than 25 years. Petroleum contracts may provide that Mauritania has a carried interest of up to 10% during the exploration period. Petroleum contracts shall grant Mauritania the option to participate for a percentage not less than 10% nor more than 14% in the rights of the contractor during the exploitation period.
Morocco (including Western Sahara)
The two main legislative acts in Morocco relevant to petroleum exploration and production are (i) the Law 21‑90 (April 1, 1992) as amended and completed by the Law 27‑99 (February 15, 2000) and (ii) the Decree 2‑93‑786 (November 3, 1993) as amended and completed by decree 2‑99‑210 (March 16, 2000) (together, “Morocco’s Petroleum Laws”). The regulatory authority in Morocco is the Ministry of Energy, Mines, Water and Environment and the national oil company acting on its behalf is ONHYM. ONHYM is a public establishment ( établissement public ) with the legal personality and financial autonomy created pursuant to the Law 33‑01 (November 11, 2003) which was further completed by the Decree 2‑04‑372 (December 29, 2004).
Pursuant to the Law 21‑90, the granting of an exploration permit is subject to the conclusion of a petroleum contract with the Moroccan State. Therefore, companies who wish to gain rights to explore and produce in Morocco can only do so by entering into a petroleum contract with ONHYM acting on behalf of the State. It is further provided that the State of Morocco (via ONHYM) shall retain a participation in exploration permits or exploitation concessions which shall not be in excess of 25%. More generally, ONHYM is representing the State of Morocco for licensing, exploration and exploitation matters within the limit of its prerogatives set out pursuant to the Law 33‑01. Assignments of interests in exploration permits also require the consent of the administration pursuant to the Law 21‑90.
The Sahrawi Arab Democratic Republic (the “SADR”) has claimed sovereignty over the Western Sahara territory, including the area offshore, and has issued exploration licenses which conflict with those issued by Morocco, including certain licenses which conflict with the Boujdour Maritime block license issued to Kosmos. Other countries have formally recognized the SADR, but the UN has not. It is uncertain when and how Western Sahara’s sovereignty issues will be resolved.
Sao Tome and Principe
The Fundamental Law on Petroleum Operations, Law No. 16/2009 governs petroleum operations in Sao Tome and Principe, including the exploration, development and production of hydrocarbons and the marketing and transportation thereof.  There is also the Petroleum Taxation Law, Law No. 15/2009. The ANP STP is established by Law No. 5/2004, and is responsible for the regulation, contracting and supervision of hydrocarbon operations in Sao Tome and Principe.
Senegal
The Petroleum Code of Senegal, Law No. 98‑05 of January 8, 1998 governs petroleum operations in Senegal, including the exploration, development and production of hydrocarbons and the marketing and transportation thereof, as well as the rights of landowners. The implementing decree is No 98‑810 of October 6, 1998. The Ministry in charge of Energy grants or denies applications for petroleum agreements, and such are granted by decree. Any amendment to the petroleum agreements requires the consent of the Minister. The Senegalese national oil company, Societe des Petroles du Senegal (“PETROSEN”), as the regulatory body tasked with both upstream and downstream missions, is under the supervision of the Ministry of Energy. PETROSEN prepares and negotiates all hydrocarbon licenses and contracts. PETROSEN has a carried interest during the exploration phase. The assignment of interests in petroleum contracts, as well as amendments thereto, require the consent of the Minister.
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Suriname
The three sets of rules governing petroleum exploration and production in Suriname are (i) Staatsolie’s Concession Agreement (Decree E8‑B, Official Gazette 1981 no. 59), (ii) the Mining Decree of 1986 (Official Gazette 1986 no. 28) and (iii) the Petroleum Law 1990 (Official Gazette 1991 no. 7, as amended in 2001).
The Mining Decree granted concession rights for petroleum activities to state enterprises. Staatsolie, the national oil company, was founded in 1980 as a state enterprise and holds mining rights onshore and offshore in Suriname. The Suriname Petroleum Law granted state enterprises with petroleum concession rights the authority, upon the approval of the Minister of Natural Resources, to enter into petroleum contracts with E&P companies. Therefore, companies who wish to gain rights to explore and produce in Suriname can only do so by entering into a petroleum contract with Staatsolie, subject to approval by the Minister of Natural Resources. Assignments of interests in petroleum contracts also require the consent of Staatsolie and/or The Minister of Natural Resources.
Certain Bermuda Law Considerations
As a Bermuda exempted company, we are subject to regulation in Bermuda. Among other things, we must comply with the provisions of the Bermuda Companies Act regulating the payment of dividends and making of distributions from contributed surplus.
We have been designated by the Bermuda Monetary Authority as a non‑resident for Bermuda exchange control purposes. This designation allows us to engage in transactions in currencies other than the Bermuda dollar, and there are no restrictions on our ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda or to pay dividends to United States residents who are holders of our common shares.
Under Bermuda law, “exempted” companies are companies formed for the purpose of conducting business outside Bermuda from a principal place of business in Bermuda. As an exempted company, we may not, without a license or consent granted by the Minister of Finance, participate in certain business transactions, including transactions involving Bermuda landholding rights and the carrying on of business of any kind for which we are not licensed in Bermuda.
Employees
As of December 31, 2016, we had approximately 270 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
We were incorporated pursuant to the laws of Bermuda as Kosmos Energy Ltd. in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings was formed as an exempted company limited by guarantee pursuant to the laws of the Cayman Islands in March 2004. Pursuant to the terms of a corporate reorganization that was completed simultaneously with the closing of our initial public offering, all of the interests in Kosmos Energy Holdings were exchanged for newly issued common shares of Kosmos Energy Ltd. and as a result, Kosmos Energy Holdings became a wholly owned subsidiary of Kosmos Energy Ltd.
We maintain a registered office in Bermuda at Clarendon House, 2 Church Street, Hamilton HM 11, Bermuda. The telephone number of our registered offices is (441) 295‑5950. Our U.S. subsidiary maintains its headquarters at 8176 Park Lane, Suite 500, Dallas, Texas 75231 and its telephone number is (214) 445‑9600.
Available Information
Kosmos is listed on the New York Stock Exchange and our common shares are traded under the symbol KOS. We file or furnish annual, quarterly and current reports, proxy statements and other information with the SEC. The public may read and copy any reports, statements or other information at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information about the operation of the public reference room by calling
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the SEC at 1‑800‑SEC‑0330. In addition, the SEC maintains a website at http://www.sec.gov that contains documents we file electronically with the SEC.
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 Ghana, an area in which we 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 for oil at such depths and the relatively recent discovery of commercial quantities of oil in the region. Likewise, our deepwater offshore Morocco (including Western Sahara), Sao Tome and Principe, Senegal, Suriname and Mauritania 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.
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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.
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. Exploratory wells bear a much greater risk of loss 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, 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 locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management team has identified and scheduled drilling locations on our license 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 partners and regulators, seasonal conditions, oil prices, assessment of risks, costs and drilling results. The final determination on whether to drill 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 activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified
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will be drilled 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 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 have recently experienced significant and sustained declines 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:
 	·	 	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 price and availability of competitors’ supplies of oil and natural gas; and	

 	·	 	the price, availability or mandated use of alternative fuels.	
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
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various petroleum agreements and licenses, our interests in the undeveloped parts of our license areas may lapse. Should the prospects we have identified in this annual report on Form 10‑K under the license agreements currently in place yield discoveries, we cannot assure you that we will not face delays in drilling 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, 2016, we have unfulfilled drilling obligations in 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 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 WCTP and DT Block 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.
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The unit partners’ respective interests in the Jubilee 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 UUOA. The parties to the 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 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 UUOA will not negatively affect our interests in the Jubilee Unit or that such redetermination will be satisfactorily resolved.
We are not, and may not be in the future, the operator on all of our license areas and do not, and may not in the future, hold all of the working interests in certain of our license areas. Therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or 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 Unit Operator on the Jubilee Unit and do not hold operatorship in one of our two blocks offshore Ghana (the DT Block). In addition, the terms of the UUOA governing the unit partners’ interests in the Jubilee Unit require certain actions be approved by at least 80% of the unit voting interests and the terms of our other current or future license or venture agreements may require at least the majority of working interests to approve certain actions. 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 operated by our block partners will depend on a number of factors that will be largely outside of our control, including:
 	·	 	the timing and amount of capital expenditures;	

 	·	 	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; and	

 	·	 	the rate of production of reserves, if any.	
This limited ability to exercise control over the operations on some of 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
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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, 2016.
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.
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. If oil prices decline by $1.00 per Bbl from prices used in calculating such estimates, then the PV‑10 and the Standardized Measure as of December 31, 2016 would each decrease by approximately $28.5 million. Oil prices have recently experienced significant declines. 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 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
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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	

 	·	 	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. 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
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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 Field. A gas pipeline from the Jubilee Field has been constructed to transport such natural gas for processing and sale. However, we granted the first 200 Bcf of natural gas from the Jubilee Phase 1 to Ghana at no cost. Through December 31, 2016, Ghana has received approximately 48 Bcf. Thus, in Ghana, even if additional infrastructure was in place for natural gas processing and sales, it would still be quite some time before we would be able to commercialize our Ghana natural gas. As a result, we do not have proved gas reserves associated with future natural gas sales from Jubilee Field in Ghana. A gas pipeline from the TEN fields to the Jubilee Field is under construction to transport associated natural gas as well as non-associated natural gas for processing and sale. However, we are still finalizing a gas sales agreement. As a result, we do not have proved gas reserves associated with future natural gas sales from the TEN fields in Ghana.
In Mauritania and Senegal, we plan to export the majority of our gas resource to the LNG market. However, that is contingent on making a final investment decision on our gas discoveries and constructing the necessary infrastructure to produce, liquefy and transport the gas to the market as well as finding an LNG purchaser.
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 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 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
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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 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 is currently under construction. However, the uptime of the facility during 2017 and 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 need to flare such natural gas in order to maintain crude oil production. Currently, we have not been issued an amended permit from the Ghana EPA to flare natural gas produced from the Jubilee Field in substantial 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. 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 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, 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. For example, following a February 2016 inspection of the turret area of the Jubilee field FPSO, by SOFEC, Inc., the original turret manufacturer, a potential issue was identified with the turret bearing. As a precautionary measure,	
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additional operating procedures to monitor the turret bearing and reduce the degree of rotation of the vessel have been put in place until this situation has been remediated;	

 	·	 	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.
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.
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 our water injection facilities on the FPSO and water and gas injection wells. This equipment downtime negatively impacted oil production during the year. 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 of and the high cost of this infrastructure, further discoveries we may make in Africa and South America may never be economically producible.
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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 for us, 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 all of our proved reserves are located offshore Ghana. The WCTP petroleum contract, the DT petroleum contract and the 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 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 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.
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 or civil unrest; 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.
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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 Ghanaian Revenue Authority (the “GRA”) has disputed certain tax deductions we have 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.
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, 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 States, the United Kingdom, Bermuda 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.
A portion of our asset portfolio is in Western Sahara, and we could be adversely affected by the political, economic and military conditions in that region. Our exploration licenses in this region conflict with exploration licenses issued by the Sahrawi Arab Democratic Republic (SADR).
Morocco claims the territory of Western Sahara, where our Boujdour Maritime block is geographically located, as part of the Kingdom of Morocco, and it has de facto administrative control of approximately 80% of Western Sahara. However, Western Sahara is on the United Nations (the “UN”) list of Non‑Self‑Governing territories, and the territory’s sovereignty has been in dispute since 1975. The Polisario Front, representing the SADR, has a conflicting claim of sovereignty over Western Sahara. No countries have formally recognized Morocco’s claim to Western Sahara, although some countries implicitly support Morocco’s position. Other countries have formally recognized the SADR, but the UN has not. A UN‑administered cease‑fire has been in place since 1991, and while there have been intermittent UN‑sponsored talks, between Morocco and SADR (represented by the Polisario Front), the dispute remains stalemated. It is uncertain when and how Western Sahara’s sovereignty issues will be resolved.
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We own a 55% participating interest in the Boujdour Maritime block located geographically offshore Western Sahara. Our license was granted by the government of Morocco; however, the SADR has issued its own offshore exploration licenses which, in some areas, conflict with our licenses. As a result of SADR’s conflicting claim of rights to oil and natural gas licenses granted by Morocco, and the SADR’s claims that Morocco’s exploitation of Western Sahara’s natural resources violates international law, our interests could decrease in value or be lost. Any political instability, terrorism, changes in government, or escalation in hostilities involving the SADR, Morocco or neighboring states could adversely affect our operations and assets. In addition, Morocco has recently experienced political and social disturbances that could affect its legal and administrative institutions. A change in U.S. foreign policy or the policies of other countries regarding Western Sahara could also adversely affect our operations and assets. We are not insured against political or terrorism risks because management deems the premium costs of such insurance to be currently prohibitively expensive relative to the limited coverage provided thereby.
Furthermore, various activist groups have mounted public relations campaigns to force companies to cease and divest operations in Western Sahara, and we could come under similar public pressure. Some investors have refused to invest in companies with operations in Western Sahara, and we could be subject to similar pressure. Any of these factors could have a negative impact on our stock price and a material adverse effect on our results of operations and financial condition.
A maritime boundary demarcation between Côte D’Ivoire and Ghana may affect a portion of our license areas offshore Ghana.
The historical maritime boundary between Ghana and its western neighbor, the Republic of Côte d’Ivoire, forms the western boundary of the DT Block offshore Ghana. In early 2010, Côte d’Ivoire petitioned the United Nations to demarcate the Ivorian territorial maritime boundary with Ghana. In response to the petition, Ghana established a Boundary Commission to undertake negotiations with Côte d’Ivoire in an effort to resolve their respective maritime boundary. The Ivorian Government then issued a map in September 2011, which reflected potential petroleum license areas that overlap with the DT Block. In September 2014, Ghana submitted the matter to arbitration under the United Nations Convention on the Law of the Sea, and in December 2014, the two parties agreed to transfer the dispute to the ITLOS. On January 12, 2015, the ITLOS formed a special chamber to address the maritime boundary dispute.
On March 2, 2015, Côte D’Ivoire applied to the ITLOS for a provisional measures order suspending activities in the disputed area in which the TEN fields is located until the substantive case concerning the border dispute is adjudicated. More specifically, the provisional measures application asked that Ghana be ordered to: (i) suspend all ongoing exploration and exploitation operations in the disputed area, (ii) refrain from granting any authorizations for new exploration and exploitation in the disputed area, (iii) not use any data acquired in the disputed area in any way that would be detrimental to Côte d’Ivoire, and (iv) take any necessary action for the preservation of the continental shelf, its water, and its underground in the disputed area.
In late April 2015, the Special Chamber of ITLOS issued its order in response to Côte d’Ivoire’s provisional measures application. In its order, ITLOS rejected Côte d’Ivoire’s requests that Ghana suspend its ongoing exploration and development operations in the disputed area but ordered Ghana to: (i) take all necessary steps to ensure that no new drilling either by Ghana or any entity or person under its control takes place in the disputed area; (ii) take all necessary steps to prevent information resulting from past, ongoing or future exploration activities conducted by Ghana, or with its authorization, in the disputed area that is not already in the public domain from being used in any way whatsoever to the detriment of Cote d’Ivoire; (iii) carry out strict and continuous monitoring of all activities undertaken by Ghana or with its authorization in the disputed area with a view to ensuring the prevention of serious harm to the marine environment; (iv) take all necessary steps to prevent serious harm to the marine environment, including the continental shelf and its superjacent waters, in the disputed area and shall cooperate to that end; and (v) pursue cooperation with Côte d’Ivoire and refrain from any unilateral action that might lead to aggravating the dispute. On June 11, 2015, the Ghana Attorney General issued a letter to the DT Operator, which confirmed the DT Block partners may (i) continue to drill wells that had been started but not completed prior to the ITLOS order and (ii) carry out completion work on wells that have already been drilled.  The TEN fields achieved first oil in the third quarter of 2016.  With respect to the Wawa Discovery, in April 2016 the Ghana Ministry of Energy approved our request to enlarge the TEN fields and production area subject to continued subsurface and development concept evaluation, along with the requirement to integrate the Wawa Discovery into the TEN PoD. Any future drilling activities for the Wawa Discovery would be subject to resolution of the ITLOS order.
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We do not know if the maritime boundary dispute will change our and our block partners’ rights to undertake further development and production from within our discoveries within such areas. In the event that the ITLOS proceedings result in an unfavorable outcome for Ghana, our operations within such areas could be materially impacted.
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.
Participants in the oil and gas industry are subject to numerous laws 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	

 	·	 	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 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 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. See “Item 1. Business—Other Regulation of the Oil and Gas Industry—Ghana.”
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We are subject to numerous environmental, health and safety laws and regulations which may result in material liabilities and costs.
We are subject to various international, foreign, federal, state and local environmental, health and safety 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. 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 environmental, health and safety 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 environmental, health or safety 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.
We are not fully insured against all risks and our insurance may not cover any or all environmental, health or safety 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, Morocco, 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, Morocco, 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 whether there may be changes to these international agreements as a result of the new Trump administration, which regulatory uncertainty 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,
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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.
Environmental, health and safety laws are complex, change frequently and have tended to become increasingly stringent over time. Our costs of complying with current and future climate change, environmental, health and safety 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, 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;	

 	·	 	increased costs of doing business;	

 	·	 	reduction in demand for our products; and	

 	·	 	other adverse effects on our ability to develop our properties.	
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
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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.
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 shares. 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,
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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.
The recovery from the global economic crisis of 2008 and resulting recession has been slow and uneven. Market volatility and reduced consumer demand have increased economic uncertainty, and the current global economic growth rate is slower than what was experienced in the decade preceding the crisis. 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 currently, and 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;	

 	·	 	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.
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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 shares of an opportunity to sell their common shares 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, 2016, we had $850.0 million outstanding and $616.9 million of committed undrawn capacity under our commercial debt facility, subject to borrowing base availability. As of December 31, 2016, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability was $400.0 million. As of December 31, 2016, there were 9 outstanding letters of credit totaling $72.8 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
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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 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 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 of ours while carrying on our ongoing business;	

 	·	 	difficulty associated with coordinating geographically separate organizations; and	

 	·	 	the challenge of attracting and retaining personnel associated with acquired operations.	
The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be adversely affected.
The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost
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savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, increased interest expense associated with debt incurred or assumed in connection with the transaction, adverse changes in oil and gas industry conditions, or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties, including the assumption of environmental or other liabilities in connection with the acquisition. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.
Our bye‑laws contain a provision renouncing our interest and expectancy in certain corporate opportunities, which could adversely affect our business or future prospects.
Our bye‑laws provide that, to the fullest extent permitted by applicable law, we renounce any right, interest or expectancy in, or in being offered an opportunity to participate in, any business opportunity that may be from time to time be presented to certain of our affiliates or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (other than us and our subsidiaries) or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such person shall be liable to us for breach of any statutory, fiduciary, contractual or other duty, as a director or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us unless, in the case of any such person who is our director, such person fails to present any business opportunity that is expressly offered to such person solely in his or her capacity as our director.
As a result, our directors and certain of our affiliates and their respective affiliates may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they or their affiliates have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing of our interest and expectancy in any business opportunity that may be from time to time presented to our directors and certain of our affiliates and their respective affiliates could adversely impact our business or future prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours.
We receive certain beneficial tax treatment as a result of being an exempted company incorporated pursuant to the laws of Bermuda. Changes in that treatment could have a material adverse effect on our net income, our cash flow and our financial condition.
We are an exempted company incorporated pursuant to the laws of Bermuda and operate through subsidiaries in a number of countries throughout the world. Consequently, we are subject to changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the United States, Bermuda, Ghana, and other jurisdictions in which we or any of our subsidiaries operate or are resident. In the past, legislation has been introduced in the Congress of the United States that would reform the U.S. tax laws as they apply to certain non‑U.S. entities and operations, including legislation that would treat a foreign corporation as a U.S. corporation for U.S. federal income tax purposes if substantially all of its senior management is located in the United States. If this or similar legislation is passed that changes our U.S. tax position, it could have a material adverse effect on our net income, our cash flow and our financial condition.
We may become subject to taxes in Bermuda after March 31, 2035, which may have a material adverse effect on our results of operations.
The Bermuda Minister of Finance, under the Exempted Undertakings Tax Protection Act 1966 of Bermuda, as amended, has given us an assurance that if any legislation is enacted in Bermuda that would impose tax computed on profits or income, or computed on any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance tax, then the imposition of any such tax will not be applicable to us or any of our operations, shares, debentures or other obligations until March 31, 2035, except insofar as such tax applies to persons who ordinarily reside in Bermuda or to any taxes payable by us in respect of real property owned or leased by us in Bermuda.
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The impact of Bermuda’s letter of commitment to the Organization for Economic Cooperation and Development to eliminate harmful tax practices is uncertain and could adversely affect our tax status in Bermuda.
The Organization for Economic Cooperation and Development (“OECD”) has published reports and launched a global initiative among member and non‑member countries on measures to limit harmful tax competition. These measures are largely directed at counteracting the effects of tax havens and preferential tax regimes in countries around the world. According to the OECD, Bermuda is a jurisdiction that has substantially implemented the internationally agreed tax standard and as such is listed on the OECD “white” list. However, we are not able to predict whether any changes will be made to this classification or whether such changes will subject us to additional taxes.
The adoption of financial reform legislation by the United States Congress in 2010, and its implementing regulations, could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price and other risks associated with our business.
We use derivative instruments to manage our commodity price and interest rate risk. The United States Congress adopted comprehensive financial reform legislation in 2010 that establishes federal oversight and regulation of the over‑the‑counter derivatives market and entities, such as ours, that participate in that market. The Dodd‑Frank Act was signed into law by the President on July 21, 2010. The Commodity Futures Trading Commission (“CFTC”), which has jurisdiction over derivatives instruments that are “swaps,” has implemented many, but not all, of these provisions through regulations; the SEC, which regulates “security-based swaps” has proposed but not finalized most of its implementing regulations.
Of particular importance to us, the CFTC has the authority to, under certain findings, establish position limits for certain futures, options on futures and swap contracts. Certain bona fide hedging transactions or positions would be exempt from these position limits. The CFTC has proposed rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain energy, metal, and agricultural physical commodities, subject to exceptions for certain bona fide hedging transactions. It is not possible at this time to predict when the CFTC will finalize these regulations; therefore, the impact of those provisions on us is uncertain at this time.
The CFTC has designated certain interest‑rate swaps and index credit default swaps for mandatory clearing and exchange trading. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. The application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that the Company uses for hedging.
Derivatives dealers that we transact with will need to comply with new margin and segregation requirements for uncleared swaps and security-based swaps. While it is expected that our uncleared derivatives transactions will not directly be subject to those margin requirements, due to the increased costs to dealers for transacting uncleared derivatives in general, our costs for these transactions may increase.
The Dodd‑Frank Act and its implementing regulations may also require the counterparties to our derivative instruments to register with the CFTC and become subject to substantial regulation or even spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. These requirements and others could significantly increase the cost of derivatives contracts (including through requirements to clear swaps and to post collateral, each of which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Our revenues could also be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.
The European Union and other non‑U.S. jurisdictions are also implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we or our transactions may become subject to such regulations. At this time, the impact of such regulations is not clear.
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Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
We may become a “passive foreign investment company” for U.S. federal income tax purposes, which could create adverse tax consequences for U.S. investors.
U.S. investors that hold stock in a “passive foreign investment company” (“PFIC”) are subject to special rules that can create adverse U.S. federal income tax consequences, including imputed interest charges and recharacterization of certain gains and distributions. Based on management estimates and projections of future revenue, we do not believe that we will be a PFIC for the current taxable year and we do not expect to become one in the foreseeable future. Because PFIC status is a factual determination that is made annually and thus is subject to change, there can be no assurance that we will not be a PFIC for any taxable year.
A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.
The oil and gas industry has become increasingly dependent on digital technologies to conduct day‑to‑day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data.
We depend on digital technology, including information systems and related infrastructure as well as cloud application and services, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. Our business partners, including vendors, service providers, co‑venturers, purchasers of our production, and financial institutions, are also dependent on digital technology. The complexity of the technologies needed to explore for and develop oil and gas in increasingly difficult physical environments, such as deepwater, and global competition for oil and gas resources make certain information more attractive to thieves.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber‑attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial‑of‑service on websites. For example, in 2012, a wave of network attacks impacted Saudi Arabia’s oil industry and breached financial institutions in the U.S. Certain countries are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies.
Our technologies, systems, networks, and those of our business partners may become the target of cyber‑attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations. Although to date we have not experienced any significant cyber‑attacks, there can be no assurance that we will not be the target of cyber‑attacks in the future or suffer such losses related to any cyber‑incident. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
Outbreaks of disease in the geographies in which we operate may adversely affect our business operations and financial condition.
Many of our operations are currently, and will likely remain in the near future, in developing countries which are susceptible to outbreaks of disease and may lack the resources to effectively contain such an outbreak quickly. Such outbreaks may impact our ability to explore for oil and gas, develop or produce our license areas by limiting access to qualified personnel, increasing costs associated with ensuring the safety and health of our personnel, restricting transportation of personnel, equipment, supplies and oil and gas production to and from our areas of operation and diverting the time, attention and resources of government agencies which are necessary to conduct our operations. In addition, any losses we experience as a result of such outbreaks of disease which impact sales or delay production may not be covered by our insurance policies.
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An epidemic of the Ebola virus disease occurred in parts of West Africa in 2014 and continued through 2015. A substantial number of deaths were reported by the World Health Organization (“WHO”) in West Africa, and the WHO declared it a global health emergency. It is impossible to predict the effect and potential spread of new outbreaks of the Ebola virus in West Africa and surrounding areas. Should another Ebola virus outbreak occur, including to the countries in which we operate, or not be satisfactorily contained, our exploration, development and production plans for our operations could be delayed, or interrupted after commencement. Any changes to these operations could significantly increase costs of operations. Our operations require contractors and personnel to travel to and from Africa as well as the unhindered transportation of equipment and oil and gas production (in the case of our producing fields). Such operations also rely on infrastructure, contractors and personnel in Africa. If travel bans are implemented or extended to the countries in which we operate, including Ghana, or contractors or personnel refuse to travel there, we could be adversely affected. If services are obtained, costs associated with those services could be significantly higher than planned which could have a material adverse effect on our business, results of operations, and future cash flow. In addition, should an Ebola virus outbreak spread to Ghana, access to the FPSO operating at the Jubilee Field could be restricted and/or terminated. The FPSO is potentially able to operate for a short period of time without access to the mainland, but if restrictions extended for a longer period we and the operator of the Jubilee Field would likely be required to cease production and other operations until such restrictions were lifted.
Risks Relating to Our Common Shares
Our share price may be volatile, and purchasers of our common shares could incur substantial losses.
Our share price may be volatile. The stock market in general has experienced extreme volatility that has often been unrelated to the operating performance of particular companies. The market price for our common shares may be influenced by many factors, including, but not limited to:
 	·	 	the price of oil and natural gas;	

 	·	 	the success of our exploration and development operations, and the marketing of any oil and natural gas we produce;	

 	·	 	operational incidents;	

 	·	 	regulatory developments in Bermuda, the United States and foreign countries where we operate;	

 	·	 	the recruitment or departure of key personnel;	

 	·	 	quarterly or annual variations in our financial results or those of companies that are perceived to be similar to us;	

 	·	 	market conditions in the industries in which we compete and issuance of new or changed securities;	

 	·	 	analysts’ reports or recommendations;	

 	·	 	the failure of securities analysts to cover our common shares or changes in financial estimates by analysts;	

 	·	 	the inability to meet the financial estimates of analysts who follow our common shares;	

 	·	 	the issuance or sale of any additional securities of ours;	

 	·	 	investor perception of our company and of the industry in which we compete; and	

 	·	 	general economic, political and market conditions.	
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A substantial portion of our total issued and outstanding common shares may be sold into the market at any time. This could cause the market price of our common shares to drop significantly, even if our business is doing well.
All of the shares sold in our initial public offering are freely tradable without restrictions or further registration under the federal securities laws, unless purchased by our “affiliates” as that term is defined in Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”). Substantially all of the remaining common shares are restricted securities as defined in Rule 144 under the Securities Act (unless they have been sold pursuant to Rule 144 to date). Restricted securities may be sold in the U.S. public market only if registered or if they qualify for an exemption from registration, including by reason of Rule 144 or Rule 701 under the Securities Act. All of our restricted shares are eligible for sale in the public market, subject in certain circumstances to the volume, manner of sale limitations with respect to shares held by our affiliates and other limitations under Rule 144. Additionally, we have registered all our common shares that we may issue under our employee benefit plans. These shares can be freely sold in the public market upon issuance, unless pursuant to their terms these share awards have transfer restrictions attached to them. Sales of a substantial number of our common shares, or the perception in the market that the holders of a large number of shares intend to sell common shares, could reduce the market price of our common shares.
The concentration of our share capital ownership among our largest shareholders, and their affiliates, will limit your ability to influence corporate matters.
Our two largest shareholders collectively own approximately 48% of our issued and outstanding common shares as of February 1, 2017. Consequently, these shareholders have significant influence over all matters that require approval by our shareholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.
Holders of our common shares will be diluted if additional shares are issued.
We may issue additional common shares, preferred shares, warrants, rights, units and debt securities for general corporate purposes, including, but not limited to, repayment or refinancing of borrowings, working capital, capital expenditures, investments and acquisitions. We continue to actively seek to expand our business through complementary or strategic acquisitions, and we may issue additional common shares in connection with those acquisitions. We also issue restricted shares to our executive officers, employees and independent directors as part of their compensation. If we issue additional common shares in the future, it may have a dilutive effect on our current outstanding shareholders.
We do not intend to pay dividends on our common shares and, consequently, your only opportunity to achieve a return on your investment is if the price of our shares appreciates.
We do not plan to declare dividends on shares of our common shares in the foreseeable future. Additionally, certain of our subsidiaries are currently restricted in their ability to pay dividends to us pursuant to the terms of our commercial debt facility unless they meet certain conditions, financial and otherwise. Consequently, investors must rely on sales of their common shares after price appreciation, which may never occur, as the only way to realize a return on their investment.
We are a Bermuda company and a significant portion of our assets are located outside the United States. As a result, it may be difficult for shareholders to enforce civil liability provisions of the federal or state securities laws of the United States.
We are a Bermuda exempted company. As a result, the rights of holders of our common shares will be governed by Bermuda law and our memorandum of association and bye‑laws. The rights of shareholders under Bermuda law may differ from the rights of shareholders of companies incorporated in other jurisdictions. Some of our directors are not residents of the United States, and a substantial portion of our assets are located outside the United States. As a result, it may be difficult for investors to effect service of process on that person in the United States or to enforce in the United States judgments obtained in U.S. courts against us or that person based on the civil liability provisions of the U.S. securities laws. It is doubtful whether courts in Bermuda will enforce judgments obtained in other jurisdictions, including the United States, against us or our directors or officers under the securities laws of those jurisdictions or entertain actions in Bermuda against us or our directors or officers under the securities laws of other jurisdictions.
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Bermuda law differs from the laws in effect in the United States and might afford less protection to shareholders.
Our shareholders could have more difficulty protecting their interests than would shareholders of a corporation incorporated in a jurisdiction of the United States. As a Bermuda company, we are governed by the Companies Act 1981 of Bermuda (the “Bermuda Companies Act”). The Bermuda Companies Act differs in some material respects from laws generally applicable to U.S. corporations and shareholders, including the provisions relating to interested directors, mergers and acquisitions, takeovers, shareholder lawsuits and indemnification of directors. Set forth below is a summary of these provisions, as well as modifications adopted pursuant to our bye‑laws, which differ in certain respects from provisions of Delaware corporate law. Because the following statements are summaries, they do not discuss all aspects of Bermuda law that may be relevant to us and our shareholders.
Interested Directors.  Under Bermuda law and our bye‑laws, as long as a director discloses a direct or indirect interest in any contract or arrangement with us as required by law, such director is entitled to vote in respect of any such contract or arrangement in which he or she is interested, unless disqualified from doing so by the chairman of the meeting, and such a contract or arrangement will not be voidable solely as a result of the interested director’s participation in its approval. In addition, the director will not be liable to us for any profit realized from the transaction. In contrast, under Delaware law, such a contract or arrangement is voidable unless it is approved by a majority of disinterested directors or by a vote of shareholders, in each case if the material facts as to the interested director’s relationship or interests are disclosed or are known to the disinterested directors or shareholders, or such contract or arrangement is fair to the corporation as of the time it is approved or ratified. Additionally, such interested director could be held liable for a transaction in which such director derived an improper personal benefit.
Mergers and Similar Arrangements.  The amalgamation of a Bermuda company with another company or corporation (other than certain affiliated companies) requires the amalgamation agreement to be approved by the company’s board of directors and by its shareholders. Unless the company’s bye‑laws provide otherwise, the approval of 75% of the shareholders voting at such meeting is required to approve the amalgamation agreement, and the quorum for such meeting must be two persons holding or representing more than one‑third of the issued shares of the company. Our bye‑laws provide that an amalgamation (other than with a wholly owned subsidiary, per the Bermuda Companies Act) that has been approved by the board must only be approved by shareholders owning a majority of the issued and outstanding shares entitled to vote. Under Bermuda law, in the event of an amalgamation of a Bermuda company with another company or corporation, a shareholder of the Bermuda company who is not satisfied that fair value has been offered for such shareholder’s shares may, within one month of notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the fair value of those shares. Under Delaware law, with certain exceptions, a merger, consolidation or sale of all or substantially all the assets of a corporation must be approved by the board of directors and a majority of the issued and outstanding shares entitled to vote thereon. Under Delaware law, a shareholder of a corporation participating in certain major corporate transactions may, under certain circumstances, be entitled to appraisal rights pursuant to which such shareholder may receive cash in the amount of the fair value of the shares held by such shareholder (as determined by a court) in lieu of the consideration such shareholder would otherwise receive in the transaction.
Shareholders’ Suit.  Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company’s memorandum of association or bye‑laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of the company’s shareholders than that which actually approved it.
When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply to the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company’s affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company.
Our bye‑laws contain a provision by virtue of which we and our shareholders waive any claim or right of action that they have, both individually and on our behalf, against any director or officer in relation to any action or failure to take action by such director or officer, except in respect of any fraud or dishonesty of such director or officer. Class actions and derivative actions generally are available to shareholders under Delaware law for, among other things, breach of
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fiduciary duty, corporate waste and actions not taken in accordance with applicable law. In such actions, the court has discretion to permit the winning party to recover attorneys’ fees incurred in connection with such action.
Indemnification of Directors.  We may indemnify our directors and officers in their capacity as directors or officers for any loss arising or liability attaching to them by virtue of any rule of law in respect of any negligence, default, breach of duty or breach of trust of which a director or officer may be guilty in relation to the company other than in respect of his own fraud or dishonesty. Under Delaware law, a corporation may indemnify a director or officer of the corporation against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in defense of an action, suit or proceeding by reason of such position if such director or officer acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, such director or officer had no reasonable cause to believe his or her conduct was unlawful. In addition, we have entered into customary indemnification agreements with our directors.
Item 1B.  Unresolved Staff Comments
Not applicable.
Item 2.  Properties
See “Item 1. Business.” We also have various operating leases for rental of office space, office and field equipment, and vehicles. See Note 15 of Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for the future minimum rental payments. Such information is incorporated herein by reference.
Item 3.  Legal Proceedings
From time to time, we may be involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the occurrence or outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flows; however, an unfavorable outcome could have a material adverse effect on our results of operations for a specific interim period or year.
In June 2016, Kosmos Energy Ghana HC filed a Request for Arbitration with the International Chamber of Commerce against Tullow Ghana Limited in connection with a dispute arising under the DT Joint Operating Agreement. At dispute is Kosmos Energy Ghana HC’s responsibility for expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow has charged such expenditures to the DT joint account. Kosmos disputes that these expenditures are chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement.
Item 4.  Mine Safety Disclosures
Not applicable.
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PART II
Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Shares Trading Summary
Our common shares are traded on the NYSE under the symbol KOS. The following table shows the quarterly high and low sale prices of our common shares.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2016	 	2015	 	
 	 	High	 	Low	 	High	 	Low	 	
First Quarter	    	$	6.41	    	$	3.17	    	$	9.32	    	$	7.58	 	
Second Quarter	 	 	6.79	 	 	4.63	 	 	10.03	 	 	7.94	 	
Third Quarter	 	 	6.63	 	 	5.16	 	 	8.44	 	 	5.34	 	
Fourth Quarter	 	 	7.14	 	 	4.39	 	 	8.00	 	 	4.62	 	
As of February 21, 2017, based on information from the Company’s transfer agent, Computershare Trust Company, N.A., the number of holders of record of Kosmos’ common shares was 107. On February 21, 2017, the last reported sale price of Kosmos’ common shares, as reported on the NYSE, was $6.09 per share.
We have never paid any dividends on our common shares. At the present time, we intend to retain all of our future earnings, if any, generated by our operations for the development and growth of our business. Additionally, we are subject to Bermuda legal constraints that may affect our ability to pay dividends on our common shares and make other payments. Under the Bermuda Companies Act, we may not declare or pay a dividend if there are reasonable grounds for believing that we are, or would after the payment be, unable to pay our liabilities as they become due or that the realizable value of our assets would thereafter be less than the aggregate of our liabilities, issued share capital and share premium accounts. Certain of our subsidiaries are also currently restricted in their ability to pay dividends to us pursuant to the terms of the Senior Notes, the Facility and the Corporate Revolver unless we meet certain conditions, financial and otherwise. Any decision to pay dividends in the future is at the discretion of our board of directors and depends on our financial condition, results of operations, capital requirements and other factors that our board of directors deems relevant. Currently we do not anticipate paying any dividends in the foreseeable future.
Issuer Purchases of Equity Securities
Under the terms of our Long Term Incentive Plan (“LTIP”), we have issued shares of restricted shares to our employees. On the date that these restricted shares vest, we provide such employees the option to sell shares to cover their tax liability, via a net exercise provision pursuant to our applicable restricted share award agreements and the LTIP, either the number of vested shares (based on the closing price of our common shares on such vesting date) equal to the minimum statutory tax liability owed by such grantee or up to the maximum statutory tax liability for such grantee. The Company may repurchase the restricted shares sold by the grantees to settle their tax liability. The repurchased shares are reallocated to the number of shares available for issuance under the LTIP. The following table outlines the total number of shares purchased during fiscal year 2016 and the average price paid per share.
 	 	 	 	 	 	 	
 	    	Total Number	    	Average	 	
 	 	of Shares	 	Price Paid	 	
 	 	Purchased	 	per Share	 	
 	 	(In thousands)	 	 	 	 	
January 1, 2016—January 31, 2016	 	79	 	$	5.20	 	
February 1, 2016—February 29, 2016	 	14	 	 	4.32	 	
March 1, 2016—March 31, 2016	 	4	 	 	4.92	 	
April 1, 2016—April 30, 2016	 	9	 	 	5.56	 	
May 1, 2016—May 31, 2016	 	5	 	 	6.48	 	
June 1, 2016—June 30, 2016	 	17	 	 	5.60	 	
July 1, 2016—July 31, 2016	 	 —	 	 	 —	 	
August 1, 2016—August 31, 2016	 	 —	 	 	 —	 	
September 1, 2016—September 30, 2016	 	 —	 	 	 —	 	
October 1, 2016—October 31, 2016	 	 —	 	 	 —	 	
November 1, 2016—November 30, 2016	 	 —	 	 	 —	 	
December 1, 2016—December 31, 2016	 	 —	 	 	 —	 	
Total	 	128	 	 	5.22	 	
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Share Performance Graph
The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filings.
The following graph illustrates changes over the five-year period ended December 31, 2016, in cumulative total stockholder return on our common shares as measured against the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration & Production Index. The graph tracks the performance of a $100 investment in our common shares and in each index (with the reinvestment of all dividends).

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2011	 	2012	 	2013	 	2014	 	2015	 	2016	 	
Kosmos Energy Ltd. (KOS)	 	$	100.00	   	$	68.61	  	$	62.11	 	$	46.61	    	$	28.89	    	$	38.94	 	
S&P 500 (SPX)	 	 	100.00	 	 	109.36	 	 	143.24	 	 	161.77	 	 	163.86	 	 	186.29	 	
Dow Jones U.S. Exploration & Production Index (DWCEXP)	 	 	100.00	 	 	78.53	 	 	99.03	 	 	71.71	 	 	40.71	 	 	97.13	 	
 
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Item 6.  Selected Financial Data
The following selected consolidated financial information set forth below as of and for the five years ended, December 31, 2016, should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data.”
 
Consolidated Statements of Operations Information:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	    	2016	    	2015	    	2014	    	2013	    	2012	 	
 	 	(In thousands, except per share data)	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenue	 	$	310,377	 	$	446,696	 	$	855,877	 	$	851,212	 	$	667,951	 	
Gain on sale of assets	 	 	 —	 	 	24,651	 	 	23,769	 	 	 —	 	 	 —	 	
Other income	 	 	74,978	 	 	209	 	 	3,092	 	 	941	 	 	3,150	 	
Total revenues and other income	 	 	385,355	 	 	471,556	 	 	882,738	 	 	852,153	 	 	671,101	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas production	 	 	119,367	 	 	105,336	 	 	100,122	 	 	96,791	 	 	95,109	 	
Facilities insurance modifications	 	 	14,961	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	
Exploration expenses	 	 	202,280	 	 	156,203	 	 	93,519	 	 	230,314	 	 	100,652	 	
General and administrative	 	 	87,623	 	 	136,809	 	 	135,231	 	 	158,421	 	 	157,087	 	
Depletion and depreciation	 	 	140,404	 	 	155,966	 	 	198,080	 	 	222,544	 	 	185,707	 	
Interest and other financing costs, net	 	 	44,147	 	 	37,209	 	 	45,548	 	 	47,590	 	 	65,425	 	
Derivatives, net	 	 	48,021	 	 	(210,649)	 	 	(281,853)	 	 	17,027	 	 	31,490	 	
Restructuring charges	 	 	 —	 	 	 —	 	 	11,742	 	 	 —	 	 	 —	 	
Other expenses, net	 	 	23,116	 	 	5,246	 	 	2,081	 	 	3,512	 	 	1,475	 	
Total costs and expenses	 	 	679,919	 	 	386,120	 	 	304,470	 	 	776,199	 	 	636,945	 	
Income (loss) before income taxes	 	 	(294,564)	 	 	85,436	 	 	578,268	 	 	75,954	 	 	34,156	 	
Income tax expense (benefit)	 	 	(10,784)	 	 	155,272	 	 	298,898	 	 	166,998	 	 	101,184	 	
Net income (loss)	 	$	(283,780)	 	$	(69,836)	 	$	279,370	 	$	(91,044)	 	$	(67,028)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss) per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	$	(0.74)	 	$	(0.18)	 	$	0.73	 	$	(0.24)	 	$	(0.18)	 	
Diluted	 	$	(0.74)	 	$	(0.18)	 	$	0.72	 	$	(0.24)	 	$	(0.18)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average number of shares used to compute net  per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	385,402	 	 	382,610	 	 	379,195	 	 	376,819	 	 	371,847	 	
Diluted	 	 	385,402	 	 	382,610	 	 	386,119	 	 	376,819	 	 	371,847	 	
 
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Consolidated Balance Sheets Information:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	    	2016	    	2015(1)(2)	    	2014(1)	    	2013(1)	    	2012(1)	 	
 	 	(In thousands)	 	
Cash and cash equivalents	 	$	194,057	 	$	275,004	 	$	554,831	 	$	598,108	 	$	515,164	 	
Total current assets	 	 	475,187	 	 	734,148	 	 	1,010,476	 	 	734,961	 	 	750,118	 	
Total property and equipment, net	 	 	2,708,892	 	 	2,322,839	 	 	1,784,846	 	 	1,522,962	 	 	1,525,762	 	
Total other assets	 	 	157,386	 	 	146,063	 	 	131,537	 	 	53,742	 	 	48,021	 	
Total assets	 	 	3,341,465	 	 	3,203,050	 	 	2,926,859	 	 	2,311,665	 	 	2,323,901	 	
Total current liabilities	 	 	370,025	 	 	456,741	 	 	448,771	 	 	219,324	 	 	190,253	 	
Total long-term liabilities	 	 	1,890,241	 	 	1,420,796	 	 	1,139,129	 	 	1,100,006	 	 	1,104,742	 	
Total shareholders’ equity	 	 	1,081,199	 	 	1,325,513	 	 	1,338,959	 	 	992,335	 	 	1,028,906	 	
Total liabilities and shareholders’ equity	 	 	3,341,465	 	 	3,203,050	 	 	2,926,859	 	 	2,311,665	 	 	2,323,901	 	
 
 	(1)	 	Effective December 31, 2015, the Company adopted new guidance on the presentation of debt issuance costs. This guidance was adopted retrospectively and all prior periods have been adjusted to reflect this change in accounting principle. 	

 	(2)	 	Effective December 31, 2015, the Company adopted new guidance on the presentation of deferred taxes. The Company elected to adopt the accounting change using the prospective method. See Note 2 of Notes to the Consolidated Financial Statements. 	
Consolidated Statements of Cash Flows Information:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	    	2016	    	2015(1)	    	2014(1)	    	2013(1)	    	2012(1)	 	
 	 	(In thousands)	 	
Net cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	$	52,077	 	$	440,779	 	$	443,586	 	$	522,404	 	$	371,530	 	
Investing activities	 	 	(537,763)	 	 	(796,433)	 	 	(368,603)	 	 	(322,383)	 	 	(378,984)	 	
Financing activities	 	 	448,019	 	 	79,634	 	 	(139,184)	 	 	(115,327)	 	 	(126,796)	 	

 	(1)	 	Effective December 31, 2016, the Company adopted new guidance on the presentation of restricted cash. This guidance was adopted retrospectively and all prior periods have been adjusted to reflect this change in accounting principle. 	

 

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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis contains forward‑looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward‑looking statements as a result of various factors, including, without limitation, those set forth in “Cautionary Statement Regarding Forward‑Looking Statements” and “Item 1A. Risk Factors.” The following discussion of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this annual report on Form 10‑K.
Overview
Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margins. Our assets include existing production and development projects offshore Ghana, large discoveries and significant further hydrocarbon exploration potential offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Sao Tome and Principe, Suriname, Morocco and Western Sahara.
Recent Developments
Corporate
In July 2016, we amended and restated the revolving letter of credit facility agreement (“LC Facility”), extending the maturity date to July 2019. The LC Facility size remains at $75.0 million, as amended in July 2015, with additional commitments up to $50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. Other amendments include increasing the margin from 0.5% to 0.8% per annum on amounts outstanding, adding a commitment fee payable quarterly in arrears at an annual rate equal to 0.65% on the available commitment amount and providing for issuance fees to be payable to the lender per new issuance of a letter of credit.
 
In September 2016, following the lender’s semi-annual redetermination, the borrowing base under our Facility was increased from the March 2016 redetermination to $1.467 billion (effective October 1, 2016). The borrowing base calculation includes value related to the Jubilee and TEN fields.
 
In February 2017, we exercised an option to increase the size of the LC Facility to $125.0 million to facilitate the issuance of additional letters of credit.
 
Rig Agreement
In January 2017, Kosmos Energy Ventures (“KEV”), a subsidiary of Kosmos Energy Ltd., exercised its right under the amended Atwood Achiever rig agreement with Atwood Oceanics, Inc. to exercise its option to cancel the fourth year and revert to the original day rate of approximately $0.6 million per day and original agreement end date of November 2017. KEV is required to make a rate recovery payment of approximately $48.1 million based on this election.
Ghana
 
Jubilee
 
In February 2016, the Jubilee Field operator identified an issue with the turret bearing of the FPSO Kwame Nkrumah. This necessitated the FPSO to be shut down for an extended period beginning in March with production resuming in early May. This resulted in the need to implement new operating and offloading procedures, including the use of tug boats for heading control and a dynamically positioned (“DP”) shuttle tanker and storage vessel for offloading. These new operating procedures were successfully implemented in April 2016 and are working effectively as evidenced by the fact that 81 parcels have been offloaded from the FPSO since implementation through December 31, 2016. Oil production from the Jubilee Field averaged approximately 73,700 barrels (gross) of oil per day during 2016.
Kosmos and its partners have determined the preferred long-term solution to the turret bearing issue is to convert
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the FPSO to a permanently spread moored facility, with offloading through a new deepwater Catenary Anchor Leg Mooring (“CALM”) buoy. The partners are now working with the Government of Ghana to amend the field operating philosophy for this field remediation solution. The Jubilee turret remediation work is progressing as planned and the FPSO spread-mooring on its current heading is expected to be completed by March 2017. This will allow the tug boats previously required to hold the vessel on a fixed heading to be removed, significantly reducing the complexity of the current operation. The next phase of the remediation work involves modifications to the turret for long-term spread-moored operations. At present, the partnership is evaluating options to select the optimal long-term orientation and to determine if a rotation of the FPSO is necessary. This evaluation is ongoing amongst the partnership and the Government of Ghana, and final decisions and approvals are expected in the first half of 2017. A facility shutdown of up to 12 weeks may be required during 2017. However, significant efforts are ongoing within the partnership to reduce the duration of the shutdown.
 
A deepwater CALM buoy, anticipated to be installed in 2018, is intended to restore full offloading functionality and remove the need for the DP shuttle and storage tankers and associated operating costs. Market inquiries are currently ongoing to estimate the cost and schedule for the fabrication and installation of this buoy. This phase of work also requires approval of both the Government of Ghana and the Jubilee Unit partners.
 
The financial impact of lower Jubilee production as well as the additional expenditures associated with the damage to the turret bearing is being mitigated through a combination of the comprehensive Hull and Machinery insurance (“H&M”), procured by the operator, Tullow, on behalf of the Jubilee Unit partners, and the corporate Loss of Production Income (“LOPI”) insurance procured by Kosmos. Both LOPI and H&M insurance coverages have been confirmed by our insurers and payments are being received. The costs and reimbursements related to the turret bearing issue appear on the income statement as follows: LOPI proceeds are included as other income in the revenue section, increased operating costs and reimbursement of the same are included as oil and gas production in the costs and expenses section, and costs to convert the FPSO to a permanently spread moored facility and associated insurance reimbursements will show up as facilities insurance modifications in the costs and expenses section. Our LOPI coverage for this incident ends in May 2017.
Tweneboa, Enyenra and Ntomme (“TEN”)
 
The TEN FPSO, Prof. John Evans Atta Mills, sailed from Singapore in January 2016 and arrived in Ghanaian waters in March 2016. The 11 development wells in the initial phase of drilling were completed as of October 2016. Hook-up of the FPSO and connecting the pre-drilled wells to the vessel via the subsea infrastructure was completed in 2016. The TEN fields delivered first oil in August 2016 and averaged 14,500 Bopd in 2016. In early January 2017, the capacity of the FPSO was successfully tested at an average rate of 80,000 Bopd during a short-term flow test. However, due to certain issues with managing pressures in the Enyenra reservoir and because no new wells can be drilled until after the previously disclosed ITLOS ruling expected later in 2017, the operator has elected to manage the existing wells in a prudent manner to optimize long-term recovery over the lifetime of the field. Work continues among the project partners to consider ways to increase production. This reservoir management is not expected to negatively impact the ultimate field recovery.
Other
 
In June 2016, Kosmos Energy Ghana HC filed a Request for Arbitration with the International Chamber of Commerce against Tullow Ghana Limited in connection with a dispute arising under the DT Joint Operating Agreement. At dispute is Kosmos Energy Ghana HC’s responsibility for expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives concluded. Tullow has charged such expenditures to the DT joint account. Kosmos disputes that these expenditures are properly chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement. 
 
Mauritania and Senegal Partnership with BP
 
In December 2016, we announced a partnership with affiliates of BP p.l.c. (‘‘BP’’) in Mauritania and Senegal following a competitive farm-out process for our interests in our blocks offshore Mauritania and Senegal. We believe BP is the optimal partner to advance the gas developments in these blocks and to move forward a multi-well exploration program to fully exploit the hydrocarbon potential of the basin and test its liquids potential, currently scheduled to commence in the second quarter of 2017. In Mauritania, BP acquired a 62% participating interest in our four Mauritania licenses (C6, C8, C12 and C13). In Senegal, BP acquired a 49.99% interest in Kosmos BP Senegal Limited, our controlled
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affiliate company which holds a 65% participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks offshore Senegal. The participating interest gives effect to the completion of our exercise in December 2016 of an option to increase our equity in each contract area from 60% to 65% in exchange for carrying Timis Corporation’s paying interest share of a third well in either contract area, subject to a maximum gross cost of $120.0 million. In consideration for these transactions, Kosmos will receive $162 million in cash up front, $221 million exploration and appraisal carry, up to $533 million in a development carry and variable consideration up to $2 per barrel for up to 1 billion barrels of liquids, structured as a production royalty, subject to future liquids discovery and prevailing oil prices.
 
Greater Tortue Discovery
 
In January 2016, we announced the Guembeul-1 exploration well, located in the northern part of the Saint Louis Offshore Profond license area in Senegal, made a significant gas discovery. Located approximately three miles south of the Tortue-1 exploration well in Mauritania in approximately 8,850 feet of water, the Guembeul-1exploration well was drilled to a total depth of 17,200 feet. The well encountered 101 meters (331 feet) of net gas pay in two excellent quality reservoirs, including 56 meters (184 feet) in the Lower Cenomanian and 45 meters (148 feet) in the underlying Albian, with no water encountered.
 
In March 2016, we announced the Ahmeyim-2 appraisal well, located in Block C8 offshore Mauritania, approximately three miles northwest, and 200 meters down-dip of the basin-opening Tortue-1 discovery well in approximately 9,200 feet of water,  was drilled to a total depth of 16,700 meters. The well confirmed significant thickening of the gross reservoir sequences down-structure. The Ahmeyim-2 well encountered 78 meters (256 feet) of net gas pay in two excellent quality reservoirs, including 46 meters (151 feet) in the Lower Cenomanian and 32 meters (105 feet) in the underlying Albian.
 
We have now drilled three wells on the Greater Tortue discovery. The Guembeul-1 and Ahmeyim-2 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.
 
Mauritania
 
In June 2016, we received approval from the Ministry of Petroleum, Energy and Mines for our application to enter the second phase of the exploration period for blocks C8, C12 and C13. In conjunction with our entry into the second phase of the exploration period, we relinquished 25% of the surface area of each block. The second phase of the exploration period carries a 3D seismic requirement of 1,000 square kilometers and a one well drilling obligation for Block C13 and a one well drilling obligation for Block C12. We completed the 3D seismic obligation as well as the drilling obligation for Block C8 and the 3D seismic obligation for Block C12 during the first exploration period.
 
In October 2016, we entered into a petroleum contract covering Block C6 with the Islamic Republic of Mauritania.  Block C6 currently comprises approximately 1.1 million acres (4,300 square kilometers), with a first exploration period of four years from the effective date (October 28, 2016). The first exploration phase includes a 2,000 square kilometer 3D seismic requirement.
 
We are in the process of completing a multi-block 3D seismic survey offshore Mauritania covering approximately 5,500 square kilometers over Blocks C6, C8, C12 and C13.
 
Senegal
 
In February 2016, we completed a 3D seismic survey of approximately 4,500 square kilometers in the western portions of the Cayar Offshore Profond and Saint Louis Offshore Profond license areas.
 
The second exploration well offshore Senegal, Teranga-1, located in the Cayar Offshore Profond block approximately 40 miles northwest of Dakar in nearly 5,900 feet of water was drilled to a total depth of 15,900 feet. The well encountered 31 meters (102 feet) of net gas pay in good quality reservoir in the Lower Cenomanian objective. Well results confirm that a prolific inboard gas fairway extends approximately 125 miles from the Marsouin-1 well in Mauritania through the Greater Tortue area on the maritime boundary to the Teranga-1 well in Senegal.
 
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Suriname
 
In April 2016, we closed a farm-out agreement with Hess Suriname Exploration Limited, a wholly-owned subsidiary of the Hess Corporation (“Hess”), covering the Block 42 contract area offshore Suriname. Under the terms of the agreement, Hess acquired a one-third non-operated interest in Block 42 from both Chevron Corporation (“Chevron”) and Kosmos. As part of the agreement, Hess is funding the cost of a 6,500 square kilometer 3D seismic survey, subject to an agreed maximum limit, inclusive of Hess’ share, which is expected to be completed in the first quarter of 2017. Additionally, Hess will disproportionately fund a portion of the first exploration well in the Block 42 contract area, subject to an agreed maximum limit, inclusive of Hess’ share, contingent upon the partnership entering the next phase of the exploration period. The new participating interests are one-third to each of Kosmos, Chevron and Hess, respectively. Kosmos remains the operator.
 
In April 2016, we received an extension of Phase 1 of the Exploration Period for Block 45 offshore Suriname which now expires in September 2018. We have recently acquired an additional 340 square kilometers of 3D seismic.
 
In January 2017, we completed a 3D seismic survey of approximately 6,500 square kilometers over Block 42 and Block 45 offshore Suriname.
 
Sao Tome and Principe
 
In January and February 2016, we closed farm-in agreements with Equator, an affiliate of Oando, for Block 5 and Block 12, respectively, offshore Sao Tome and Principe, and whereby we acquired a 65% participating interest and operatorship in each block, effective as of February and March 2016, respectively. The national petroleum agency, Agencia Nacional Do Petroleo De Sao Tome E Príncipe (“ANP STP”), has a 15% and 12.5% carried interest in Block 5 and Block 12, respectively. 
 
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 a 20% participating interest to Galp in each of Blocks 5, 11 and 12 offshore Sao Tome and Principe. Based on the terms of the agreement, Galp will pay a proportionate share of Kosmos’ past costs in the form of a partial carry on the 3D seismic survey expected to begin in the first quarter of 2017.
 
Morocco
 
In May 2016, Kosmos and Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”) executed a petroleum agreement with the Office National des Hydrocarbures et des Mines ("ONHYM"), the national oil company of the Kingdom of Morocco, for the Boujdour Maritime block. The Boujdour Maritime petroleum agreement largely replaces the acreage covered by the Cap Boujdour petroleum agreement which expired in March 2016.  Under the terms of the petroleum agreement, Kosmos is the operator of the Boujdour Maritime block and has a 55% participating interest, Cairn has a 20% participating interest, and ONHYM holds a 25% carried interest in the block through the exploration period.
 
In September 2016, we entered into an agreement by which BP agreed to pay Kosmos $30 million in lieu of fulfilling their obligation to fund an exploration well and assigned its 45% participating interest in the Essaouira Offshore Block back to us, and the Moroccan government issued joint ministerial orders approving the assignment in October 2016, making it effective.   During the same month, we received an extension of the first Extension Period of exploration for the Essaouira Offshore petroleum contract, which now expires in November 2018. This extension included the modification of the minimum work program to replace an exploration well with acquisition and PSTM processing of 3,000 square-kilometers of 3D seismic and a seabed sampling survey for geochemical and heat flow analysis. The $30 million received from BP in January 2017 will be utilized to fund the modified work program.
 
The petroleum contracts for Tarhazoute Offshore and Foum Assaka Offshore expired in June 2016 and July 2016, respectively.
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Portugal
 
In January 2017, we provided to our co-venturers a notice of withdrawal from the Ameijoa, Camarao, Mexilhao and Ostra Blocks offshore Portugal.
 
Results of Operations
All of our results, as presented in the table below, represent operations from the Jubilee Field in Ghana. Certain operating results and statistics for the years ended December 31, 2016, 2015 and 2014 are included in the following table:
 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2016	 	2015	 	2014	 	
 	 	(In thousands, except per barrel data)	 	
Sales volumes:	    	 	 	    	 	 	    	 	 	 	
MBbl	 	 	6,756	 	 	8,538	 	 	8,728	 	
 	 	 	 	 	 	 	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	 	 	 	
Oil sales	 	$	310,377	 	$	446,696	 	$	855,877	 	
Average sales price per Bbl	 	 	45.94	 	 	52.32	 	 	98.06	 	
 	 	 	 	 	 	 	 	 	 	 	
Costs:	 	 	 	 	 	 	 	 	 	 	
Oil production, excluding workovers	 	$	119,758	 	$	92,994	 	$	79,648	 	
Oil production, workovers	 	 	(391)	 	 	12,342	 	 	20,474	 	
Total oil production costs	 	$	119,367	 	$	105,336	 	$	100,122	 	
 	 	 	 	 	 	 	 	 	 	 	
Depletion and depreciation	 	$	140,404	 	$	155,966	 	$	198,080	 	
 	 	 	 	 	 	 	 	 	 	 	
Average cost per Bbl:	 	 	 	 	 	 	 	 	 	 	
Oil production, excluding workovers	 	$	17.73	 	$	10.89	 	$	9.13	 	
Oil production, workovers	 	 	(0.06)	 	 	1.45	 	 	2.35	 	
Total oil production costs	 	 	17.67	 	 	12.34	 	 	11.48	 	
 	 	 	 	 	 	 	 	 	 	 	
Depletion and depreciation	 	 	20.78	 	 	18.27	 	 	22.69	 	
Oil production cost and depletion costs	 	$	38.45	 	$	30.61	 	$	34.17	 	
 
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The discussion of the results of operations and the period‑to‑period comparisons presented below analyze our historical results. The following discussion may not be indicative of future results.
Year Ended December 31, 2016 vs. 2015
 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended	 	 	 	 	
 	 	December 31,	 	Increase	 	
 	    	2016	    	2015	    	(Decrease)	 	
 	 	(In thousands)	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenue	 	$	310,377	 	$	446,696	 	$	(136,319)	 	
Gain on sale of assets	 	 	 —	 	 	24,651	 	 	(24,651)	 	
Other income	 	 	74,978	 	 	209	 	 	74,769	 	
Total revenues and other income	 	 	385,355	 	 	471,556	 	 	(86,201)	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	
Oil and gas production	 	 	119,367	 	 	105,336	 	 	14,031	 	
Facilities insurance modifications	 	 	14,961	 	 	 —	 	 	14,961	 	
Exploration expenses	 	 	202,280	 	 	156,203	 	 	46,077	 	
General and administrative	 	 	87,623	 	 	136,809	 	 	(49,186)	 	
Depletion and depreciation	 	 	140,404	 	 	155,966	 	 	(15,562)	 	
Interest and other financing costs, net	 	 	44,147	 	 	37,209	 	 	6,938	 	
Derivatives, net	 	 	48,021	 	 	(210,649)	 	 	258,670	 	
Other expenses, net	 	 	23,116	 	 	5,246	 	 	17,870	 	
Total costs and expenses	 	 	679,919	 	 	386,120	 	 	293,799	 	
Income (loss) before income taxes	 	 	(294,564)	 	 	85,436	 	 	(380,000)	 	
Income tax expense (benefit)	 	 	(10,784)	 	 	155,272	 	 	(166,056)	 	
Net loss	 	$	(283,780)	 	$	(69,836)	 	$	(213,944)	 	
Oil and gas revenue. Oil and gas revenue decreased by $136.3 million as a result of seven cargos sold during the year ended December 31, 2016 as compared to nine cargos during the year ended December 31, 2015, and as a result of a lower realized price per barrel. We lifted and sold 6,756 MBbl at an average realized price per barrel of $45.94 in 2016 and 8,538 MBbl at an average realized price per barrel of $52.32 in 2015.
Gain on sale of assets. During the year ended December 31, 2015, we closed a farm-out agreement with Chevron. As part of the transaction, we received proceeds in excess of our book basis, resulting in a gain of $24.7 million.
Other income. During the year ended December 31, 2016, we recognized $74.8 million of LOPI proceeds related to the turret bearing issue on the Jubilee FPSO.
Oil and gas production.  Oil and gas production costs increased by $14.0 million during the year ended December 31, 2016 as compared to the year ended December 31, 2015. The 2016 costs were impacted by increased costs associated with the new operating procedures related to the turret bearing issue while the 2015 costs were impacted by higher workover costs in the Jubilee Field.
Facilities insurance modifications. During the year ended December 31, 2016, we incurred $15.0 million of facilities modification costs associated with the long-term solution to convert the FPSO to a permanently spread moored facility which we expect to substantially recover from our insurance policy.
Exploration expenses. Exploration expenses increased by $46.1 million during the year ended December 31, 2016, as compared to the year ended December 31, 2015. The increase is primarily a result of $107.7 million of stacked rig costs in 2016 and an increase of $31.5 million in seismic and geological and geophysical costs partially mitigated by $94.0 million of unsuccessful well costs in 2015 primarily for the Western Sahara CB-1 exploration well.
General and administrative. General and administrative costs decreased by $49.2 million during the year ended December 31, 2016, as compared to the year ended December 31, 2015. The decrease is primarily a result of a decrease in non-cash stock-based compensation and effective cost control.
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Depletion and depreciation. Depletion and depreciation decreased $15.6 million during the year ended December 31, 2016, as compared with the year ended December 31, 2015, primarily as a result of depletion recognized related to the sale of seven cargos of oil during 2016, as compared to nine cargos during the prior year.
Interest and other financing costs, net. Interest expense increased by $6.9 million during the year ended December 31, 2016, as compared to the year ended December 31, 2015. Higher gross interest costs on a larger debt balance and a full year of interest in 2016 on the 2021 Senior Notes totaling $14.2 million were partially offset by $7.4 million of higher capitalized interest during the current year as compared to the prior year.
Derivatives, net. During the years ended December 31, 2016 and 2015, we recorded a loss of $48.0 million and a gain of $210.6 million, respectively, on our outstanding hedge positions. The loss recorded in 2016 was a result of increases in the forward oil price curve and the gain recorded in 2015 was a result of decreases in the forward oil price curve.
Other expenses, net. Other expenses, net increased by $17.9 million during the year ended December 31, 2016, as compared to the year ended December 31, 2015, primarily as a result of a $14.9 million inventory write off and $11.3 million in disputed charges and related costs offset by $4.0 million of insurance proceeds related to the damaged riser.
Income tax expense (benefit). The Company’s effective tax rates for the years ended December 31, 2016 and 2015 were a tax benefit of 4% and a tax expense of 182%, respectively. The effective tax rates for the periods presented were impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such expenses or losses. The effective tax rate in Ghana is impacted by non-deductible expenditures associated with the damage to the turret bearing which we expect to recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax. Income tax expense decreased by $166.1 million during the year ended December 31, 2016, as compared with the year ended December 31, 2015, primarily as a result of lower revenue in Ghana.
Year Ended December 31, 2015 vs. 2014
 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended	 	 	 	 	
 	 	December 31,	 	Increase	 	
 	    	2015	    	2014	    	(Decrease)	 	
 	 	(In thousands)	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenue	 	$	446,696	 	$	855,877	 	$	(409,181)	 	
Gain on sale of assets	 	 	24,651	 	 	23,769	 	 	882	 	
Other income	 	 	209	 	 	3,092	 	 	(2,883)	 	
Total revenues and other income	 	 	471,556	 	 	882,738	 	 	(411,182)	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	
Oil and gas production	 	 	105,336	 	 	100,122	 	 	5,214	 	
Exploration expenses	 	 	156,203	 	 	93,519	 	 	62,684	 	
General and administrative	 	 	136,809	 	 	135,231	 	 	1,578	 	
Depletion and depreciation	 	 	155,966	 	 	198,080	 	 	(42,114)	 	
Interest and other financing costs, net	 	 	37,209	 	 	45,548	 	 	(8,339)	 	
Derivatives, net	 	 	(210,649)	 	 	(281,853)	 	 	71,204	 	
Restructuring charges	 	 	 —	 	 	11,742	 	 	(11,742)	 	
Other expenses, net	 	 	5,246	 	 	2,081	 	 	3,165	 	
Total costs and expenses	 	 	386,120	 	 	304,470	 	 	81,650	 	
Income before income taxes	 	 	85,436	 	 	578,268	 	 	(492,832)	 	
Income tax expense	 	 	155,272	 	 	298,898	 	 	(143,626)	 	
Net income (loss)	 	$	(69,836)	 	$	279,370	 	$	(349,206)	 	
Oil and gas revenue. Oil and gas revenue decreased by $409.2 million during the year ended December 31, 2015 as compared to the year ended December 31, 2014, as a result of a significantly lower realized price per barrel and a slight 
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decrease in sales volumes. We lifted and sold 8,538 MBbl at an average realized price per barrel of $52.32 in 2015 and 8,728 MBbl at an average realized price per barrel of $98.06 in 2014.
Oil and gas production. Oil and gas production costs increased by $5.2 million during the year ended December 31, 2015 as compared to the year ended December 31, 2014 primarily as a result of an increase in routine operating expenses, including $2.8 million related to repairs to the gas compressor and costs to remove the damaged water injection riser, partially mitigated by a reduction in well workover costs.
Exploration expenses. Exploration expenses increased by $62.7 million during the year ended December 31, 2015, as compared to the year ended December 31, 2014. The increase is primarily a result of $86.8 million of unsuccessful well costs for the Western Sahara CB-1 exploration well in 2015 partially mitigated by a decrease in seismic costs of $28.6 million.
Depletion and depreciation. Depletion and depreciation decreased $42.1 million during the year ended December 31, 2015, as compared with the year ended December 31, 2014, primarily as a result of a lower depletion rate in 2015 as a result of an increase in our proved reserves associated with the Jubilee Field.
Interest and other financing costs, net. Interest expense decreased by $8.3 million during the year ended December 31, 2015, as compared to the year ended December 31, 2014, primarily as a result of higher gross interest costs driven by a larger debt balance offset by higher capitalized interest during the year ended December 31, 2015, as compared to the year ended December 31, 2014.
Derivatives, net.  During the years ended December 31, 2015 and 2014, we recorded a gain of $210.6 million and $281.9 million, respectively, on our outstanding hedge positions. The gains recorded were a result of decreases in the forward oil price curve during the respective periods.
Restructuring charges. During the year ended December 31, 2015, we had no restructuring charges; however, during the year ended December 31, 2014, we recognized $11.7 million in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization, which includes $5.0 million of non‑cash expense related to awards granted under our LTIP.
Income tax expense. The Company’s effective tax rates for the years ended December 31, 2015 and 2014 were 182% and 52%, respectively. The effective tax rates for the periods presented were impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such expenses or losses. Income tax expense decreased by $143.6 million during the year ended December 31, 2015, as compared with the year ended December 31, 2014, primarily as a result of lower revenue in Ghana.
Liquidity and Capital Resources
We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to exploring for and developing oil and natural gas resources along the Atlantic Margins. We have historically met our funding requirements through cash flows generated from our operating activities and obtained additional funding from issuances of equity and debt. In relation to cash flow generated from our operating activities, if we are unable to continuously export associated natural gas in large quantities, which causes potential production restraints in the Jubilee Field, then the Company’s cash flows from operations will be adversely affected. We have also experienced mechanical issues, including failures of our water injection facilities and gas compressor on the Jubilee FPSO, as well as the current turret bearing issue. This equipment downtime negatively impacted oil production and we are in the process of repairing the current mechanical issues and implementing a long-term solution for the turret issue.
While we are presently in a strong financial position, a future decline in oil prices, if prolonged, could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. It could also impact the borrowing base available under the Facility or the related debt covenants. Commodity prices are volatile and future prices cannot be accurately predicted. We maintain a hedging program to partially mitigate the price volatility. Our investment decisions are based on longer‑term commodity prices based on the long‑term nature of our projects and development plans. Current commodity prices, our hedging program and our current liquidity position support our capital program for 2017.
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As such, our 2017 capital budget is based on our development plans for Ghana and our exploration and appraisal program for 2017.
Our future financial condition and liquidity can be impacted by, among other factors, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the reliability of our oil and gas production facilities, our ability to continuously export oil and gas, our ability to secure and maintain partners and their alignment with respect to capital plans, the actual cost of exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.
In September 2016, following the lender’s semi-annual redetermination, the borrowing base under our Facility was increased from the March 2016 redetermination to $1.467 billion (effective October 1, 2016). The borrowing base calculation includes value related to the Jubilee and TEN fields.
Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents for the years ended December 31, 2016, 2015 and 2014
 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended	 	
 	 	December 31,	 	
 	    	2016	    	2015	    	2014	 	
 	 	(In thousands)	 	
Sources of cash, cash equivalents and restricted cash:	 	 	 	 	 	 	 	 	 	 	
Net cash provided by operating activities	 	$	52,077	 	$	440,779	 	$	443,586	 	
Net proceeds from issuance of senior secured notes	 	 	 —	 	 	206,774	 	 	294,000	 	
Borrowings under long-term debt	 	 	450,000	 	 	100,000	 	 	 —	 	
Proceeds on sale of assets	 	 	210	 	 	28,692	 	 	58,315	 	
 	 	 	502,287	 	 	776,245	 	 	795,901	 	
Uses of cash, cash equivalents and restricted cash:	 	 	 	 	 	 	 	 	 	 	
Oil and gas assets	 	 	535,975	 	 	823,642	 	 	424,535	 	
Other property	 	 	1,998	 	 	1,483	 	 	2,383	 	
Payments on long-term debt	 	 	 —	 	 	200,000	 	 	400,000	 	
Purchase of treasury stock	 	 	1,981	 	 	18,110	 	 	11,096	 	
Deferred financing costs	 	 	 —	 	 	9,030	 	 	22,088	 	
 	 	 	539,954	 	 	1,052,265	 	 	860,102	 	
Decrease in cash, cash equivalents and restricted cash	 	$	(37,667)	 	$	(276,020)	 	$	(64,201)	 	
Net cash provided by operating activities.  Net cash provided by operating activities in 2016 was $52.1 million compared with net cash provided by operating activities of $440.8 million in 2015 and $443.6 million in 2014, respectively. The decrease in cash provided by operating activities in the year ended December 31, 2016 when compared to the same period in 2015 was primarily a result of a decrease in results from operations driven by lower barrels sold related to the turret bearing issue and lower realized revenue per barrel sold. The decrease in cash provided by operating activities in 2015 when compared to 2014 was primarily as a result of a decrease in results from operations driven by lower realized revenue per barrel sold mitigated by a positive change in working capital items.
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The following table presents our liquidity and financial position as of December 31, 2016:
 	 	 	 	 	
 	    	December 31, 2016	 	 	 	
 	 	(In thousands)	 	 	 	
Cash and cash equivalents	 	$	194,057	 	 	 	
Restricted cash	 	 	79,138	 	 	 	
Senior Notes at par	 	 	525,000	 	 	 	
Drawings under the Facility	 	 	850,000	 	 	 	
Net debt	 	$	1,101,805	 	 	 	
 	 	 	 	 	 	 	
Availability under the Facility	 	$	616,900	 	 	 	
Availability under the Corporate Revolver	 	$	400,000	 	 	 	
Available borrowings plus cash and cash equivalents	 	$	1,210,957	 	 	 	
Capital Expenditures and Investments
We expect to incur capital costs as we:
 	·	 	fund asset integrity projects at Jubilee;	

 	·	 	execute exploration and appraisal activities in our Senegal and Mauritania license areas; and	

 	·	 	acquire and analyze seismic, perform new ventures and manage our rig activities.	
We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells we plan to drill, our participating interests in our prospects including disproportionate payment amounts, the costs involved in developing or participating in the development of a prospect, the timing of third‑party projects, our ability to utilize our available drilling rig capacity, the availability of suitable equipment and qualified personnel and our cash flows from operations. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if market conditions deteriorate; or one or more of our assumptions proves to be incorrect or if we choose to expand our acquisition, exploration, appraisal, development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could result in dilution to our shareholders. The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations.
 
2017 Capital Program
We estimate we will spend approximately $175 million of capital, net of carry amounts related to the Mauritania and Senegal transactions with BP, for the year ending December 31, 2017. This capital expenditure budget consists of:
 	·	 	approximately $75 million for developmental related expenditures offshore Ghana, largely focused on Jubilee asset integrity; and	

 	·	 	approximately $100 million related to seismic acquisition and new ventures.	
In addition, we expect to receive approximately $200 million from BP related to our Mauritania and Senegal transactions, which we believe will be offset with approximately $200 million of rig costs incurred with the termination and subsidy of the Atwood Achiever drilling rig.
This positions us to achieve our objectives and invest counter-cyclically while maintaining a strong balance sheet. The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our drilling results among other factors. We plan to resume our previously suspended drilling program during the second quarter of 2017. Our future financial condition and liquidity will be impacted by, among other factors, our level of
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production of oil and the prices we receive from the sale of oil, our ability to effectively hedge future production volumes, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, our partners’ alignment with respect to capital plans, and the actual cost of exploration, appraisal and development of our oil and natural gas assets.
Significant Sources of Capital
Facility
In March 2014, we amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities.
In September 2016, following the lender’s semi-annual redetermination, the borrowing base under our Facility was increased from the March 2016 redetermination to $1.467 billion (effective October 1, 2016). The borrowing base calculation includes value related to the Jubilee and TEN fields.
As part of the debt refinancing in March 2014, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and existing unamortized debt issuance costs attributable to those participants were expensed. As a result, we recorded a $2.9 million loss on the extinguishment of debt for the year ended December 31, 2014. As of December 31, 2016, we have $30.3 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility, including certain costs related to the amendment.
As of December 31, 2016, borrowings under the Facility totaled $850.0 million and the undrawn availability under the Facility was $616.9 million.
Interest is the aggregate of the applicable margin (3.25% to 4.50%, depending on the length of time that has passed from the date the Facility was entered into); LIBOR; and mandatory cost (if any, as defined in the Facility). Interest is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six‑month intervals after the first day of the interest period). We pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. Commitment fees are equal to 40% per annum of the then‑applicable respective margin when a commitment is available for utilization and, equal to 20% per annum of the then‑applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835—Interest, which requires interest expense to be recognized using the effective interest method. As part of the March 2014 amendment, the Facility’s estimated effective interest rate was changed and, accordingly, we adjusted our estimate of deferred interest previously recorded during prior years by $4.5 million, which was recorded as a reduction to interest expense for the year ended December 31, 2014.
The Facility provides a revolving‑credit and letter of credit facility. The availability period for the revolving‑credit facility, as amended in March 2014 expires on March 31, 2018; however the Facility has a revolving‑credit sublimit, which will be the lesser of $500.0 million and the total available facility at that time, that will be available for drawing until the date falling one month prior to the final maturity date. The letter of credit sublimit expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2018, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2021. As of December 31, 2016, we had no letters of credit issued under the Facility.
We have the right to cancel all the undrawn commitments under the Facility. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined each year on March 31 and September 30. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in Ghana.
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If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. The Facility contains customary cross default provisions.
We were in compliance with the financial covenants contained in the Facility as of September 30, 2016 (the most recent assessment date), which requires the maintenance of:
 	·	 	the field life cover ratio (as defined in the glossary), not less than 1.30x; and	

 	·	 	the loan life cover ratio (as defined in the glossary), not less than 1.10x; and	

 	·	 	the debt cover ratio (as defined in the glossary), not more than 3.5x; and	

 	·	 	the interest cover ratio (as defined in the glossary), not less than 2.25x.	
Corporate Revolver
In November 2012, we secured a Corporate Revolver from a number of financial institutions which, as amended in June 2015, has an availability of $400.0 million. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration, appraisal and development programs.
As of December 31, 2016, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400.0 million.
Interest is the aggregate of the applicable margin (6.0%), LIBOR and mandatory cost (if any, as defined in the Corporate Revolver). Interest is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six‑month intervals after the first day of the interest period). We pay commitment fees on the undrawn portion of the total commitments. Commitment fees, as amended in June 2015, for the lenders are equal to 30% per annum of the respective margin when a commitment is available for utilization.
The Corporate Revolver, as amended in June 2015, expires on November 23, 2018. The available amount is not subject to borrowing base constraints. We have the right to cancel all the undrawn commitments under the Corporate Revolver. We are required to repay certain amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default exists under the Corporate Revolver, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us. The Corporate Revolver contains customary cross default provisions.
We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2016 (the most recent assessment date), which requires the maintenance of:
 	·	 	the debt cover ratio (as defined in the glossary), not more than 3.5x; and	

 	·	 	the interest cover ratio (as defined in the glossary), not less than 2.25x.	
The U.S. and many foreign economies continue to experience uncertainty driven by varying macroeconomic conditions. Although some of these economies have shown signs of improvement, macroeconomic recovery remains uneven. Uncertainty in the macroeconomic environment and associated global economic conditions have resulted in extreme volatility in credit, equity, and foreign currency markets, including the European sovereign debt markets and volatility in various other markets. If any of the financial institutions within our Facility or Corporate Revolver are unable to perform on their commitments, our liquidity could be impacted. We actively monitor all of the financial institutions participating in our Facility and Corporate Revolver. None of the financial institutions have indicated to us that they may be unable to perform on their commitments. In addition, we periodically review our banking and financing relationships, considering the stability of the institutions and other aspects of the relationships. Based on our monitoring activities, we currently believe our banks will be able to perform on their commitments.
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Revolving Letter of Credit Facility
In July 2013, we entered into a revolving letter of credit facility agreement (“LC Facility”). The size of the LC Facility is $75.0 million, as amended in July 2015, with additional commitments up to $50.0 million being available if the existing lender increases its commitments or if commitments from new financial institutions are added. The LC Facility provides that we shall maintain cash collateral in an amount equal to at least 75% of all outstanding letters of credit under the LC Facility, provided that during the period of any breach of certain financial covenants, the required cash collateral amount shall increase to 100%.
In July 2016, we amended and restated the LC Facility, extending the maturity date to July 2019. The LC Facility size remains at $75.0 million, with additional commitments up to $50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. Other amendments included increasing the margin from 0.5% to 0.8% per annum on amounts outstanding, adding a commitment fee payable quarterly in arrears at an annual rate equal to 0.65% on the available commitment amount and providing for issuance fees to be payable to the lender per new issuance of a letter of credit. We may voluntarily cancel any commitments available under the LC Facility at any time. As of December 31, 2016, there were nine letters of credit totaling $72.8 million under the LC Facility. The LC Facility contains customary cross default provisions.
In February 2017, we exercised an option to increase the size of the LC Facility to $125 million to facilitate the issuance of additional letters of credit.
7.875% Senior Secured Notes due 2021
During August 2014, the Company issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.
During April 2015, we issued an additional $225.0 million Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued.
The Senior Notes mature on August 1, 2021. Interest is payable semi‑annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries (the “Guarantees”).
Redemption and Repurchase.  At any time prior to August 1, 2017 and subject to certain conditions, the Company may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of Senior Notes issued under the indenture dated August 1, 2014 related to the Senior Notes (the “Indenture”) at a redemption price of 107.875%, plus accrued and unpaid interest, with the cash proceeds of certain eligible equity offerings. Additionally, at any time prior to August 1, 2017, the Company may, on any one or more occasions, redeem all or a part of the Senior Notes at a redemption price equal to 100%, plus any accrued and unpaid interest, and a make‑whole premium. On or after August 1, 2017, the Company may redeem all or a part of the Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:
 	 	 	 	
Year	    	Percentage	 	
On or after August 1, 2017, but before August 1, 2018	 	103.9	%	
On or after August 1, 2018, but before August 1, 2019	 	102.0	%	
On or after August 1, 2019 and thereafter	 	100.0	%	
 
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We may also redeem the Senior Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the Senior Notes at a price equal to the principal amount of the Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted.
Upon the occurrence of a change of control triggering event as defined under the Indenture, the Company will be required to make an offer to repurchase the Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.
If we sell assets, under certain circumstances outlined in the Indenture, we will be required to use the net proceeds to make an offer to purchase the Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.
Covenants.  The Indenture restricts our ability and the ability of our restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of our subsidiaries to make dividends or other payments to us, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing.
Collateral.  The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all currently outstanding shares, additional shares, dividends or other distributions paid in respect of such shares or any other property derived from such shares, in each case held by us in relation to the Company’s direct subsidiary, Kosmos Energy Holdings, pursuant to the terms of the Charge over Shares of Kosmos Energy Holdings dated November 23, 2012, as amended and restated on March 14, 2014, between the Company and BNP Paribas as Security and Intercreditor Agent. The Senior Notes share  pari passu  in the benefit of such equitable charge based on the respective amounts of the obligations under the Indenture and the amount of obligations under the Corporate Revolver. The Guarantees are not secured.
Contractual Obligations
The following table summarizes by period the payments due for our estimated contractual obligations as of December 31, 2016:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Payments Due By Year(5)	 	
 	 	Total	 	2017	 	2018	 	2019	 	2020	 	2021	 	Thereafter	 	
 	 	(In thousands)	 	
Principal debt repayments(1)	 	$	1,375,000	 	$	 —	    	$	 —	    	$	268,823	 	$	395,166	    	$	711,011	    	$	 —	 	
Interest payments on long-term debt(2)	 	 	383,066	 	 	92,490	 	 	94,029	 	 	83,567	 	 	67,771	 	 	45,209	 	 	 —	 	
Operating leases(3)	 	 	11,171	 	 	4,190	 	 	3,820	 	 	3,161	 	 	 —	 	 	 —	 	 	 —	 	
Atwood Achiever drilling rig contract(4)	 	 	229,482	 	 	229,482	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	

 	(1)	 	Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the estimated future available borrowing base as of December 31, 2016. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of December 31, 2016, there were no borrowings under the Corporate Revolver.	

 	(2)	 	Based on outstanding borrowings as noted in (1) above and the LIBOR yield curves at the reporting date and commitment fees related to the Facility and Corporate Revolver and interest on the Senior Notes.	

 	(3)	 	Primarily relates to corporate office and foreign office leases.	
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 	(4)	 	In January 2017, KEV exercised its option to cancel the fourth year and revert to the original day rate of approximately $0.6 million per day and original agreement end date of November 2017. Commitments calculated using the original day rate of $0.6 million effective February 1, 2017, excluding applicable taxes. The commitments also include a $48.1 million rate recovery payment equal to the difference between the original day rate and the amended day rate.	

 	(5)	 	Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments and seismic obligations, in our petroleum contracts.	
We currently have a commitment to drill two exploration wells in Mauritania. In Mauritania, our partner is obligated to fund our share of the cost of the exploration wells subject to their maximum $221 million cumulative exploration and appraisal carry covering both our Mauritania and Senegal blocks. Additionally, in Sao Tome and Principe we have 2D and 3D seismic requirements of 1,200 square kilometers and 4,000 square kilometers, respectively, and we have 3D seismic requirements in Mauritania and Western Sahara of 3,000 square kilometers and 5,000 square kilometers, respectively.
The following table presents maturities by expected debt maturity dates, the weighted average interest rates expected to be paid on the Facility given current contractual terms and market conditions, and the debt’s estimated fair value. Weighted‑average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not take into account amortization of deferred financing costs.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Asset	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(Liability)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Fair Value at	 	
 	 	Years Ending December 31,	 	December 31,	 	
 	    	2017	 	2018	 	2019	 	2020	 	2021	    	Thereafter	    	2016	 	
 	 	(In thousands, except percentages)	 	
Fixed rate debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior Notes	 	$	 —	 	$	 —	 	$	 —	 	$	 —	 	$	525,000	 	$	 —	 	$	(528,938)	 	
Fixed interest rate	 	 	7.88	%  	 	7.88	%  	 	7.88	%  	 	7.88	%  	 	7.88	%	 	 —	%  	 	 	 	
Variable rate debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Facility(1)	 	$	 —	 	$	 —	 	$	268,823	 	$	395,166	 	$	186,011	 	$	 —	 	$	(850,000)	 	
Weighted average interest rate(2)	 	 	4.21	%  	 	5.17	%  	 	5.68	%  	 	6.43	%  	 	6.79	%	 	 —	%  	 	 	 	
Capped interest rate swaps:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notional debt amount	 	$	200,000	 	$	200,000	 	$	 —	 	$	 —	 	$	 —	 	$	 —	 	$	53	 	
Cap	 	 	3.00	%  	 	3.00	%  	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	 	 	
Average fixed rate payable(3)	 	 	1.23	%  	 	1.23	%  	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	 	 	
Variable rate receivable(4)	 	 	0.97	%  	 	1.55	%  	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	 	 	

 	(1)	 	The amounts included in the table represent principal maturities only. The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of December 31, 2016. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of December 31, 2016, there were no borrowings under the Corporate Revolver.	

 	(2)	 	Based on outstanding borrowings as noted in (1) above and the LIBOR yield curves plus applicable margin at the reporting date. Excludes commitment fees related to the Facility and Corporate Revolver.	

 	(3)	 	We expect to pay the fixed rate if 1-month LIBOR is below the cap, and pay the market rate less the spread between the cap and the fixed rate if LIBOR is above the cap, net of the capped interest rate swaps.	

 	(4)	 	Based on implied forward rates in the yield curve at the reporting date.	
Off‑Balance Sheet Arrangements
We may enter into off‑balance sheet arrangements and transactions that can give rise to material off‑balance sheet obligations. As of December 31, 2016, our material off‑balance sheet arrangements and transactions include operating leases and undrawn letters of credit. There are no other transactions, arrangements, or other relationships with
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unconsolidated entities or other persons that are reasonably likely to materially affect Kosmos’ liquidity or availability of or requirements for capital resources.
Critical Accounting Policies
This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities as of the date the financial statements are available to be issued. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates. Our significant accounting policies are detailed in “Item 8. Financial Statements and Supplementary Data—Note 2—Accounting Policies.” We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management.
Revenue Recognition.  We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold based on the provisional sales prices. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2016 and 2015, we had no oil and gas imbalances recorded in our consolidated financial statements.
Our oil and gas revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge for accounting purposes, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale occurs.
Exploration and Development Costs.  We follow the successful efforts method of accounting for our oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are charged to expense as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift crude oil and natural gas to the surface are expensed.
Receivables.  Our receivables consist of joint interest billings, oil sales and other receivables. For our oil sales receivable, we require a letter of credit to be posted to secure the outstanding receivable. Receivables from joint interest owners are stated at amounts due, net of any allowances for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things.
Income Taxes.  We account for income taxes as required by the ASC 740—Income Taxes (“ASC 740”). We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal, state and international tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to realize or utilize our deferred tax assets. If realization is not more likely than not, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in no benefit for the deferred tax amounts. As of December 31, 2016 and 2015, we have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. If our estimates and judgments regarding our ability to realize our deferred tax
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assets change, the benefits associated with those deferred tax assets may increase or decrease in the period our estimates and judgments change. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.
ASC 740 provides a more‑likely‑than‑not standard in evaluating whether a valuation allowance is necessary after weighing all of the available evidence. When evaluating the need for a valuation allowance, we consider all available positive and negative evidence, including the following:
 	·	 	the status of our operations in the particular taxing jurisdiction including whether we have commenced production from a commercial discovery;	

 	·	 	whether a commercial discovery has resulted in significant proved reserves that have been independently verified;	

 	·	 	the amounts and history of taxable income or losses in a particular jurisdiction;	

 	·	 	projections of future income, including the sensitivity of such projections to changes in production volumes and prices;	

 	·	 	the existence, or lack thereof, of statutory limitations on the period that net operating losses may be carried forward in a jurisdiction; and	

 	·	 	the creation and timing of future income associated with the turnaround of deferred tax liabilities in excess of deferred tax assets.	
Derivative Instruments and Hedging Activities.  We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of three‑way collars, put options, call options and swaps. We also use interest rate derivative contracts to mitigate our exposure to interest rate fluctuations related to our long‑term debt. Our derivative financial instruments are recorded on the balance sheet as either assets or a liabilities measured at fair value. We do not apply hedge accounting to our oil derivative contracts. Effective June 1, 2010, we discontinued hedge accounting on our interest rate swap contracts and accordingly the changes in the fair value of the instruments are recognized in earnings in the period of change. The effective portions of the discontinued hedges as of May 31, 2010, were included in accumulated other comprehensive income or loss (“AOCI”) in the equity section of the accompanying consolidated balance sheets, and were transferred to earnings when the hedged transactions settled.
Estimates of Proved Oil and Natural Gas Reserves.  Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the SEC and the FASB. The accuracy of these reserve estimates is a function of:
 	·	 	the engineering and geological interpretation of available data;	

 	·	 	estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost;	

 	·	 	the accuracy of various mandated economic assumptions; and	

 	·	 	the judgments of the persons preparing the estimates.	
Asset Retirement Obligations.  We account for asset retirement obligations as required by the ASC 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement
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obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that obligation shall be recognized at the asset’s acquisition date as if that obligation were incurred on that date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion and depreciation in the consolidated statement of operations. Estimating the future restoration and removal costs requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Additionally, asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is made to the oil and gas property balance.
Impairment of Long‑Lived Assets.  We review our long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value. The carrying amount of a long‑lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long‑lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to us are recorded at the lower of carrying amount or fair value less cost to sell.
We believe the assumptions used in our undiscounted cash flow analysis to test for impairment are appropriate and result in a reasonable estimate of future cash flows. The undiscounted cash flows from the analysis exceeded the carrying amount of our long-lived assets. The most significant assumptions are the pricing and production estimates used in undiscounted cash flow analysis. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation. In order to evaluate the sensitivity of the assumptions, we assumed a hypothetical reduction in our production profile and lower pricing during the early years which still showed no impairment. If we experience further declines in oil pricing, increases in our estimated future expenditures or a decrease in our estimated production profile our long-lived assets could be at risk for impairment.  
New Accounting Pronouncements
See “Item 8. Financial Statements and Supplementary Data—Note 2—Accounting Policies” for a discussion of recent accounting pronouncements.  
Item 7A.  Qualitative and Quantitative Disclosures About Market Risk
The primary objective of the following information is to provide forward‑looking quantitative and qualitative information about our potential exposure to market risks. The term “market risks” as it relates to our currently anticipated transactions refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward‑looking information provides indicators of how we view and manage ongoing market risk exposures. We enter into market‑risk sensitive instruments for purposes other than to speculate.
We manage market and counterparty credit risk in accordance with our policies. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8. Financial Statements and Supplementary Data—Note 2—Accounting Policies, Note 8—Derivative Financial Instruments
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and Note 9—Fair Value Measurements” for a description of the accounting procedures we follow relative to our derivative financial instruments.
The following table reconciles the changes that occurred in fair values of our open derivative contracts during the year ended December 31, 2016:
 	 	 	 	 	 	 	 	 	 	 	
 	 	Derivative Contracts Assets (Liabilities)	 	
 	    	Commodities	    	Interest Rates	    	Total	 	
 	 	(In thousands)	 	
Fair value of contracts outstanding as of December 31, 2015	 	$	237,641	 	$	(496)	 	$	237,145	 	
Changes in contract fair value	 	 	(45,483)	 	 	(1,076)	 	 	(46,559)	 	
Contract maturities	 	 	(190,520)	 	 	1,625	 	 	(188,895)	 	
Fair value of contracts outstanding as of December 31, 2016	 	$	1,638	 	$	53	 	$	1,691	 	
 
Commodity Price Risk
The Company’s revenues, earnings, cash flows, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, which have historically been very volatile. Our oil sales are indexed against Dated Brent crude. Dated Brent prices in 2016 ranged between $25.99 and $55.41.
Commodity Derivative Instruments
We enter into various oil derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future oil production. These contracts currently consist of three‑way collars, put options, call options and swaps. In regards to our obligations under our various commodity derivative instruments, if our production does not exceed our existing hedged positions, our exposure to our commodity derivative instruments would increase.
Commodity Price Sensitivity
The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of December 31, 2016:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Weighted Average Dated Brent Price per Bbl	 	Asset (Liability)	 	
 	    	 	    	 	    	Deferred	    	 	 	    	 	 	    	 	 	    	 	 	    	 	 	 	Fair Value at	 	
 	 	 	 	 	 	Premium	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	December 31,	 	
Term	 	Type of Contract	 	MBbl	 	Payable	 	Swap	 	Sold Put	 	Floor	 	Ceiling	 	Call	 	2016(2)	 	
2017:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January — December	 	Swap with puts/calls	 	2,000	 	$	2.13	 	$	72.50	 	$	55.00	 	$	 —	 	$	 —	 	$	90.00	 	$	18,916	 	
January — December	 	Swap with puts	 	2,000	 	 	 —	 	 	64.95	 	 	50.00	 	 	 —	 	 	 —	 	 	 —	 	 	10,903	 	
January — December	 	Three-way collars	 	3,002	 	 	2.29	 	 	 —	 	 	30.00	 	 	45.00	 	 	57.50	 	 	 —	 	 	(17,579)	 	
January — December	 	Sold calls(1)	 	2,000	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	85.00	 	 	 —	 	 	(117)	 	
2018:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January — December	 	Three-way collars	 	2,913	 	$	0.74	 	$	 —	 	$	41.57	 	$	56.57	 	$	65.90	 	$	 —	 	$	(1,041)	 	
January — December	 	Sold calls(1)	 	2,000	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	65.00	 	 	 —	 	 	(7,701)	 	
2019:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January — December	 	Sold calls(1)	 	913	 	$	 —	 	$	 —	 	$	 —	 	$	 —	 	$	80.00	 	$	 —	 	$	(1,712)	 	

 	(1)	 	Represents call option contracts sold to counterparties to enhance other derivative positions.	

 	(2)	 	Fair values are based on the average forward Dated Brent oil prices on December 31, 2016 which by year are: 2017—$57.71, 2018—$58.05 and 2019—$57.68. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on February 21, 2017 market quotes by year are: 2017—$56.21 2018—$55.51 and 2019—$54.66.	
In February 2017, we entered into three-way collar contracts for 1.0 MMBbl from January 2018 through December 2018 with a floor price of $50.00 per barrel, a ceiling price of $62.00 per barrel and a purchased call price of $70.00 per barrel. The contracts are indexed to Dated Brent prices and have a weighted average deferred premium payable of $2.32 per barrel.
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At December 31, 2016, our open commodity derivative instruments were in a net asset position of $1.7 million. As of December 31, 2016, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre‑tax earnings by approximately $49.6 million. Similarly, a hypothetical 10% price decrease would increase future pre‑tax earnings by approximately $41.1 million.
Interest Rate Derivative Instruments
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations” for specific information regarding the terms of our interest rate derivative instruments that are sensitive to changes in interest rates.
Interest Rate Sensitivity
At December 31, 2016, we had indebtedness outstanding under the Facility of $850.0 million, of which $650.0 million bore interest at floating rates after consideration of our fixed rate interest rate hedges. The interest rate on this indebtedness as of December 31, 2016 was approximately 3.9%. If LIBOR increased 10% at this level of floating rate debt, we would pay an additional $0.4 million in interest expense per year on the Facility. We paid commitment fees on the $616.9 million of undrawn availability and $33.1 million of unavailable commitments under the Facility and on the $400.0 million of undrawn availability under the Corporate Revolver during 2016, which are not subject to changes in interest rates.
As of December 31, 2016, the fair market value of our interest rate swaps was a net liability of approximately $52.9 thousand. If LIBOR increased by 10%, we estimate it would have a negligible impact on the fair market value of our interest rate swaps.
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Item 8.  Financial Statements and Supplementary Data
 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 	 	
 	Page	
Consolidated Financial Statements of Kosmos Energy Ltd.:	 	
Reports of Independent Registered Public Accounting Firm 	92 	
Consolidated Balance Sheets as of December 31, 2016 and 2015 	94 	
Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014 	95 	
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 2014 	96 	
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2016, 2015 and 2014 	97 	
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014 	98 	
Notes to Consolidated Financial Statements 	99 	
Supplemental Oil and Gas Data (Unaudited) 	125 	
Supplemental Quarterly Financial Information (Unaudited) 	130 	

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Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Kosmos Energy Ltd.
We have audited the accompanying consolidated balance sheets of Kosmos Energy Ltd. as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedules included at Item 15(a). These financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Kosmos Energy Ltd. at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the financial information set forth therein.
As discussed in Note 2 to the consolidated financial statements, Kosmos Energy Ltd. adopted ASU 2016-09, Improvements to Employee Share-based Payment Accounting.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Kosmos Energy Ltd.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 27, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Dallas, Texas
February 27, 2017
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Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Kosmos Energy Ltd.
We have audited Kosmos Energy Ltd.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Kosmos Energy Ltd.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting appearing in Item 9A. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Kosmos Energy Ltd. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Kosmos Energy Ltd. as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2016 of Kosmos Energy Ltd. and our report dated February 27, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Dallas, Texas
February 27, 2017
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KOSMOS ENERGY LTD.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2016	 	2015	 	
Assets	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	194,057	 	$	275,004	 	
Restricted cash	 	 	24,506	 	 	28,533	 	
Receivables:	 	 	 	 	 	 	 	
Joint interest billings, net	 	 	63,249	 	 	67,200	 	
Oil sales	 	 	54,195	 	 	35,950	 	
Other	 	 	25,893	 	 	34,882	 	
Inventories	 	 	74,380	 	 	85,173	 	
Prepaid expenses and other	 	 	7,209	 	 	24,766	 	
Derivatives	 	 	31,698	 	 	182,640	 	
Total current assets	 	 	475,187	 	 	734,148	 	
 	 	 	 	 	 	 	 	
Property and equipment:	 	 	 	 	 	 	 	
Oil and gas properties, net	 	 	2,700,889	 	 	2,314,226	 	
Other property, net	 	 	8,003	 	 	8,613	 	
Property and equipment, net	 	 	2,708,892	 	 	2,322,839	 	
 	 	 	 	 	 	 	 	
Other assets:	 	 	 	 	 	 	 	
Restricted cash	 	 	54,632	 	 	7,325	 	
Long-term receivables - joint interest billings	 	 	45,663	 	 	37,687	 	
Deferred financing costs, net of accumulated amortization of $11,213 and $8,475 at December 31, 2016 and December 31, 2015, respectively	 	 	5,248	 	 	7,986	 	
Long-term deferred tax assets	 	 	37,827	 	 	33,209	 	
Derivatives	 	 	3,808	 	 	59,856	 	
Other	 	 	10,208	 	 	 —	 	
Total assets 	 	$	3,341,465	 	$	3,203,050	 	
 	 	 	 	 	 	 	 	
Liabilities and shareholders’ equity	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	
Accounts payable	 	$	220,627	 	$	295,689	 	
Accrued liabilities	 	 	129,706	 	 	159,897	 	
Derivatives	 	 	19,692	 	 	1,155	 	
Total current liabilities	 	 	370,025	 	 	456,741	 	
 	 	 	 	 	 	 	 	
Long-term liabilities:	 	 	 	 	 	 	 	
Long-term debt	 	 	1,321,874	 	 	860,878	 	
Derivatives	 	 	14,123	 	 	4,196	 	
Asset retirement obligations	 	 	63,574	 	 	43,938	 	
Deferred tax liabilities	 	 	482,221	 	 	502,189	 	
Other long-term liabilities	 	 	8,449	 	 	9,595	 	
Total long-term liabilities	 	 	1,890,241	 	 	1,420,796	 	
 	 	 	 	 	 	 	 	
Shareholders’ equity:	 	 	 	 	 	 	 	
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2016 and December 31, 2015	 	 	 —	 	 	 —	 	
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 395,859,061 and 393,902,643 issued at December 31, 2016 and 2015, respectively	 	 	3,959	 	 	3,939	 	
Additional paid-in capital	 	 	1,975,247	 	 	1,933,189	 	
Accumulated deficit	 	 	(850,410)	 	 	(564,686)	 	
Treasury stock, at cost, 9,101,395 and 8,812,054 shares at December 31, 2016 and 2015, respectively	 	 	(47,597)	 	 	(46,929)	 	
Total shareholders’ equity	 	 	1,081,199	 	 	1,325,513	 	
Total liabilities and shareholders’ equity 	 	$	3,341,465	 	$	3,203,050	 	

See accompanying notes.
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KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Years Ended December 31,	 	
 	    	 	2016	    	2015	    	2014	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenue	 	 	$	310,377	 	$	446,696	 	$	855,877	 	
Gain on sale of assets	 	 	 	 —	 	 	24,651	 	 	23,769	 	
Other income	 	 	 	74,978	 	 	209	 	 	3,092	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues and other income	 	 	 	385,355	 	 	471,556	 	 	882,738	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas production	 	 	 	119,367	 	 	105,336	 	 	100,122	 	
Facilities insurance modifications	 	 	 	14,961	 	 	 —	 	 	 —	 	
Exploration expenses	 	 	 	202,280	 	 	156,203	 	 	93,519	 	
General and administrative	 	 	 	87,623	 	 	136,809	 	 	135,231	 	
Depletion and depreciation	 	 	 	140,404	 	 	155,966	 	 	198,080	 	
Interest and other financing costs, net	 	 	 	44,147	 	 	37,209	 	 	45,548	 	
Derivatives, net	 	 	 	48,021	 	 	(210,649)	 	 	(281,853)	 	
Restructuring charges	 	 	 	 —	 	 	 —	 	 	11,742	 	
Other expenses, net	 	 	 	23,116	 	 	5,246	 	 	2,081	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	 	679,919	 	 	386,120	 	 	304,470	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) before income taxes	 	 	 	(294,564)	 	 	85,436	 	 	578,268	 	
Income tax expense (benefit)	 	 	 	(10,784)	 	 	155,272	 	 	298,898	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	$	(283,780)	 	$	(69,836)	 	$	279,370	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss) per share:	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	$	(0.74)	 	$	(0.18)	 	$	0.73	 	
Diluted	 	 	$	(0.74)	 	$	(0.18)	 	$	0.72	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average number of shares used to compute net income (loss) per share:	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	 	385,402	 	 	382,610	 	 	379,195	 	
Diluted	 	 	 	385,402	 	 	382,610	 	 	386,119	 	
See accompanying notes.
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KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Years Ended December 31,	 	
 	    	 	2016	 	2015	 	2014	 	
Net income (loss)	 	 	$	(283,780)	 	$	(69,836)	 	$	279,370	 	
Other comprehensive loss:	 	 	 	 	 	 	 	 	 	 	 	
Reclassification adjustments for derivative gains included in net income (loss)	 	 	 	 —	 	 	(767)	 	 	(1,391)	 	
Other comprehensive loss	 	 	 	 —	 	 	(767)	 	 	(1,391)	 	
Comprehensive income (loss)	 	 	$	(283,780)	 	$	(70,603)	 	$	277,979	 	

See accompanying notes.
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KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(In thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	Accumulated	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Additional	 	 	 	 	Other	 	 	 	 	 	 	 	
 	 	Common Shares	 	Paid-in	 	Accumulated	 	Comprehensive	 	Treasury	 	 	 	 	
 	    	Shares	    	 Amount 	    	Capital	    	Deficit	    	Income	    	Stock	    	Total	 	
Balance as of December 31, 2013	 	391,974	 	$	3,920	 	$	1,781,535	 	$	(774,220)	 	$	2,158	 	$	(21,058)	 	$	992,335	 	
Equity-based compensation	 	 —	 	 	 —	 	 	79,741	 	 	 —	 	 	 —	 	 	 —	 	 	79,741	 	
Derivatives, net	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(1,391)	 	 	 —	 	 	(1,391)	 	
Restricted stock awards and units	 	469	 	 	4	 	 	(4)	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	
Restricted stock forfeitures	 	 —	 	 	 —	 	 	2	 	 	 —	 	 	 —	 	 	(2)	 	 	 —	 	
Purchase of treasury stock	 	 —	 	 	 —	 	 	(1,084)	 	 	 —	 	 	 —	 	 	(10,012)	 	 	(11,096)	 	
Net income	 	 —	 	 	 —	 	 	 —	 	 	279,370	 	 	 —	 	 	 —	 	 	279,370	 	
Balance as of December 31, 2014	 	392,443	 	 	3,924	 	 	1,860,190	 	 	(494,850)	 	 	767	 	 	(31,072)	 	 	1,338,959	 	
Equity-based compensation	 	 —	 	 	 —	 	 	75,267	 	 	 —	 	 	 —	 	 	 —	 	 	75,267	 	
Derivatives, net	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(767)	 	 	 —	 	 	(767)	 	
Restricted stock awards and units	 	1,460	 	 	15	 	 	(15)	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	
Restricted stock forfeitures	 	 —	 	 	 —	 	 	16	 	 	 —	 	 	 —	 	 	(16)	 	 	 —	 	
Purchase of treasury stock	 	 —	 	 	 —	 	 	(2,269)	 	 	 —	 	 	 —	 	 	(15,841)	 	 	(18,110)	 	
Net loss	 	 —	 	 	 —	 	 	 —	 	 	(69,836)	 	 	 —	 	 	 —	 	 	(69,836)	 	
Balance as of December 31, 2015	 	393,903	 	 	3,939	 	 	1,933,189	 	 	(564,686)	 	 	 —	 	 	(46,929)	 	$	1,325,513	 	
Equity-based compensation	 	 —	 	 	 —	 	 	43,391	 	 	(1,944)	 	 	 —	 	 	 —	 	 	41,447	 	
Restricted stock awards and units	 	1,956	 	 	20	 	 	(20)	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	
Restricted stock forfeitures	 	 —	 	 	 —	 	 	2	 	 	 —	 	 	 —	 	 	(2)	 	 	 —	 	
Purchase of treasury stock	 	 —	 	 	 —	 	 	(1,315)	 	 	 —	 	 	 —	 	 	(666)	 	 	(1,981)	 	
Net loss	 	 —	 	 	 —	 	 	 —	 	 	(283,780)	 	 	 —	 	 	 —	 	 	(283,780)	 	
Balance as of December 31, 2016	 	395,859	 	$	3,959	 	$	1,975,247	 	$	(850,410)	 	$	 —	 	$	(47,597)	 	$	1,081,199	 	

See accompanying notes.
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KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

 	 	 	Years Ended December 31,	 	
 	    	 	2016	    	2015	    	2014	 	
Operating activities	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	$	(283,780)	 	$	(69,836)	 	$	279,370	 	
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	 	 	 	 	 	 	 	 	 	 	 	
Depletion, depreciation and amortization	 	 	 	150,608	 	 	166,290	 	 	208,628	 	
Deferred income taxes	 	 	 	(23,561)	 	 	110,786	 	 	216,409	 	
Unsuccessful well costs	 	 	 	6,079	 	 	94,910	 	 	1,105	 	
Change in fair value of derivatives	 	 	 	46,559	 	 	(210,957)	 	 	(271,298)	 	
Cash settlements on derivatives, net (including $187.9 million, $225.5 million and $18.4 million on commodity hedges during 2016, 2015 and 2014	 	 	 	188,895	 	 	224,741	 	 	4,460	 	
Equity-based compensation	 	 	 	40,084	 	 	75,057	 	 	79,541	 	
Gain on sale of assets	 	 	 	 —	 	 	(24,651)	 	 	(23,769)	 	
Loss on extinguishment of debt	 	 	 	 —	 	 	165	 	 	2,898	 	
Other	 	 	 	13,355	 	 	7,875	 	 	(3,875)	 	
Changes in assets and liabilities:	 	 	 	 	 	 	 	 	 	 	 	
(Increase) decrease in receivables	 	 	 	(20,558)	 	 	2,209	 	 	(156,192)	 	
Increase in inventories	 	 	 	(4,107)	 	 	(29,855)	 	 	(8,100)	 	
Decrease in prepaid expenses and other	 	 	 	17,557	 	 	512	 	 	1,732	 	
Increase (decrease) in accounts payable	 	 	 	(75,487)	 	 	111,289	 	 	90,228	 	
Increase (decrease) in accrued liabilities	 	 	 	(3,567)	 	 	(17,756)	 	 	22,449	 	
Net cash provided by operating activities	 	 	 	52,077	 	 	440,779	 	 	443,586	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Investing activities	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas assets	 	 	 	(535,975)	 	 	(823,642)	 	 	(424,535)	 	
Other property	 	 	 	(1,998)	 	 	(1,483)	 	 	(2,383)	 	
Proceeds on sale of assets	 	 	 	210	 	 	28,692	 	 	58,315	 	
Net cash used in investing activities	 	 	 	(537,763)	 	 	(796,433)	 	 	(368,603)	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Financing activities	 	 	 	 	 	 	 	 	 	 	 	
Borrowings under long-term debt	 	 	 	450,000	 	 	100,000	 	 	 —	 	
Payments on long-term debt	 	 	 	 —	 	 	(200,000)	 	 	(400,000)	 	
Net proceeds from issuance of senior secured notes	 	 	 	 —	 	 	206,774	 	 	294,000	 	
Purchase of treasury stock	 	 	 	(1,981)	 	 	(18,110)	 	 	(11,096)	 	
Deferred financing costs	 	 	 	 —	 	 	(9,030)	 	 	(22,088)	 	
Net cash provided by (used in) financing activities	 	 	 	448,019	 	 	79,634	 	 	(139,184)	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Net decrease in cash, cash equivalents and restricted cash	 	 	 	(37,667)	 	 	(276,020)	 	 	(64,201)	 	
Cash, cash equivalents and restricted cash at beginning of period	 	 	 	310,862	 	 	586,882	 	 	651,083	 	
Cash, cash equivalents and restricted cash at end of period	 	 	$	273,195	 	$	310,862	 	$	586,882	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Supplemental cash flow information	 	 	 	 	 	 	 	 	 	 	 	
Cash paid for:	 	 	 	 	 	 	 	 	 	 	 	
Interest	 	 	$	27,860	 	$	33,315	 	$	23,182	 	
Income taxes	 	 	$	13,997	 	$	35,857	 	$	108,068	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Non-cash activity:	 	 	 	 	 	 	 	 	 	 	 	
Conversion of joint interest billings receivable to long-term note receivable	 	 	$	9,814	 	$	 —	 	$	 —	 	

See accompanying notes.
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KOSMOS ENERGY LTD.
Notes to Consolidated Financial Statements
 
1. Organization
Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise.
Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margins. Our assets include existing production and development projects offshore Ghana, large discoveries and significant further hydrocarbon exploration potential offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Sao Tome and Principe, Suriname, Morocco and Western Sahara. Kosmos is listed on the New York Stock Exchange and is traded under the ticker symbol KOS.
We have one reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long‑lived assets and all of our product sales are related to production located offshore Ghana.
2. Accounting Policies
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Kosmos Energy Ltd. and its wholly owned subsidiaries. All intercompany transactions have been eliminated.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.
Reclassifications
Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no material impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows, except as disclosed related to the adoption of recent accounting pronouncements.
Cash, Cash Equivalents and Restricted Cash
 	 	 	 	 	 	 	 	 	 	
 	 	December 31,	
 	 	2016	 	2015	 	2014	
 	 	(In thousands)	
Cash and cash equivalents	 	$	194,057	 	$	275,004	 	$	554,831	
Restricted cash - current	 	 	24,506	 	 	28,533	 	 	15,926	
Restricted cash - long-term	 	 	54,632	 	 	7,325	 	 	16,125	
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	 	$	273,195	 	$	310,862	 	$	586,882	
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Cash and cash equivalents includes demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.
In accordance with our commercial debt facility (the “Facility”), we are required to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six‑month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver or the Facility, whichever is greater. As of December 31, 2016 and 2015, we had $24.5 million and $24.4 million, respectively, in current restricted cash to meet this requirement.
In addition, in accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of December 31, 2016 and 2015, we had zero and $4.1 million, respectively, of short-term restricted cash and $54.6 million and $7.3 million, respectively, of long‑term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts.
Receivables
Our receivables consist of joint interest billings, oil sales and other receivables. For our oil sales receivable, we require a letter of credit to be posted to secure the outstanding receivable. Receivables from joint interest owners are stated at amounts due, net of any allowances for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things. We had an allowance for doubtful accounts of $0.6 million and zero in current joint interest billings receivables as of December 31, 2016 and 2015, respectively.
Inventories
Inventories consisted of $68.1 million and $84.4 million of materials and supplies and $6.3 million and $0.8 million of hydrocarbons as of December 31, 2016 and 2015, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded a write down of $14.9 million during the year ended December 31, 2016 for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows.
Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.
Exploration and Development Costs
The Company follows the successful efforts method of accounting for its oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are expensed as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed and recorded in exploration expense on the consolidated statement of operations. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed as oil and gas production expense.
The Company evaluates unproved property periodically for impairment. The impairment assessment considers results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential future reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize an impairment loss at that time.
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Depletion, Depreciation and Amortization
Proved properties and support equipment and facilities are depleted using the unit‑of‑production method based on estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in a discovery of proved reserves and development costs are amortized using the unit‑of‑production method based on estimated proved developed oil and natural gas reserves for the related field.
Depreciation and amortization of other property is computed using the straight-line method over the assets’ estimated useful lives (not to exceed the lease term for leasehold improvements), ranging from one to eight years.
 	 	 	 	 	 	
 	    	Years	 	
 	 	Depreciated	 	
Leasehold improvements	 	1	to	8	 	
Office furniture, fixtures and computer equipment	 	3	to	7	 	
Vehicles	 	 	5	 	 	

Amortization of deferred financing costs is computed using the straight‑line method over the life of the related debt.
Capitalized Interest
Interest costs from external borrowings are capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is depleted on the unit‑of‑production method in the same manner as the underlying assets.
Asset Retirement Obligations
The Company accounts for asset retirement obligations as required by ASC 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion and depreciation in the consolidated statement of operations.
Impairment of Long‑lived Assets
The Company reviews its long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable, or at least annually. ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value. The carrying amount of a long‑lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long‑lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell.
We believe the assumptions used in our undiscounted cash flow analysis to test for impairment are appropriate and result in a reasonable estimate of future cash flows. The undiscounted cash flows from the analysis exceeded the carrying amount of our long-lived assets. The most significant assumptions are the pricing and production estimates used in undiscounted cash flow analysis. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation. In order to evaluate the sensitivity of the assumptions, we assumed a hypothetical reduction in our production profile which still showed no impairment. If we experience declines in oil pricing, increases
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in our estimated future expenditures or a decrease in our estimated production profile our long-lived assets could be at risk for impairment.  
Derivative Instruments and Hedging Activities
We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of three‑way collars, put options, call options and swaps. We also use interest rate derivative contracts to mitigate our exposure to interest rate fluctuations related to our long‑term debt. Our derivative financial instruments are recorded on the balance sheet as either assets or liabilities and are measured at fair value. We do not apply hedge accounting to our oil derivative contracts. Effective June 1, 2010, we discontinued hedge accounting on our interest rate swap contracts. Therefore, from that date forward, the changes in the fair value of the instruments were recognized in earnings during the period of change. The effective portions of the discontinued hedges as of May 31, 2010, were included in accumulated other comprehensive income or loss (“AOCI”) in the equity section of the accompanying consolidated balance sheets, and were transferred to earnings when the hedged transactions settled. As of December 31, 2015 all instruments previously designated as hedges have settled and there is no balance remaining in AOCI. See Note 8—Derivative Financial Instruments.
Estimates of Proved Oil and Natural Gas Reserves
Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”). The accuracy of these reserve estimates is a function of:
 	·	 	the engineering and geological interpretation of available data;	

 	·	 	estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost;	

 	·	 	the accuracy of various mandated economic assumptions; and	

 	·	 	the judgments of the persons preparing the estimates.	
Revenue Recognition
We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold based on the provisional sales prices. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2016 and 2015, we had no oil and gas imbalances recorded in our consolidated financial statements.
Our oil and gas revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale.
Equity‑based Compensation
For equity‑based compensation awards, compensation expense is recognized in the Company’s financial statements over the awards’ vesting periods based on their grant date fair value. The Company utilizes (i) the closing stock
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price on the date of grant to determine the fair value of service vesting restricted stock awards and restricted stock units and (ii) a Monte Carlo simulation to determine the fair value of restricted stock awards and restricted stock units with a combination of market and service vesting criteria. Forfeitures are recognized in the period in which they occur.
Restructuring Charges
The Company accounts for restructuring charges in accordance with ASC 420-Exit or Disposal Cost Obligations. Under these standards, the costs associated with restructuring charges are recorded during the period in which the liability is incurred. During the year ended December 31, 2014, we recognized $11.7 million in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization, which includes $5.0 million of accelerated non-cash expense related to awards previously granted under our Long-Term Incentive Plan (the “LTIP”).
Treasury Stock
We record treasury stock purchases at cost. The majority of our treasury stock purchases are from our employees that surrendered shares to the Company to satisfy their minimum statutory tax withholding requirements and were not part of a formal stock repurchase plan. The remainder of our treasury stock is forfeited restricted stock awards granted under our long‑term incentive plan.
Income Taxes
The Company accounts for income taxes as required by ASC 740—Income Taxes. Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.
We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be sustained upon examination by the tax authorities, based on the technical merits of the position. Accordingly, we measure tax benefits from such positions based on the most likely outcome to be realized.
Foreign Currency Translation
The U.S. dollar is the functional currency for all of the Company’s material foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are not significant, and as such, the effect of exchange rate changes is not material to any reporting period.
Concentration of Credit Risk
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 readily 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.
Recent Accounting Standards
Recently Adopted
In July 2015, the FASB issued ASU 2015-11, “Simplifying the Measurement of Inventory.” ASU 2015-11 changes the measurement principle for entities that do not measure inventory using the last-in, first-out (LIFO) or retail inventory method from the lower of cost or market to lower of cost and net realizable value. The ASU also eliminates the requirement for these entities to consider replacement cost or net realizable value less an approximately normal profit margin when measuring inventory. The standard requires prospective application upon adoption. The Company has elected to early adopt ASU 2015-11 during the first quarter of 2016. The adoption of this standard did not have a material impact
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on the Company’s consolidated financial statements.
The Company adopted ASU 2016-09, “Improvements to Employee Share-based Payment Accounting” during the year using an effective date of January 1, 2016. The change in accounting for forfeitures associated with share-based payment transactions was adopted using the modified retrospective method and resulted in a $1.9 million increase to opening accumulated deficit, a $3.0 million increase to opening additional paid-in capital and a $1.1 million increase to opening long-term deferred tax assets in the consolidated balance sheets. The changes in accounting for the recognition of excess tax benefits and tax shortfalls were adopted prospectively.
In August 2016, the FASB issued ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” ASU 2016-15 clarifies current GAAP or provides specific guidance on eight cash flow classification issues to reduce current and potential future diversity in practice. The Company has elected to early adopt this standard using the retrospective method as prescribed by the standard. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.
 
In November 2016, the FASB issued ASU 2016-18, “Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” ASU 2016-18 requires that a statement of cash flows explain the change during the period in total of cash, cash equivalents, and amounts generally described as restricted cash and restricted cash equivalents. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company has elected to early adopt this standard using the retrospective method as prescribed by the standard. The consolidated statements of cash flows have been reclassified to conform with the presentation required by ASU 2016-18, and the changes in restricted cash are now presented as part of the change in total cash, cash equivalents and restricted cash rather than as changes in investing activities as previously presented.
 
Not Yet Adopted
In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. As of December 31, 2016, the Company does not expect the adoption of this standard to have a material impact to our revenue recognition based on our existing contracts with customers. 
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The new leasing standard requires the modified retrospective adoption method. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements.
In October 2016, the FASB issued ASU 2016-16, “Intra-Entity Transfers of Assets Other Than Inventory.” ASU 2016-16 requires the company to recognize income tax consequences, if any, on intercompany asset transfers, other than inventory, when the transfer occurs. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements.
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3. Acquisitions and Divestitures
2016 Transactions
 
In January and February 2016, we closed farm-in agreements with Equator Exploration Limited (“Equator”), an affiliate of Oando Energy Resources, for Block 5 and Block 12 offshore Sao Tome and Principe. As a result of subsequent farm-outs we currently have a 45% participating interest and operatorship in each block. The national petroleum agency, ANP STP, has a 15% and 12.5% carried interest in Block 5 and Block 12, respectively.
 
In April 2016, we closed a farm-out agreement with Hess Suriname Exploration Limited, a wholly-owned subsidiary of the Hess Corporation (“Hess”), covering the Block 42 contract area offshore Suriname. Under the terms of the agreement, Hess acquired a one-third non-operated interest in Block 42 from both Chevron and Kosmos. As part of the agreement, Hess is funding the cost of acquiring and processing a 6,500 square kilometer 3D seismic survey, subject to a maximum spend. Additionally, Hess will disproportionately fund a portion of the first exploration well in the Block 42 contract area, subject to a maximum spend, contingent upon the partnership entering the next phase of the exploration period. The new participating interests are one-third to each of Kosmos, Chevron and Hess, respectively. Kosmos remains 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.
 
In May 2016, Kosmos and Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”) executed a petroleum agreement with the Office National des Hydrocarbures et des Mines ("ONHYM"), the national oil company of the Kingdom of Morocco, for the Boujdour Maritime block. The Boujdour Maritime petroleum agreement largely replaces the acreage covered by the Cap Boujdour petroleum agreement which expired in March 2016. Under the terms of the petroleum agreement, Kosmos is the operator of the Boujdour Maritime block and has a 55% participating interest, Cairn has a 20% participating interest, and ONHYM holds a 25% carried interest in the block through the exploration period.
 
In September 2016, we entered into an agreement by which BP agreed to pay Kosmos $30 million in lieu of drilling an exploration well and assigned its 45% participating interest in the Essaouira Offshore Block back to us, and the Moroccan government issued joint ministerial orders approving the assignment in October 2016, making it effective. After giving effect to the assignment, our participating interest is 75% in the Essaouria Offshore block and we remain the operator. The $30 million payment was received from BP in January 2017.
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, Societe Mauritanienne des Hydrocarbures et de Patrimoine Minier (“SMHPM”), currently has a 10% carried participating interest during the exploration period. Block C6 currently comprises approximately 1.1 million acres (4,300 square kilometers), with a first exploration period of four years from the effective date (October 28, 2016). The first exploration phase includes a 2,000 square kilometer 3D seismic requirement.
In December 2016, Kosmos closed a farm-out agreement with a subsidiary of Galp Energia SGPS S.A. (“Galp”) to farm-out a 20% non-operated stake of the Company’s interest in Blocks 5, 11, and 12 offshore Sao Tome and Principe. Based on the terms of the agreement, Galp will pay a proportionate share of Kosmos’ past costs in the form of a partial carry on the 3D seismic survey which began in the first quarter of 2017.
In December 2016, we announced a partnership with affiliates of BP p.l.c. (‘‘BP’’) in Mauritania and Senegal following a competitive farm-out process for our interests in our blocks offshore Mauritania and Senegal. In Mauritania, BP acquired a 62% participating interest in our four Mauritania licenses (C6, C8, C12 and C13). In Senegal, BP acquired a 49.99% interest in Kosmos BP Senegal Limited, our controlled affiliate company which holds a 65% participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks offshore Senegal. The participating interest gives effect to the completion of our exercise in December 2016 of an option to increase our equity in each contract area from 60% to 65% in exchange for carrying Timis Corporation’s paying interest share of a third well in either contract area, subject to a maximum gross cost of $120.0 million. In consideration for these transactions, Kosmos will receive $162 million in cash up front, $221 million exploration and appraisal carry, up to $533 million in a development carry and variable consideration up to $2 per barrel for up to 1 billion barrels of liquids, structured as a production royalty, subject
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to future liquids discovery and prevailing oil prices. The effective date of these transactions is July 1, 2016, with BP paying interim costs from the effective date to the closing date.
2015 Transactions
In March 2015, we closed a farm-in agreement with Repsol Exploracion, S.A. (“Repsol”), acquiring a non-operated interest in the Camarao, Ameijoa, Mexilhao and Ostra blocks in the Peniche Basin offshore Portugal. As part of the agreement, we reimbursed a portion of Repsol’s previously incurred exploration costs, as well as partially carried Repsol’s share of the costs of a planned 3D seismic program. After giving effect to the farm-in agreement, our participating interest is 31% in each of the blocks.
In March 2015, we closed a farm‑out agreement with Chevron Corporation (“Chevron”) covering the C8, C12 and C13 petroleum contracts offshore Mauritania. As partial consideration for the farm-out, Chevron paid a disproportionate share of the costs of one exploration well, the Marsouin-1 exploration well, as well as its proportionate share of certain previously incurred exploration costs. The final allocation resulted in sales proceeds of $28.7 million, which exceeded our book basis in the assets, resulting in a $24.7 million gain on the transaction. As a further component of the consideration for the farm-out, Chevron was required to make an election by February 1, 2016, to either farm-in to the Tortue-1 exploration well by paying a disproportionate share of the costs incurred in drilling of the well or, alternatively elect to not farm-in to the Tortue-1 exploration well and pay a disproportionate share of the costs of a second contingent exploration or appraisal well in the contract areas, subject to maximum expenditure caps. Chevron failed to make this mandatory election by the required date. Consequently, pursuant to the terms of the farm-out agreement, Chevron has withdrawn from our Mauritania blocks. Chevron’s 30% non-operated participating interest was reassigned to us.
In September 2015, we notified the government of Ireland and our partners that we are withdrawing from all of our blocks offshore Ireland. These blocks were acquired during 2013.
In October 2015, we closed a sale and purchase agreement with ERHC Energy EEZ, LDA, whereby we acquired an 85% participating interest and operatorship in Block 11 offshore Sao Tome and Principe. The National Petroleum Agency, Agencia Nacional Do Petroleo De Sao Tome E Príncipe (“ANP STP”), has a 15% carried interest.
In November 2015, we closed a farm-in agreement with Galp Energia Sao Tome E Principe, Unipessoal, LDA (“Galp”), a wholly owned subsidiary of Petrogal, S.A. to acquire a 45% non-operated participating interest in Block 6 offshore Sao Tome and Principe.
2014 Transactions
In the first quarter of 2014, we closed three farm-out agreements with BP Exploration (Morocco) Limited, a wholly owned subsidiary of BP plc (“BP”), covering our three blocks in the Agadir Basin, offshore Morocco. The sales proceeds of the farm-outs were $56.9 million. The proceeds on the sale of the interests exceeded our book basis in the assets, resulting in a $23.8 million gain on the transaction. The petroleum agreements for Tarhazoute Offshore and Foum Assaka Offshore expired in June 2016 and July 2016, respectively.
 
In the first quarter of 2014, we closed a farm-out agreement with Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”), covering the Cap Boujdour Offshore block, offshore Western Sahara. Cairn paid $1.5 million for their share of costs incurred from the effective date of the farm-out agreement through the closing date, which was recorded as a reduction in our basis. The Cap Boujdour petroleum agreement expired in March 2016.
In August 2014, we entered into a farm-in agreement with Timis Corporation Limited (“Timis”), whereby we acquired a 60% participating interest and operatorship, covering the Cayar Offshore Profond and Saint Louis Offshore Profond blocks offshore Senegal. As part of the agreement, we carried the full costs of a 3D seismic program. Additionally, we carried the full costs of the Guembeul-1 exploration well and will fund Timis’ share of the costs of a second contingent exploration well in either contract area, subject to a maximum gross cost per well of $120.0 million, should Kosmos elect to drill such well. In December 2016, we exercised our option to increase our equity to 65% in exchange for carrying the full cost of a third contingent exploration or appraisal well, subject to a maximum gross cost of $120.0 million.
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4. Joint Interest Billings
The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur.
In 2014, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners of its request for the contractor group to pay GNPC’s 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners will be reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues under the terms of the Deepwater Tano (“DT”) petroleum contract. As of December 31, 2016 and 2015, the joint interest billing receivables due from GNPC for the TEN fields development costs were $44.0 million and $35.3 million, respectively, which were classified as long-term on the consolidated balance sheets.
5. Property and Equipment
Property and equipment is stated at cost and consisted of the following:
 	 	 	 	 	 	 	 	 	
 	    	 	December 31,	 	
 	 	 	2016	 	2015	 	
 	 	 	(In thousands)	 	
Oil and gas properties:	 	 	 	 	 	 	 	 	
Proved properties	 	 	$	1,385,331	 	$	1,337,215	 	
Unproved properties	 	 	 	919,056	 	 	593,510	 	
Support equipment and facilities	 	 	 	1,386,448	 	 	1,241,943	 	
Total oil and gas properties	 	 	 	3,690,835	 	 	3,172,668	 	
Accumulated depletion	 	 	 	(989,946)	 	 	(858,442)	 	
Oil and gas properties, net	 	 	 	2,700,889	 	 	2,314,226	 	
 	 	 	 	 	 	 	 	 	
Other property	 	 	 	37,186	 	 	34,807	 	
Accumulated depreciation	 	 	 	(29,183)	 	 	(26,194)	 	
Other property, net	 	 	 	8,003	 	 	8,613	 	
 	 	 	 	 	 	 	 	 	
Property and equipment, net	 	 	$	2,708,892	 	$	2,322,839	 	
 
We recorded depletion expense of $131.5 million, $146.6 million and $188.3 million for the years ended December 31, 2016, 2015 and 2014, respectively.
 
6. Suspended Well Costs
The Company capitalizes exploratory well costs as unproved properties within oil and gas properties until a determination is made that the well has either found proved reserves or is impaired. If proved reserves are found, the capitalized exploratory well costs are reclassified to proved properties. Well costs are charged to exploration expense if the exploratory well is determined to be impaired.
The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the years ended December 31, 2016, 2015 and 2014. The table excludes $2.4 million, $70.3 million and $1.1 million in costs that were capitalized and subsequently expensed during the same year for the years ended December 31, 2016, 2015
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and 2014, respectively. During 2014, the exploratory well costs associated with the TEN fields were reclassified to proved property.
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Years Ended December 31,	 	
 	    	 	2016	 	2015	 	2014	 	
 	 	 	(In thousands)	 	
Beginning balance 	 	 	$	426,881	 	$	226,714	 	$	376,166	 	
Additions to capitalized exploratory well costs pending the determination of proved reserves 	 	 	 	307,582	 	 	223,542	 	 	71,039	 	
Reclassification due to determination of proved reserves 	 	 	 	 —	 	 	 —	 	 	(220,491)	 	
Capitalized exploratory well costs charged to expense 	 	 	 	 —	 	 	(23,375)	 	 	 —	 	
Ending balance 	 	 	$	734,463	 	$	426,881	 	$	226,714	 	

The following table provides aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling:
 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Years Ended December 31,	 	
 	    	 	2016	    	2015	    	2014	    	
 	 	 	(In thousands, except well counts)	 	
Exploratory well costs capitalized for a period of one year or less	 	 	$	279,809	 	$	199,486	 	$	16,814	 	
Exploratory well costs capitalized for a period of one to two years	 	 	 	244,804	 	 	17,702	 	 	40,865	 	
Exploratory well costs capitalized for a period of three to seven years	 	 	 	209,850	 	 	209,693	 	 	169,035	 	
Ending balance	 	 	$	734,463	 	$	426,881	 	$	226,714	 	
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	 	 	 	5	 	 	3	 	 	5	 	
 
As of December 31, 2016, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to Mahogany, Teak (formerly Teak‑1 and Teak‑2) and Akasa discoveries in the West Cape Three Points (“WCTP”) Block and the Wawa discovery in the DT Block, which are all located offshore Ghana, the Greater Tortue discovery which crosses the Mauritania and Senegal maritime border and the Marsouin discovery in Block C8 offshore Mauritania.
Mahogany and Teak Discoveries — In November 2015, we signed the Jubilee Field Unit Expansion Agreement with our partners to allow for the development of the Mahogany and Teak discoveries through the Jubilee FPSO and infrastructure. The expansion of the Jubilee Unit becomes effective upon approval by Ghana’s Ministry of Energy of the Greater Jubilee Full Field Development Plan (“GJFFDP”), which was submitted to the government of Ghana in December 2015. The GJFFDP encompasses future development of the Jubilee Field, in addition to future development of the Mahogany and Teak discoveries, which were declared commercial during 2015. We are currently in discussions with the government of Ghana concerning the GJFFDP. Upon approval of the GJFFDP by the Ministry of Energy, the Jubilee Unit will be expanded to include the Mahogany and Teak discoveries and revenues and expenses associated with these discoveries will be at the Jubilee Unit interests. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow after approval of the GJFFDP by Ghana’s Ministry of Energy.
Akasa Discovery — We are currently in discussions with the government of Ghana regarding additional technical studies and evaluation that we want to conduct before we are able to make a determination regarding commerciality of the discovery. If we determine the discovery to be commercial, a declaration of commerciality would be provided and a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP petroleum contract. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block, including the Akasa Discovery, to Tullow after approval of the GJFFDP by Ghana’s Ministry of Energy.
Wawa Discovery — In February 2016, we requested the Ghana Ministry of Energy to approve the enlargement of the areal extent of the TEN fields and production area to capture the resource accumulation located in the Wawa Discovery Area for a potential future integrated development with the TEN fields. In April 2016, the Ghana Ministry of Energy approved our request to enlarge the TEN development and production area subject to continued subsurface and development concept evaluation, along with the requirement to integrate the Wawa Discovery into the TEN PoD.
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Greater Tortue Discovery — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania which encountered hydrocarbon pay. Two additional wells have been drilled. Following additional evaluation, a decision regarding commerciality will be made.
Marsouin Discovery — In November 2015, we completed the Marsouin-1 exploration well in the northern part of Block C8 offshore Mauritania which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality will be made.
7. Debt
 	 	 	 	 	 	 	 	 	
 	 	 	December 31,	 	
 	   	 	2016	   	2015	 	
 	 	 	(In thousands)	 	
Outstanding debt principal balances:	 	 	 	 	 	 	 	 	
Facility	 	 	$	850,000	 	$	400,000	 	
Senior Notes	 	 	 	525,000	 	 	525,000	 	
Total	 	 	 	1,375,000	 	 	925,000	 	
Unamortized deferred financing costs and discounts(1)	 	 	 	(53,126)	 	 	(64,122)	 	
Long-term debt 	 	 	$	1,321,874	 	$	860,878	 	

 	(1)	 	Includes $30.3 million and $37.5 million of unamortized deferred financing costs related to the Facility and $22.8 million and $26.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of December 31, 2016 and December 31, 2015, respectively.	
Facility
In March 2014, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of the debt refinancing in March 2014, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and existing unamortized debt issuance costs attributable to those participants were expensed. As a result, we recorded a $2.9 million loss on the extinguishment of debt. As of December 31, 2016, we have $30.3 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility, including certain costs related to the amendment.
In September 2016, following the lender’s semi-annual redetermination, the borrowing base under our Facility was $1.467 billion (effective October 1, 2016). The borrowing base calculation includes value related to the Jubilee and TEN fields. 
As of December 31, 2016, borrowings under the Facility totaled $850.0 million and the undrawn availability under the Facility was $616.9 million. Interest is the aggregate of the applicable margin (3.25% to 4.50%, depending on the length of time that has passed from the date the Facility was entered into); LIBOR; and mandatory cost (if any, as defined in the Facility). Interest is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). We pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. Commitment fees are equal to 40% per annum of the then-applicable respective margin when a commitment is available for utilization and, equal to 20% per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835—Interest, which requires interest expense to be recognized using the effective interest method. We determined the effective interest rate based on the estimated level of borrowings under the Facility. As part of the March 2014 amendment, the Facility’s estimated effective interest rate was changed and, accordingly, we adjusted our estimate of deferred interest previously recorded during prior years by $4.5 million, which was recorded as a reduction to interest expense for the year ended December 31, 2014.
The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving- credit facility, as amended in March 2014 expires on March 31, 2018, however the Facility has a revolving-credit sublimit, which will be the lesser of $500.0 million and the total available facility at that time, that will be available for drawing
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until the date falling one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2018, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2021. As of December 31, 2016, we had no letters of credit issued under the Facility.
Kosmos has the right to cancel all the undrawn commitments under the Facility. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined each year on March 31 and September 30.  The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in Ghana.
If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. The Facility contains customary cross default provisions.
We were in compliance with the financial covenants contained in the Facility as of the September 30, 2016 (the most recent assessment date).
Corporate Revolver
In November 2012, we secured a Corporate Revolver from a number of financial institutions which, as amended in June 2015, has an availability of $400.0 million. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration; appraisal and development programs. As of December 31, 2016, we have $5.2 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term, which as amended expires in November 2018. These deferred financing costs are included in the Other assets section of the consolidated balance sheet.
As of December 31, 2016, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400.0 million.
Interest is the aggregate of the applicable margin (6.0%); LIBOR; and mandatory cost (if any, as defined in the Corporate Revolver). Interest is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six‑month intervals after the first day of the interest period). We pay commitment fees on the undrawn portion of the total commitments. Commitment fees, as amended in June 2015, for the lenders are equal to 30% per annum of the respective margin when a commitment is available for utilization.
The Corporate Revolver, as amended in June 2015, expires on November 23, 2018. The available amount is not subject to borrowing base constraints. Kosmos has the right to cancel all the undrawn commitments under the Corporate Revolver. The Company is required to repay certain amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default exists under the Corporate Revolver, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us.
We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2016 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.
Revolving Letter of Credit Facility
In July 2013, we entered into a revolving letter of credit facility agreement (“LC Facility”). The size of the LC Facility is $75.0 million, as amended in July 2015, with additional commitments up to $50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. The LC Facility provides that we maintain cash collateral in an amount equal to at least 75% of all outstanding letters of credit under the LC Facility, provided that during the period of any breach of certain financial covenants, the required cash collateral amount shall increase to 100%.
In July 2016, we amended and restated the LC Facility, extending the maturity date to July 2019. The LC Facility size remains at $75.0 million, as amended in July 2015, with additional commitments up to $50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. Other amendments include increasing the margin from 0.5% to 0.8% per annum on amounts outstanding, adding a commitment
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fee payable quarterly in arrears at an annual rate equal to 0.65% on the available commitment amount and providing for issuance fees to be payable to the lender per new issuance of a letter of credit. We may voluntarily cancel any commitments available under the LC Facility at any time. As of December 31, 2016, there were nine outstanding letters of credit totaling $72.8 million under the LC Facility. The LC Facility contains customary cross default provisions.
In February 2017, we exercised an option to increase the size of the LC Facility to $125.0 million to facilitate the issuance of additional letters of credit.
7.875% Senior Secured Notes due 2021
 
During August 2014, the Company issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.
 
During April 2015, we issued an additional $225.0 million of Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued.
 
The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries (the “Guarantees”).
 
Redemption and Repurchase.  At any time prior to August 1, 2017 and subject to certain conditions, the Company may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of Senior Notes issued under the indenture dated August 1, 2014 related to the Senior Notes (the “Indenture”) at a redemption price of 107.875%, plus accrued and unpaid interest, with the cash proceeds of certain eligible equity offerings. Additionally, at any time prior to August 1, 2017, the Company may, on any one or more occasions, redeem all or a part of the Senior Notes at a redemption price equal to 100%, plus any accrued and unpaid interest, and a make-whole premium. On or after August 1, 2017, the Company may redeem all or a part of the Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:
 	 	 	 	
Year	    	Percentage	 	
On or after August 1, 2017, but before August 1, 2018	 	103.9	%	
On or after August 1, 2018, but before August 1, 2019	 	102.0	%	
On or after August 1, 2019 and thereafter	 	100.0	%	

We may also redeem the Senior Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the Senior Notes at a price equal to the principal amount of the Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted.
 
Upon the occurrence of a change of control triggering event as defined under the Indenture, the Company will be required to make an offer to repurchase the Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.
 
If we sell assets, under certain circumstances outlined in the Indenture, we will be required to use the net proceeds to make an offer to purchase the Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.
 
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Covenants.  The Indenture restricts our ability and the ability of our restricted subsidiaries to, among other things:  incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of our subsidiaries to make dividends or other payments to us, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing.
 
Collateral.  The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all currently outstanding shares, additional shares, dividends or other distributions paid in respect of such shares or any other property derived from such shares, in each case held by us in relation to the Company’s direct subsidiary, Kosmos Energy Holdings, pursuant to the terms of the Charge over Shares of Kosmos Energy Holdings dated November 23, 2012, as amended and restated on March 14, 2014, between the Company and BNP Paribas as Security and Intercreditor Agent. The Senior Notes share  pari passu  in the benefit of such equitable charge based on the respective amounts of the obligations under the Indenture and the amount of obligations under the Corporate Revolver. The Guarantees are not secured.
At December 31, 2016, the estimated repayments of debt during the five years and thereafter are as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Payments Due by Year	 	
 	    	Total	    	2017	    	2018	    	2019	    	2020	    	2021	    	Thereafter	 	
 	 	(In thousands)	 	
Principal debt repayments(1)	 	$	1,375,000	 	$	 —	 	$	 —	 	$	268,823	 	$	395,166	 	$	711,011	 	$	 —	 	

 	(1)	 	Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the estimated future available borrowing base as of December 31, 2016. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of December 31, 2016, there were no borrowings under the Corporate Revolver.	
Interest and other financing costs, net
Interest and other financing costs, net incurred during the period comprised of the following:
 	 	 	 	 	 	 	 	 	 	
 	Years Ended December 31,	 	
 	2016	    	2015	    	2014	 	
 	(In thousands)	 	
Interest expense	$	89,029	 	$	74,897	 	$	57,876	 	
Amortization—deferred financing costs	 	10,204	 	 	10,324	 	 	10,548	 	
Loss on extinguishment of debt	 	 —	 	 	165	 	 	2,898	 	
Capitalized interest	 	(59,803)	 	 	(52,392)	 	 	(20,577)	 	
Deferred interest	 	(581)	 	 	1,770	 	 	(3,562)	 	
Interest income	 	(1,954)	 	 	(844)	 	 	(529)	 	
Other, net	 	7,252	 	 	3,289	 	 	(1,106)	 	
Interest and other financing costs, net	$	44,147	 	$	37,209	 	$	45,548	 	

 
8. Derivative Financial Instruments
We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes.
We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of nonperformance risk in the fair value measurement of our derivative contracts as required by ASC 820—Fair Value Measurements and Disclosures.
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Oil Derivative Contracts
The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of December 31, 2016. Volumes are net of any offsetting derivative contracts entered into.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Weighted Average Dated Brent Price per Bbl	 	
 	 	 	 	 	 	Net Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Premium	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Term	    	Type of Contract	    	MBbl	    	Payable	    	Swap	    	Sold Put	    	Floor	    	Ceiling	    	Call	 	
2017:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January — December	 	Swap with puts/calls	 	2,000	 	$	2.13	 	$	72.50	 	$	55.00	 	$	 —	 	$	 —	 	$	90.00	 	
January — December	 	Swap with puts	 	2,000	 	 	 —	 	 	64.95	 	 	50.00	 	 	 —	 	 	 —	 	 	 —	 	
January — December	 	Three-way collars	 	3,002	 	 	2.29	 	 	 —	 	 	30.00	 	 	45.00	 	 	57.50	 	 	 —	 	
January — December	 	Sold calls(1)	 	2,000	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	85.00	 	 	 —	 	
2018:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January — December	 	Three-way collars	 	2,913	 	$	0.74	 	$	 —	 	$	41.57	 	$	56.57	 	$	65.90	 	$	 —	 	
January — December	 	Sold calls(1)	 	2,000	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	65.00	 	 	 —	 	
2019:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January — December	 	Sold calls(1)	 	913	 	$	 —	 	$	 —	 	$	 —	 	$	 —	 	$	80.00	 	$	 —	 	

 
 	(1)	 	Represents call option contracts sold to counterparties to enhance other derivative positions.	
In February 2017, we entered into three-way collar contracts for 1.0 MMBbl from January 2018 through December 2018 with a floor price of $50.00 per barrel, a ceiling price of $62.00 per barrel and a purchased call price of $70.00 per barrel. The contracts are indexed to Dated Brent prices and have a weighted average deferred premium payable of $2.32 per barrel.
Interest Rate Derivative Contracts
The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of December 31, 2016:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Weighted Average	 	 	
Term	    	Type of Contract	 	Floating Rate	    	Notional	    	Swap	    	Sold Call	 	 	
 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	
January 2017 — December 2018	 	Capped swap	 	1-month LIBOR	 	$	200,000	 	1.23	%  	3.00	%	 	
 
Effective June 1, 2010, we discontinued hedge accounting on all interest rate derivative instruments. Therefore, from that date forward, changes in the fair value of the instruments have been recognized in earnings during the period of change. The effective portions of the discontinued hedges as of May 31, 2010, were included in AOCI in the equity section of the accompanying consolidated balance sheets, and were transferred to earnings when the hedged transaction settled. As of December 31, 2015 all instruments previously designated as hedges have settled and there is no balance remaining in AOCI. See Note 9—Fair Value Measurements for additional information regarding the Company’s derivative instruments.
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The following tables disclose the Company’s derivative instruments as of December 31, 2016 and 2015 and gain/(loss) from derivatives during the years ended December 31, 2016, 2015 and 2014
 	 	 	 	 	 	 	 	 	 	
 	 	 	 	Estimated Fair Value	 	
 	 	 	 	Asset (Liability)	 	
 	    	    	    	December 31,	 	
Type of Contract 	    	Balance Sheet Location	    	2016	    	2015	 	
 	 	 	 	(In thousands)	 	
Derivatives not designated as hedging instruments:	 	 	 	 	 	 	 	 	 	
Derivative assets:	 	 	 	 	 	 	 	 	 	
Commodity(1)	 	Derivatives assets—current	 	$	31,698	 	$	182,640	 	
Commodity(2)	 	Derivatives assets—long-term	 	 	3,226	 	 	59,197	 	
Interest rate	 	Derivatives assets—long-term	 	 	582	 	 	659	 	
Derivative liabilities:	 	 	 	 	 	 	 	 	 	
Commodity(3)	 	Derivatives liabilities—current	 	 	(19,163)	 	 	 —	 	
Interest rate	 	Derivatives liabilities—current	 	 	(529)	 	 	(1,155)	 	
Commodity(4)	 	Derivatives liabilities—long-term	 	 	(14,123)	 	 	(4,196)	 	
Total derivatives not designated as hedging instruments	 	 	 	$	1,691	 	$	237,145	 	

 	(1)	 	Includes net deferred premiums payable of $3.9 million and $6.2 million related to commodity derivative contracts as of December 31, 2016 and 2015, respectively.	

 	(2)	 	Includes net deferred premiums payable of $2.5 million and $6.9 million related to commodity derivative contracts as of December 31, 2016 and 2015, respectively.	

 	(3)	 	Includes $30.9 thousand and zero as of December 31, 2016 and December 31, 2015, respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of $6.2 million and zero related to commodity derivative contracts as of December 31, 2016 and 2015, respectively.	

 	(4)	 	Includes net deferred premiums payable of $0.6 million and zero related to commodity derivative contracts as of December 31, 2016 and 2015, respectively.	

 	 	 	 	Amount of Gain/(Loss)	 	
 	 	 	 	Years Ended December 31,	 	
Type of Contract	    	Location of Gain/(Loss)	    	2016	    	2015	    	2014	 	
 	 	 	 	(In thousands)	 	 	 	 	
Derivatives in cash flow hedging relationships:	 	 	 	 	 	 	 	 	 	 	 	 	
Interest rate(1)	 	Interest expense	 	$	 —	 	$	767	 	$	1,391	 	
Total derivatives in cash flow hedging relationships	 	 	 	$	 —	 	$	767	 	$	1,391	 	
Derivatives not designated as hedging instruments:	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity(2)	 	Oil and gas revenue	 	$	2,538	 	$	3	 	$	(11,661)	 	
Commodity	 	Derivatives, net	 	 	(48,021)	 	 	210,649	 	 	281,853	 	
Interest rate	 	Interest expense	 	 	(1,076)	 	 	(462)	 	 	(285)	 	
Total derivatives not designated as hedging instruments	 	 	 	$	(46,559)	 	$	210,190	 	$	269,907	 	

 	(2)	 	 	

 	(1)	 	Amounts were reclassified from AOCI into earnings upon settlement.	

 	(2)	 	Amounts represent the change in fair value of our provisional oil sales contracts.	
Offsetting of Derivative Assets and Derivative Liabilities
Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of December 31, 2016 and 2015, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.
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9. Fair Value Measurements
In accordance with ASC 820—Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy:
 	·	 	Level 1—quoted prices for identical assets or liabilities in active markets.	

 	·	 	Level 2—quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means.	

 	·	 	Level 3—unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.	
The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2016 and 2015, for each fair value hierarchy level:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	    	Fair Value Measurements Using:	 	
 	 	Quoted Prices in	 	 	 	 	 	 	 	 	
 	 	Active Markets for	 	Significant Other	 	Significant	 	 	 	 	
 	 	Identical Assets	 	Observable Inputs	 	Unobservable Inputs	 	 	 	 	
 	    	(Level 1)	    	(Level 2)	    	(Level 3)	    	Total	 	
 	 	(In thousands)	 	
December 31, 2016	 	 	 	 	 	 	 	 	 	 	 	 	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	$	 —	 	$	34,924	 	$	 —	 	$	34,924	 	
Interest rate derivatives	 	 	 —	 	 	582	 	 	 —	 	 	582	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	 	 —	 	 	(33,286)	 	 	 —	 	 	(33,286)	 	
Interest rate derivatives	 	 	 —	 	 	(529)	 	 	 —	 	 	(529)	 	
Total	 	$	 —	 	$	1,691	 	$	 —	 	$	1,691	 	
December 31, 2015	 	 	 	 	 	 	 	 	 	 	 	 	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	$	 —	 	$	241,837	 	$	 —	 	$	241,837	 	
Interest rate derivatives	 	 	 —	 	 	659	 	 	 —	 	 	659	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	 	 —	 	 	(4,196)	 	 	 —	 	 	(4,196)	 	
Interest rate derivatives	 	 	 —	 	 	(1,155)	 	 	 —	 	 	(1,155)	 	
Total	 	$	 —	 	$	237,145	 	$	 —	 	$	237,145	 	
 
The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short‑term nature of these instruments. Our long‑term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.
Commodity Derivatives
Our commodity derivatives represent crude oil three‑way collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for Dated Brent, (iii) a credit‑adjusted yield curve applicable
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to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for Dated Brent. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market‑quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 8—Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.
Provisional Oil Sales
The value attributable to the provisional oil sales derivative is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for Dated Brent over the term of the pricing period designated in the sales contract and the spot price on the lifting date.
Interest Rate Derivatives
We enter into interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR‑based rate. We also enter into capped interest rate swaps, whereby the Company pays a fixed rate of interest if LIBOR is below the cap, and pays the market rate less the spread between the cap and the fixed rate of interest if LIBOR is above the cap. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) LIBOR yield curves provided by independent third parties and corroborated with forward active market‑quoted LIBOR yield curves and (iii) a credit‑adjusted yield curve as applicable to each counterparty by reference to the CDS market.
Debt
The following table presents the carrying values and fair values at December 31, 2016 and 2015:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	December 31, 2016	 	December 31, 2015	 	
 	    	Carrying Value	    	Fair Value	    	Carrying Value	    	Fair Value	 	
 	 	(In thousands)	 	
Senior Notes	 	$	503,716	 	$	528,938	 	$	500,186	 	$	423,612	 	
Facility	 	 	850,000	 	 	850,000	 	 	400,000	 	 	400,000	 	
Total	 	$	1,353,716	 	$	1,378,938	 	$	900,186	 	$	823,612	 	
 
The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.
 
10. Asset Retirement Obligations
The following table summarizes the changes in the Company’s asset retirement obligations:
 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2016	 	2015	 	
 	 	(In thousands)	 	
Asset retirement obligations:	 	 	 	 	 	 	 	
Beginning asset retirement obligations	    	$	43,938	    	$	44,023	 	
Liabilities incurred during period	 	 	14,235	 	 	3,818	 	
Revisions in estimated retirement obligations	 	 	 —	 	 	(9,023)	 	
Accretion expense	 	 	5,401	 	 	5,120	 	
Ending asset retirement obligations	 	$	63,574	 	$	43,938	 	

   The Ghanaian legal and regulatory regime regarding oil field abandonment and other environmental matters is evolving. Currently, no Ghanaian environmental regulations expressly require that companies abandon or remove offshore assets. Under the Environmental Permit for the Jubilee Field, a decommissioning plan will be prepared and submitted to the Ghana Environmental Protection Agency. ASC 410—Asset Retirement and Environmental Obligations requires the
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Company to recognize this liability in the period in which the liability was incurred. The TEN fields commenced production during the third quarter and an asset retirement obligation was recorded for the facilities and wells that came online during 2016. Additional asset retirement obligations will be recorded in the period in which additional wells within our producing fields are commissioned.
 
11. Equity‑based Compensation
Restricted Stock Awards and Restricted Stock Units
Prior to our corporate reorganization, Kosmos Energy Holdings issued common units designated as profit units with a threshold value ranging from $0.85 to $90 to employees, management and directors. Profit units were equity awards that were measured on the grant date and expensed over a vesting period of four years. Founding management and directors vested 20% as of the date of issuance and an additional 20% on the anniversary date for each of the next four years. Profit units issued to employees vested 50% on the second and fourth anniversaries of the issuance date.
As part of the corporate reorganization in May 2011, vested profit units were exchanged for 31.7 million common shares of Kosmos Energy Ltd., unvested profit units were exchanged for 10.0 million restricted stock awards and the $90 profit units were cancelled. These restricted stock awards ultimately vested during 2015. Based on the terms and conditions of the corporate reorganization, the exchange of profit units for common shares of Kosmos Energy Ltd. resulted in no incremental compensation costs.
In April 2011, the Board of Directors approved the LTIP, which provides for the granting of incentive awards in the form of stock options, stock appreciation rights, restricted stock awards, restricted stock units, among other award types. In January 2015, the board of directors approved an amendment to the plan to add 15.0 million shares to the plan which was approved at the Annual General Meeting in June 2015. The LTIP provides for the issuance of 39.5 million shares pursuant to awards under the plan, in addition to the 10.0 million restricted stock awards exchanged for unvested profit units. As of December 31, 2016, the Company had approximately 8.3 million shares that remain available for issuance under the LTIP.
The Company adopted ASU 2016-09, “Improvements to Employee Share-based Payment Accounting” during the second quarter of 2016 using an effective date of January 1, 2016. Prior period compensation expense disclosed below includes estimated forfeitures and has not been adjusted.
We record equity-based compensation expense equal to the fair value of share‑based payments over the vesting periods of the LTIP awards. We recorded compensation expense from awards granted under our LTIP of $40.1 million, $75.1 million and $74.5 million during the years ended December 31, 2016, 2015 and 2014, respectively. During the year ended December 31, 2014, an additional $5.0 million of equity-based compensation was recorded as restructuring charges. The total tax benefit for the years ended December 31, 2016, 2015 and 2014 was $13.0 million, $25.7 million and $25.7 million, respectively. Additionally, we expensed a tax shortfall related to equity‑based compensation of $5.5 million, $18.6 million and $6.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. The fair value of awards vested during 2016, 2015 and 2014 was approximately $14.4 million, $52.2 million, and $37.0 million, respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service vesting criteria under the LTIP. Substantially, all of these awards vest over three or four year periods. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock.
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The following table reflects the outstanding restricted stock awards as of December 31, 2016:

 	 	 	 	Weighted-	 	Market / Service	 	Weighted-	 	
 	 	Service Vesting	 	Average	 	Vesting	 	Average	 	
 	 	Restricted Stock	 	Grant-Date	 	Restricted Stock	 	Grant-Date	 	
 	    	Awards	    	Fair Value	    	Awards	    	Fair Value	 	
 	 	(In thousands)	 	 	 	 	(In thousands)	 	 	 	 	
Outstanding at December 31, 2013	 	6,384	 	$	16.48	 	3,438	 	$	12.95	 	
Granted	 	 —	 	 	 —	 	 —	 	 	—	 	
Forfeited	 	(122)	 	 	15.20	 	(77)	 	 	10.74	 	
Vested	 	(3,022)	 	 	16.02	 	 —	 	 	—	 	
Outstanding at December 31, 2014	 	3,240	 	 	16.95	 	3,361	 	 	13.00	 	
Granted	 	660	 	 	8.64	 	 —	 	 	—	 	
Forfeited	 	(2)	 	 	12.84	 	(1,554)	 	 	13.29	 	
Vested	 	(3,088)	 	 	17.21	 	(1,546)	 	 	13.30	 	
Outstanding at December 31, 2015	 	810	 	 	9.20	 	261	 	 	9.44	 	
Granted	 	 —	 	 	 —	 	 —	 	 	 —	 	
Forfeited	 	 —	 	 	 —	 	(162)	 	 	9.44	 	
Vested	 	(322)	 	 	9.77	 	(99)	 	 	9.44	 	
Outstanding at December 31, 2016	 	488	 	 	8.83	 	 —	 	 	 —	 	
 
The following table reflects the outstanding restricted stock units as of December 31, 2016:

 	 	 	 	Weighted-	 	Market / Service	 	Weighted-	 	
 	 	Service Vesting	 	Average	 	Vesting	 	Average	 	
 	 	Restricted Stock	 	Grant-Date	 	Restricted Stock	 	Grant-Date	 	
 	    	Units	    	Fair Value	    	Units	    	Fair Value	 	
 	 	(In thousands)	 	 	 	 	(In thousands)	 	 	 	 	
Outstanding at December 31, 2013	 	2,238	 	$	10.74	 	1,858	 	$	15.59	 	
Granted	 	2,113	 	 	10.80	 	1,572	 	 	15.71	 	
Forfeited	 	(412)	 	 	10.90	 	(184)	 	 	15.48	 	
Vested	 	(572)	 	 	10.74	 	—	 	 	—	 	
Outstanding at December 31, 2014	 	3,367	 	 	10.76	 	3,246	 	 	15.66	 	
Granted	 	1,539	 	 	8.37	 	3,544	 	 	12.96	 	
Forfeited	 	(254)	 	 	10.14	 	(212)	 	 	14.48	 	
Vested	 	(1,060)	 	 	10.71	 	—	 	 	—	 	
Outstanding at December 31, 2015	 	3,592	 	$	9.79	 	6,578	 	$	14.24	 	
Granted	 	2,158	 	 	4.05	 	1,379	 	 	4.88	 	
Forfeited	 	(134)	 	 	8.87	 	(70)	 	 	14.49	 	
Vested	 	(1,456)	 	 	9.61	 	(693)	 	 	15.81	 	
Outstanding at December 31, 2016	 	4,160	 	 	6.91	 	7,194	 	 	12.29	 	
 
As of December 31, 2016, total equity‑based compensation to be recognized on unvested restricted stock awards and restricted stock units is $31.6 million over a weighted average period of 1.3 years.
For restricted stock awards and restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 100% of the awards granted for restricted stock awards and up to 200% of the awards granted for restricted stock units. The grant date fair value of these awards ranged from $6.70 to $13.57 per award for restricted stock awards and $4.83 to $15.81 per award for restricted stock units. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 41.3% to 56.7% for restricted stock awards and 44.0% to 54.0% for restricted stock units. The risk‑free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.5% to 1.1% for restricted stock awards and 0.5% to 1.2% for restricted stock units.
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For profit units that were exchanged for restricted stock awards, the significant assumptions used to calculate the fair values of the profit units granted as calculated using a binomial tree, were as follows: no dividend yield, expected volatility ranging from approximately 25% to 66%; risk‑free interest rate ranging from 1.3% to 5.1%; expected life ranging from 1.2 to 8.1 years; and projected turnover rates ranging from 7.0% to 27.0% for employees and none for management. For profit units granted immediately prior to our initial public offering, we utilized the midpoint of the range of the estimated offering price, or $17.00 per share.
In January 2017, we granted 1.8 million service vesting restricted stock units and 2.1 million market and service vesting restricted stock units to our employees under our long-term incentive plan. We expect to recognize approximately $34.1 million of non-cash compensation expense related to these grants over the next three years.
 
12. Income Taxes
Kosmos Energy Ltd. is a Bermuda company that is not subject to taxation at the corporate level. We provide for income taxes based on the laws and rates in effect in the countries in which our operations are conducted. The relationship between our pre‑tax income or loss from continuing operations and our income tax expense or benefit varies from period to period as a result of various factors which include changes in total pre‑tax income or loss, the jurisdictions in which our income (loss) is earned and the tax laws in those jurisdictions.
The components of income (loss) before income taxes were as follows:
 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	    	2016	    	2015	    	2014	 	
 	 	(In thousands)	 	
Bermuda	 	$	(63,749)	 	$	(62,372)	 	$	(31,787)	 	
United States	 	 	5,083	 	 	10,652	 	 	15,684	 	
Foreign—other	 	 	(235,898)	 	 	137,156	 	 	594,371	 	
Income (loss) before income taxes	 	$	(294,564)	 	$	85,436	 	$	578,268	 	

The components of the provision for income taxes attributable to our income (loss) before income taxes consist of the following:
 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	    	2016	    	2015	    	2014	 	
 	 	(In thousands)	 	
Current:	 	 	 	 	 	 	 	 	 	 	
Bermuda	 	$	 —	 	$	 —	 	$	 —	 	
United States	 	 	12,675	 	 	15,199	 	 	27,167	 	
Foreign—other	 	 	102	 	 	29,287	 	 	55,322	 	
Total current	 	 	12,777	 	 	44,486	 	 	82,489	 	
Deferred:	 	 	 	 	 	 	 	 	 	 	
Bermuda	 	 	 —	 	 	 —	 	 	 —	 	
United States	 	 	(3,594)	 	 	8,241	 	 	(14,403)	 	
Foreign—other	 	 	(19,967)	 	 	102,545	 	 	230,812	 	
Total deferred	 	 	(23,561)	 	 	110,786	 	 	216,409	 	
Income tax expense (benefit)	 	$	(10,784)	 	$	155,272	 	$	298,898	 	

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Our reconciliation of income tax expense (benefit) computed by applying our Bermuda statutory rate and the reported effective tax rate on income (loss) from continuing operations is as follows:
 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	    	2016	    	2015	    	2014	 	
 	 	(In thousands)	 	
Tax at Bermuda statutory rate	 	$	 —	 	$	 —	 	$	 —	 	
Foreign income (loss) taxed at different rates	 	 	(57,898)	 	 	94,184	 	 	266,993	 	
Change in valuation allowance and the expiration of fully valued deferred tax assets	 	 	29,263	 	 	40,600	 	 	16,401	 	
Non-deductible and other items	 	 	12,347	 	 	1,885	 	 	8,957	 	
Tax shortfall on equity-based compensation	 	 	5,504	 	 	18,603	 	 	6,547	 	
Total tax expense (benefit)	 	$	(10,784)	 	$	155,272	 	$	298,898	 	
Effective tax rate(1)	 	 	4	%	 	182	%	 	52	%	

 	(1)	 	The effective tax rate during the years ended December 31, 2016, 2015 and 2014 were impacted by losses of $121.4 million, $153.5 million and $159.9 million, respectively, incurred in jurisdictions in which we are not subject to taxes and therefore do not generate any income tax benefits.	
The effective tax rate for the United States is approximately 179%, 220% and 81% for the years ended December 31, 2016, 2015 and 2014, respectively. The effective tax rate in the United States is impacted by the effect of equity-based compensation tax shortfalls equal to the excess income tax benefit recognized for financial statement purposes over the income tax benefit realized for tax return purposes. The effective tax rate for Ghana is approximately 23%, 35% and 36% for the years ended December 31, 2016, 2015 and 2014, respectively. The effective tax rate in Ghana is impacted by non-deductible expenditures associated with the damage to the turret bearing, which we expect to recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax. Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets.
Deferred tax assets and liabilities, which are computed on the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities, are determined using the tax rates expected to be in effect when taxes are actually paid or recovered. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows:
 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	    	2016	    	2015	 	
 	 	(In thousands)	 	
Deferred tax assets:	 	 	 	 	 	 	 	
Foreign capitalized operating expenses	 	$	69,804	 	$	101,823	 	
Foreign net operating losses	 	 	36,352	 	 	14,719	 	
Equity compensation	 	 	30,752	 	 	26,095	 	
Other	 	 	33,744	 	 	22,656	 	
Total deferred tax assets	 	 	170,652	 	 	165,293	 	
Valuation allowance	 	 	(87,517)	 	 	(116,541)	 	
Total deferred tax assets, net	 	 	83,135	 	 	48,752	 	
Deferred tax liabilities:	 	 	 	 	 	 	 	
Depletion, depreciation and amortization related to property and equipment	 	 	(526,945)	 	 	(425,183)	 	
Unrealized derivative gains	 	 	(584)	 	 	(92,549)	 	
Total deferred tax liabilities	 	 	(527,529)	 	 	(517,732)	 	
Net deferred tax liability	 	$	(444,394)	 	$	(468,980)	 	
 
The Company has recorded a full valuation allowance against the net deferred tax assets in countries where we only have exploration operations. The net decrease in the valuation allowance of $29.0 million is due to the write-off of previously capitalized foreign operating expenses and tax losses in Morocco related to the relinquishment of three licenses
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and the utilization of deferred tax assets to offset the tax impact of a payment from a joint license holder related to their withdrawal from three licenses, together totaling $58.2 million. The decrease in valuation allowance was partially offset by the tax effect of 2016 losses and foreign capitalized operating expenses of $29.2 million.
The Company has entered into various petroleum contracts in Morocco. These petroleum contracts provide for a tax holiday, at a 0% tax rate, for a period of 10 years beginning on the date of first production, if any.
The Company has foreign net operating loss carryforwards of $116.7 million. Of these losses, we expect $0.9 million, $13.4 million, $0.5 million, $0.5 million and $0.6 million to expire in 2019, 2020, 2021, 2022 and 2023, respectively, and $100.8 million do not expire. The Ghana tax loss of $53.3 million is expected to be fully utilized in 2017. The remaining $63.4 million in tax losses currently have offsetting valuation allowances.
A subsidiary of the Company files a U.S. federal income tax return and a Texas margin tax return. In addition to the United States, the Company files income tax returns in the countries in which we operate. The Company is open to U.S. federal income tax examinations for tax years 2013 through 2016 and to Texas margin tax examinations for the tax years 2011 through 2016. In addition, the Company is open to income tax examinations for years 2011 through 2016 in its significant other foreign jurisdictions, primarily Ghana.
As of December 31, 2016, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense.
13. Net Income (Loss) Per Share
In the calculation of basic net income per share, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income, if any. We calculate basic net income per share under the two‑class method. Diluted net income (loss) per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. The computation of diluted net income (loss) per share reflects the potential dilution that could occur if all outstanding awards under our LTIP were converted into common shares or resulted in the issuance of common shares that would then share in the earnings of the Company. During periods in which the Company realizes a loss from continuing operations securities would not be dilutive to net loss per share and conversion into common shares is assumed not to occur.
Basic net income (loss) per share is computed as (i) net income (loss), (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. The Company’s diluted net income (loss) per share
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is computed as (i) basic net income (loss), (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding.
 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended	 	 	
 	 	December 31,	 	 	
 	   	2016	   	2015	   	2014	 	 	
 	 	(In thousands, except per share data)	 	 	
Numerator:	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	(283,780)	 	$	(69,836)	 	$	279,370	 	 	
Basic income allocable to participating securities(1)	 	 	 —	 	 	 —	 	 	(3,286)	 	 	
Basic net income (loss) allocable to common shareholders	 	 	(283,780)	 	 	(69,836)	 	 	276,084	 	 	
Diluted adjustments to income allocable to participating securities(1)	 	 	 —	 	 	 —	 	 	58	 	 	
Diluted net income (loss) allocable to common shareholders	 	$	(283,780)	 	$	(69,836)	 	$	276,142	 	 	
Denominator:	 	 	 	 	 	 	 	 	 	 	 	
Weighted average number of shares outstanding:	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	385,402	 	 	382,610	 	 	379,195	 	 	
Restricted stock awards and units(1)(2)	 	 	 —	 	 	 —	 	 	6,924	 	 	
Diluted	 	 	385,402	 	 	382,610	 	 	386,119	 	 	
Net income (loss) per share:	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	$	(0.74)	 	$	(0.18)	 	$	0.73	 	 	
Diluted	 	$	(0.74)	 	$	(0.18)	 	$	0.72	 	 	

 
 	(1)	 	Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income (loss) per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net income (loss) per common share calculation in periods we are in a net loss position.	

 	(2)	 	For the years ended December 31, 2016, 2015 and 2014, we excluded 11.8 million, 11.2 million and 4.4 million outstanding restricted stock awards and restricted stock units, respectively, from the computations of diluted net income per share because the effect would have been anti‑dilutive.	
14. Commitments and Contingencies
From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.
The Jubilee Field in Ghana covers an area within both the WCTP and DT petroleum contract areas. It was agreed the Jubilee Field would be unitized for optimal resource recovery. Kosmos and its partners executed a comprehensive unitization and unit operating agreement, the Jubilee UUOA, to unitize the Jubilee Field and govern each party’s respective rights and duties in the Jubilee Unit, which was effective July 16, 2009. Pursuant to the terms of the Jubilee UUOA, the tract participations are subject to a process of redetermination. The initial redetermination process was completed on October 14, 2011. As a result of the initial redetermination process, our Unit Interest is 24.1%. These consolidated financial statements are based on these re determined tract participations. Our unit interest may change in the future should another redetermination occur.
The Company leases facilities under various operating leases that expire through 2019, including our office space. Rent expense under these agreements, was $3.3 million, $4.7 million and $4.6 million for the years ended December 31, 2016, 2015 and 2014, respectively.
We currently have a commitment to drill two exploration wells in Mauritania. In Mauritania, our partner is obligated to fund our share of the cost of the exploration wells, subject to their maximum $221 million cumulative
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exploration and appraisal carry covering both our Mauritania and Senegal blocks. Additionally, in Sao Tome and Principe we have 2D and 3D seismic requirements of 1,200 square kilometers and 4,000 square kilometers, respectively, and we have 3D seismic requirements in Mauritania and Western Sahara of 3,000 square kilometers and 5,000 square kilometers, respectively.
In January 2017, Kosmos Energy Ventures (“KEV”), a subsidiary of Kosmos Energy Ltd., elected to cancel the fourth year option of the Atwood Achiever drilling rig contract and revert to the original day rate of approximately $0.6 million per day and original agreement end date of November 2017. KEV is required to make a rate recovery payment of approximately $48.1 million representing the difference between the original day rate and the amended day rate multiplied by the number of days from the amendment effective date to the date the election is exercised plus certain administrative costs. This amount will be charged to exploration expense in the first quarter of 2017.
In November 2015, we entered into a line of credit agreement with one of our block partners, whereby, our partner may draw up to $30 million on the line of credit to pay their portion of costs under the petroleum agreement. Interest accrues on drawn balances at 7.875%. The agreement matures on December 31, 2017, or earlier if certain conditions are met. As of December 31, 2016, there was $10.2 outstanding under the agreement, which is included in other long-term assets.
Future minimum rental commitments under these leases at December 31, 2016, are as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Payments Due By Year(1)	 	
 	    	Total	    	2017	    	2018	    	2019	    	2020	    	2021	    	Thereafter	 	
 	 	(In thousands)	 	
Operating leases(2)	 	$	11,171	 	$	4,190	 	$	3,820	 	$	3,161	 	$	 —	 	$	 —	 	$	 —	 	
Atwood Achiever drilling rig contract(3)	 	 	229,482	 	 	229,482	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	

 	(1)	 	Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts.	

 	(2)	 	Primarily relates to corporate office and foreign office leases.	

 	(3)	 	In January 207, KEV exercised its option to cancel the fourth year and revert to the original day rate of approximately $0.6 million per day and original agreement end date of November 2017. Commitments calculated using the original day rate of $0.6 million effective February 1, 2017, excluding applicable taxes. The commitments also include a $48.1 million rate recovery payment equal to the difference between the original day rate and the amended day rate.	
 
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15. Additional Financial Information
Accrued Liabilities
Accrued liabilities consisted of the following:
 	 	 	 	 	 	 	 	 	
 	    	 	December 31,	 	
 	   	 	2016	   	2015	 	
 	 	 	(In thousands)	 	
Accrued liabilities:	 	 	 	 	 	 	 	 	
Exploration, development and production	 	 	$	76,194	 	$	111,064	 	
General and administrative expenses	 	 	 	31,243	 	 	24,839	 	
Interest	 	 	 	17,247	 	 	17,512	 	
Income taxes	 	 	 	2,579	 	 	3,418	 	
Taxes other than income	 	 	 	1,914	 	 	3,064	 	
Other	 	 	 	529	 	 	 —	 	
 	 	 	$	129,706	 	$	159,897	 	
 
Other Income
Other income consisted of $74.8 million of Loss of Production Income (“LOPI”) proceeds related to the turret bearing issue on the Jubilee FPSO for the year ended December 31, 2016.
 
Facilities Insurance Modifications
 
Facilities insurance modifications consist of costs associated with the long-term solution to convert the FPSO to a permanently spread moored facility which we expect to recover from our insurance policy. Insurance reimbursement of these costs, if any, will also be recorded to this line.
 
Other Expenses, Net
 
Other expenses, net incurred during the period is comprised of the following:

 	Years Ended December 31,	 	
 	2016	    	2015	    	2014	 	
 	(In thousands)	 	
Inventory write-off	$	14,900	 	$	36	 	$ 	170	 	
(Gain) loss on insurance settlements - riser	 	(4,003)	 	 	4,151	 	 	 —	 	
Disputed charges and related costs	 	11,299	 	 	 —	 	 	 —	 	
Other, net	 	920	 	 	1,059	 	 	1,911	 	
Other expenses, net	$	23,116	 	$	5,246	 	$	2,081	 	
 
The disputed charges and related costs are expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow has charged such expenditures to the Deepwater Tano (“DT”) joint account. Kosmos disputes that these expenditures are chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement.
 
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KOSMOS ENERGY LTD.
Supplemental Oil and Gas Data (Unaudited)
Net proved oil and gas reserve estimates presented were prepared by Ryder Scott Company, L.P. (“RSC”) for the years ended December 31, 2016, 2015 and 2014. RSC are independent petroleum engineers located in Houston, Texas. RSC has prepared the reserve estimates presented herein and meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to independent reserve engineers for their reserves estimation process.
Net Proved Developed and Undeveloped Reserves
The following table is a summary of net proved developed and undeveloped oil and gas reserves to Kosmos’ interest in the Jubilee and TEN fields in Ghana.
 	 	 	 	 	 	 	 	
 	    	Oil	    	Gas	    	Total	 	
 	 	(MMBbl)	 	(Bcf)	 	(MMBoe)	 	
Net proved developed and undeveloped reserves at December 31, 2013(1)	 	45	 	11	 	47	 	
Extensions and discoveries(2)	 	26	 	6	 	27	 	
Production	 	(9)	 	(1)	 	(9)	 	
Revision in estimate(3)	 	11	 	(2)	 	10	 	
Purchases of minerals-in-place	 	 —	 	 —	 	 —	 	
Net proved developed and undeveloped reserves at December 31, 2014(1)	 	73	 	14	 	75	 	
Extensions and discoveries	 	 —	 	 —	 	 —	 	
Production	 	(9)	 	(1)	 	(9)	 	
Revision in estimate(4)	 	10	 	1	 	10	 	
Purchases of minerals-in-place	 	 —	 	 —	 	 —	 	
Net proved developed and undeveloped reserves at December 31, 2015(1)	 	74	 	14	 	76	 	
Extensions and discoveries	 	 —	 	 —	 	 —	 	
Production	 	(7)	 	(1)	 	(7)	 	
Revision in estimate(5)	 	7	 	2	 	8	 	
Purchases of minerals-in-place	 	 —	 	 —	 	 —	 	
Net proved developed and undeveloped reserves at December 31, 2016(1)	 	74	 	15	 	77	 	
Proved developed reserves(1)	 	 	 	 	 	 	 	
December 31, 2014	 	43	 	9	 	45	 	
December 31, 2015	 	50	 	10	 	52	 	
December 31, 2016	 	64	 	13	 	66	 	
Proved undeveloped reserves(1)	 	 	 	 	 	 	 	
December 31, 2014	 	30	 	6	 	31	 	
December 31, 2015	 	24	 	4	 	25	 	
December 31, 2016	 	10	 	2	 	11	 	

 	(1)	 	The sum of proved developed reserves and proved undeveloped reserves may not add to net proved developed and undeveloped reserves as a result of rounding.	

 	(2)	 	Discoveries are related to the TEN fields being moved from unproved to proved during 2014.	
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 	(3)	 	The increase in proved reserves is a result of a 3 MMBbl increase associated with in‑fill drilling results and an 8 MMBbl increase associated with field performance.	

 	(4)	 	The increase in proved reserves is a result of a 2 MMBbl increase associated with in-fill drilling results and a 10 MMBbl increase associated with field performance for Jubilee partially offset by 2 MMBbl of negative revisions to the TEN fields due to decreased pricing.	

 	(5)	 	The increase in proved reserves is a result of an 8 MMBbl increase associated with positive revisions to the TEN fields as a result of the completion of seven wells along with the initiation of TEN production partially offset by 1 MMBbl of negative revisions to the Jubilee Field due to decreased pricing.	
Net proved reserves were calculated utilizing the twelve month unweighted arithmetic average of the first‑day‑of‑the‑month oil price for each month for Brent crude in the period January through December 2016. The average 2016 Brent crude price of $42.90 per barrel is adjusted for crude handling, transportation fees, quality, and a regional price differential. Based on the crude quality, these adjustments are estimated to be $0.06 per barrel for Jubilee; therefore, the adjusted oil price is $42.96 per barrel for Jubilee. TEN was not adjusted as it does not currently have any production to estimate a differential. This oil price is held constant throughout the lives of the properties. There is no gas price used because gas reserves are consumed in operations as fuel.
Proved oil and gas reserves are defined by the SEC Rule 4.10(a) of Regulation S‑X as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recovered under current economic conditions, operating methods, and government regulations. Inherent uncertainties exist in estimating proved reserve quantities, projecting future production rates and timing of development expenditures.
Capitalized Costs Related to Oil and Gas Activities
The following table presents aggregate capitalized costs related to oil and gas activities:
 	 	 	 	 	 	 	 	 	 	 	
 	    	Ghana	    	Other(1)	    	Total	 	
 	 	(In thousands)	 	
As of  December 31, 2016	 	 	 	 	 	 	 	 	 	 	
Unproved properties	 	$	347,950	 	$	571,106	 	$	919,056	 	
Proved properties	 	 	2,771,779	 	 	 —	 	 	2,771,779	 	
 	 	 	3,119,729	 	 	571,106	 	 	3,690,835	 	
Accumulated depletion	 	 	(989,946)	 	 	 —	 	 	(989,946)	 	
Net capitalized costs	 	$	2,129,783	 	$	571,106	 	$	2,700,889	 	
As of  December 31, 2015	 	 	 	 	 	 	 	 	 	 	
Unproved properties	 	$	264,460	 	$	329,050	 	$	593,510	 	
Proved properties	 	 	2,579,158	 	 	 —	 	 	2,579,158	 	
 	 	 	2,843,618	 	 	329,050	 	 	3,172,668	 	
Accumulated depletion	 	 	(858,442)	 	 	 —	 	 	(858,442)	 	
Net capitalized costs	 	$	1,985,176	 	$	329,050	 	$	2,314,226	 	

 	(1)	 	Includes Africa, excluding Ghana, Europe and South America.	
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Costs Incurred in Oil and Gas Activities
The following table reflects total costs incurred, both capitalized and expensed, for oil and gas property acquisition, exploration, and development activities for the year.
 	 	 	 	 	 	 	 	 	 	 	
 	 	Ghana	 	Other(1)	 	Total	 	
 	 	(In thousands)	 	
Year ended  December 31, 2016	    	 	    	    	 	    	    	 	    	 	
Property acquisition:	 	 	 	 	 	 	 	 	 	 	
Unproved	 	$	 —	 	$	17,322	 	$	17,322	 	
Proved	 	 	 —	 	 	 —	 	 	 —	 	
Exploration	 	 	11,871	 	 	425,229	 	 	437,100	 	
Development	 	 	265,451	 	 	 —	 	 	265,451	 	
Total costs incurred	 	$	277,322	 	$	442,551	 	$	719,873	 	
Year ended  December 31, 2015	 	 	 	 	 	 	 	 	 	 	
Property acquisition:	 	 	 	 	 	 	 	 	 	 	
Unproved	 	$	 —	 	$	6,250	 	$	6,250	 	
Proved	 	 	 —	 	 	 —	 	 	 —	 	
Exploration(2)	 	 	12,441	 	 	367,196	 	 	379,637	 	
Development	 	 	462,066	 	 	 —	 	 	462,066	 	
Total costs incurred	 	$	474,507	 	$	373,446	 	$	847,953	 	
Year ended  December 31, 2014	 	 	 	 	 	 	 	 	 	 	
Property acquisition:	 	 	 	 	 	 	 	 	 	 	
Unproved	 	$	 —	 	$	 —	 	$	 —	 	
Proved	 	 	 —	 	 	 —	 	 	 —	 	
Exploration(3)	 	 	62,813	 	 	167,381	 	 	230,194	 	
Development	 	 	316,738	 	 	 —	 	 	316,738	 	
Total costs incurred	 	$	379,551	 	$	167,381	 	$	546,932	 	

 	(1)	 	Includes Africa, excluding Ghana, Europe and South America.	

 	(2)	 	Does not include reimbursement of costs associated with exploration expenses incurred in prior years which resulted in a $24.7 million gain on sale in 2015.	

 	(3)	 	Does not include reimbursement of costs associated with exploration expenses incurred in prior years which resulted in a $23.8 million gain on sale in 2014.	
Standardized Measure for Discounted Future Net Cash Flows
The following table provides projected future net cash flows based on the twelve month unweighted arithmetic average of the first‑day‑of‑the‑month oil price for Brent crude in the period January through December 2016. The average 2016 Brent crude price of $42.90 per barrel is adjusted for crude handling, transportation fees, quality, and a regional price differential. Based on the crude quality, these adjustments are estimated to be $0.06 per barrel for the Jubilee Field; therefore, the adjusted oil price is $42.96 per barrel for Jubilee. As the TEN fields recently started production, we do not have sufficient historical information to estimate the differential. However, we expect the differential to be consistent with the Jubilee Field. Since the Jubilee Field is currently at a premium, we elected to use a $0.00 differential to be conservative for the TEN fields, therefore the price utilized for the TEN fields is $42.90.
Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on market conditions that occur.
The projection should not be interpreted as representing the current value to Kosmos. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. Kosmos’ investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on a wide range of different price and cost assumptions.
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The standardized measure is intended to provide a better means to compare the value of Kosmos’ proved reserves at a given time with those of other oil producing companies than is provided by comparing raw proved reserve quantities.
 	 	 	 	 	
 	    	Ghana	 	
 	 	(In millions)	 	
At December 31, 2016	 	 	 	 	
Future cash inflows	 	$	3,204	 	
Future production costs	 	 	(1,437)	 	
Future development costs	 	 	(428)	 	
Future Ghanaian tax expenses(1)	 	 	(228)	 	
Future net cash flows	 	 	1,111	 	
10% annual discount for estimated timing of cash flows	 	 	(265)	 	
Standardized measure of discounted future net cash flows	 	$	846	 	
At December 31, 2015	 	 	 	 	
Future cash inflows	 	$	3,998	 	
Future production costs	 	 	(1,362)	 	
Future development costs	 	 	(679)	 	
Future Ghanaian tax expenses(1)	 	 	(411)	 	
Future net cash flows	 	 	1,546	 	
10% annual discount for estimated timing of cash flows	 	 	(377)	 	
Standardized measure of discounted future net cash flows	 	$	1,169	 	
At December 31, 2014	 	 	 	 	
Future cash inflows	 	$	7,412	 	
Future production costs	 	 	(1,466)	 	
Future development costs	 	 	(1,051)	 	
Future Ghanaian tax expenses(1)	 	 	(1,543)	 	
Future net cash flows	 	 	3,352	 	
10% annual discount for estimated timing of cash flows	 	 	(969)	 	
Standardized measure of discounted future net cash flows	 	$	2,383	 	

 	(1)	 	The Company is a tax exempted company incorporated pursuant to the laws of Bermuda. The Company has not been and does not expect to be subject to future income tax expense related to its proved oil and gas reserves levied at a corporate parent level. Accordingly, the Company’s Standardized Measure for the years ended December 31, 2016, 2015 and 2014, respectively, only reflect the effects of future tax expense levied at an asset level (in the Company’s case, future Ghanaian tax expense).	
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Changes in the Standardized Measure for Discounted Cash Flows
 	 	 	 	 	
 	    	Ghana	 	
 	 	(In millions)	 	
Balance at December 31, 2013	 	$	2,237	 	
Sales and transfers 2014	 	 	(756)	 	
Net changes in prices and costs	 	 	451	 	
Previously estimated development costs incurred during the period	 	 	(291)	 	
Net changes in development costs	 	 	115	 	
Revisions of previous quantity estimates	 	 	(151)	 	
Changes in production timing	 	 	690	 	
Net changes in Ghanaian tax expenses(1)	 	 	(44)	 	
Accretion of discount	 	 	306	 	
Changes in timing and other	 	 	(174)	 	
Balance at December 31, 2014	 	$	2,383	 	
Sales and transfers 2015	 	 	(341)	 	
Net changes in prices and costs	 	 	(2,842)	 	
Previously estimated development costs incurred during the period	 	 	417	 	
Net changes in development costs	 	 	6	 	
Revisions of previous quantity estimates	 	 	375	 	
Net changes in Ghanaian tax expenses(1)	 	 	802	 	
Accretion of discount	 	 	341	 	
Changes in timing and other	 	 	28	 	
Balance at December 31, 2015	 	$	1,169	 	
Sales and transfers 2016	 	 	(191)	 	
Net changes in prices and costs	 	 	(653)	 	
Previously estimated development costs incurred during the period	 	 	225	 	
Net changes in development costs	 	 	4	 	
Revisions of previous quantity estimates	 	 	65	 	
Net changes in Ghanaian tax expenses(1)	 	 	143	 	
Accretion of discount	 	 	145	 	
Changes in timing and other	 	 	(61)	 	
Balance at December 31, 2016	 	$	846	 	

 	(1)	 	The Company is a tax exempted company incorporated pursuant to the laws of Bermuda. The Company has not been and does not expect to be subject to future income tax expense related to its proved oil and gas reserves levied at a corporate parent level. Accordingly, the Company’s Standardized Measure for the years ended December 31, 2016, 2015 and 2014, respectively, only reflect the effects of future tax expense levied at an asset level (in the Company’s case, future Ghanaian tax expense).	
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KOSMOS ENERGY LTD.
Supplemental Quarterly Financial Information (Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Quarter Ended	 	
 	    	March 31,	    	June 30,	    	September 30,	   
 	December 31,	 	
 	 	(In thousands, except per share data)	 	
2016	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues and other income	 	$	62,133	 	$	45,676	 	$	66,629	 	$	210,917	 	
Costs and expenses	 	 	123,148	 	 	169,544	 	 	118,890	 	 	268,337	 	
Net loss	 	 	(58,993)	 	 	(108,324)	 	 	(59,763)	 	 	(56,700)	 	
Net loss per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic(1)	 	 	(0.15)	 	 	(0.28)	 	 	(0.15)	 	 	(0.15)	 	
Diluted(1)	 	 	(0.15)	 	 	(0.28)	 	 	(0.15)	 	 	(0.15)	 	
2015	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues and other income	 	$	132,557	 	$	121,813	 	$	95,318	 	$	121,868	 	
Costs and expenses	 	 	185,767	 	 	171,615	 	 	(27,165)	 	 	55,903	 	
Net income (loss)	 	 	(78,909)	 	 	(75,192)	 	 	60,265	 	 	24,000	 	
Net income (loss) per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic(1)	 	 	(0.21)	 	 	(0.20)	 	 	0.16	 	 	0.06	 	
Diluted(1)	 	 	(0.21)	 	 	(0.20)	 	 	0.15	 	 	0.06	 	

 	(1)	 	The sum of the quarterly earnings per share information may not add to the annual earnings per share information as a result of rounding.	
 
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Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.  Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a‑15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. However, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2016, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure.
Evaluation of Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control has been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. All internal control systems have inherent limitations, including the possibility of human error and the possible circumvention of or overriding of controls. The design of an internal control system is also based in part upon assumptions and judgments made by management. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that internal control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this report based on the framework in “Internal Control—Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
Ernst & Young LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this annual report on Form 10‑K, has issued an attestation report on the effectiveness of internal control over financial reporting as of December 31, 2016 which is included in “Item 8. Financial Statements and Supplementary Data.”
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Item 9B.  Other Information
Disclosures Required Pursuant to Section 13(r) of the Securities Exchange Act of 1934
Under the Iran Threat Reduction and Syria Human Rights Act of 2012, which added Section 13(r) of the Exchange Act, we are required to include certain disclosures in our periodic reports if we or any of our “affiliates” (as defined in Rule 12b‑2 under the Exchange Act) knowingly engaged in certain specified activities during the period covered by the report. Because the Securities and Exchange Commission (“SEC”) defines the term “affiliate” broadly, it includes any entity controlled by us as well as any person or entity that controls us or is under common control with us (“control” is also construed broadly by the SEC).
We are not presently aware that we and our consolidated subsidiaries have knowingly engaged in any transaction or dealing reportable under Section 13(r) of the Exchange Act during the fiscal quarter ended December 31, 2016. In addition, except as described below, at the time of filing this annual report on Form 10‑K, we are not aware of any such reportable transactions or dealings by companies that may be considered our affiliates as to whether they have knowingly engaged in any such reportable transactions or dealings during such period. Upon the filing of periodic reports by such other companies for the fiscal quarter or fiscal year ended December 31, 2016, as the case may be, additional reportable transactions may be disclosed by such companies.
As of December 31, 2016, funds affiliated with The Blackstone Group (“Blackstone”) held approximately 25% of our outstanding common shares, and funds affiliated with Warburg Pincus (“Warburg Pincus”) held approximately 31% of our outstanding common shares. We are also a party to a shareholders agreement with Blackstone and Warburg Pincus pursuant to which, among other things, Blackstone and Warburg Pincus each currently has the right to designate three members of our board of directors. Accordingly, each of Blackstone and Warburg Pincus may be deemed an “affiliate” of us, both currently and during the fiscal quarter ended December 31, 2016.
Disclosure relating to Warburg Pincus and its affiliates
Warburg Pincus informed us of (i) the information reproduced below (the “SAMIH Disclosure”) regarding Santander Asset Management Investment Holdings Limited (“SAMIH. SAMIH is a company that may be considered affiliate of Warburg Pincus. Because we and SAMIH may be deemed to be controlled by Warburg Pincus, we may be considered an “affiliate” of each of SAMIH for the purposes of Section 13(r) of the Exchange Act.
SAMIH Disclosure:
Quarter ended December 31, 2016
“Santander UK plc (“Santander UK”) holds two savings accounts and one current account for two customers resident in the United Kingdom (“UK”) who are currently designated by the United States (“US”) under the Specially Designated Global Terrorist (“SDGT”) sanctions program. Revenues and profits generated by Santander UK on these accounts in the year ended December 31, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.
Santander UK held a savings account for a customer resident in the UK who is currently designated by the US under the SDGT sanctions program. The savings account was closed on July 26, 2016. Revenue generated by Santander UK on this account in the year ended December 31, 2016 was negligible relative to the overall revenues and profits of Banco Santander SA.
Santander UK held a current account for a customer resident in the UK who is currently designated by the US under the SDGT sanctions program. The current account was closed on December 22, 2016. Revenue generated by Santander UK on this account in the year ended December 31, 2016 was negligible relative to the overall revenues and profits of Banco Santander SA.
Santander UK holds two frozen current accounts for two UK nationals who are designated by the US under the SDGT sanctions program. The accounts held by each customer have been frozen since their designation and have remained frozen through the year ended December 31, 2016. The accounts are in arrears (£1,844.73 in debit combined) and are
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currently being managed by Santander UK Collections & Recoveries department. Revenues and profits generated by Santander UK on these accounts in the year ended December 31, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.
During the year ended December 31, 2016, Santander UK had an OFAC match on a power of attorney account. A party listed on the account is currently designated by the US under the SDGT sanctions program and the Iranian Financial Sanctions Regulations (“IFSR”). The power of attorney was removed from the account on July 29, 2016. During the year ended December 31, 2016, related revenues and profits generated by Santander UK were negligible relative to the overall revenues and profits of Banco Santander SA.
An Iranian national, resident in the UK, who is currently designated by the US under the IFSR and the Weapons of Mass Destruction Proliferators Sanctions Regulations, held a mortgage with Santander UK that was issued prior to such designation. The mortgage account was redeemed and closed on April 13, 2016. No further drawdown has been made (or would be allowed) under this mortgage although Santander UK continued to receive repayment instalments prior to redemption. Revenues generated by Santander UK on this account in the year ended December 31, 2016 were negligible relative to the overall revenues of Banco Santander SA. The same Iranian national also held two investment accounts with Santander ISA Managers Limited. The funds within both accounts were invested in the same portfolio fund. The accounts remained frozen until the investments were closed on May 12, 2016 and bank checks issued to the customer. Revenues generated by Santander UK on these accounts in the year ended December 31, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.
In addition, during the year ended December 31, 2016, Santander UK held a basic current account for an Iranian national, resident in the UK, previously designated under the Iranian Transactions and Sanctions Regulations. The account was closed in September 2016. Revenues generated by Santander UK on this account in the year ended December 31, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.”
The SAMIH Disclosure relates solely to activities conducted by SAMIH and do not relate to any activities conducted by us. We have no involvement in or control over the activities of SAMIH, any of its predecessor companies or any of its subsidiaries. Other than as described above, we have no knowledge of the activities of SAMIH with respect to transactions with Iran, and we have not participated in the preparation of the SAMIH Disclosure. We have not independently verified the SAMIH Disclosure, are not representing to the accuracy or completeness of the SAMIH Disclosure and undertake no obligation to correct or update the SAMIH Disclosure.
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PART III
Item 10.  Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the 2016 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2016.
Item 11.  Executive Compensation
The information required by this item is incorporated herein by reference to the 2016 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2016.
Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matter s
The information required by this item is incorporated herein by reference to the 2016 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2016.
Item 13.  Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2016 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2016.
Item 14.  Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2016 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2016.
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PART IV
Item 15.  Exhibits, Financial Statement Schedules
 	(a)	 	The following documents are filed as part of this report:	
(1)Financial statements
The financial statements filed as part of the Annual Report on Form 10‑K are listed in the accompanying index to consolidated financial statements in Item 8, Financial Statements and Supplementary Data.
(2)Financial statement schedules
Schedule I—Condensed Parent Company Financial Statements
Under the terms of agreements governing the indebtedness of subsidiaries of Kosmos Energy Ltd. for 2016, 2015 and 2014 (collectively “KEL,” the “Parent Company”), such subsidiaries are restricted from making dividend payments, loans or advances to KEL. Schedule I of Article 5‑04 of Regulation S‑X requires the condensed financial information of the Parent Company to be filed when the restricted net assets of consolidated subsidiaries exceed 25 percent of consolidated net assets as of the end of the most recently completed fiscal year.
The following condensed parent‑only financial statements of KEL have been prepared in accordance with Rule 12‑04, Schedule I of Regulation S‑X and included herein. The Parent Company’s 100% investment in its subsidiaries has been recorded using the equity basis of accounting in the accompanying condensed parent‑only financial statements. The condensed financial statements should be read in conjunction with the consolidated financial statements of Kosmos Energy Ltd. and subsidiaries and notes thereto.
The terms “Kosmos,” the “Company,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise. Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or shareholders equity.
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KOSMOS ENERGY LTD.
CONDENSED PARENT COMPANY BALANCE SHEETS
(In thousands, except share data)
 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	    	2016	    	2015	 	
Assets	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	1,092	 	$	74,683	 	
Receivables from subsidiaries	 	 	14,131	 	 	 —	 	
Prepaid expenses and other	 	 	417	 	 	469	 	
Total current assets	 	 	15,640	 	 	75,152	 	
Investment in subsidiaries at equity	 	 	1,580,459	 	 	1,759,419	 	
Deferred financing costs, net of accumulated amortization of $11,213 and $8,475, respectively	 	 	5,248	 	 	7,986	 	
Total assets	 	$	1,601,347	 	$	1,842,557	 	
Liabilities and shareholders’ equity	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	
Accounts payable	 	$	13	 	$	11	 	
Accounts payable to subsidiaries	 	 	 —	 	 	1,070	 	
Accrued liabilities	 	 	17,939	 	 	17,629	 	
Total current liabilities	 	 	17,952	 	 	18,710	 	
Long-term debt	 	 	502,196	 	 	498,334	 	
Shareholders’ equity:	 	 	 	 	 	 	 	
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2016 and December 31, 2015	 	 	 —	 	 	 —	 	
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 395,859,061 and 393,902,643 issued at December 31, 2016 and 2015, respectively	 	 	3,959	 	 	3,939	 	
Additional paid-in capital	 	 	1,975,247	 	 	1,933,189	 	
Accumulated deficit	 	 	(850,410)	 	 	(564,686)	 	
Treasury stock, at cost, 9,101,395 and 8,812,054 shares at December 31, 2016 and 2015, respectively	 	 	(47,597)	 	 	(46,929)	 	
Total shareholders’ equity	 	 	1,081,199	 	 	1,325,513	 	
Total liabilities and shareholders’ equity	 	$	1,601,347	 	$	1,842,557	 	
 
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KOSMOS ENERGY LTD.
CONDENSED PARENT COMPANY STATEMENTS OF OPERATIONS
(In thousands)
 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	    	2016	    	2015	    	2014	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenue	 	$	 —	 	$	 —	 	$	 —	 	
Total revenues and other income	 	 	 —	 	 	 —	 	 	 —	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	
General and administrative	 	 	48,542	 	 	85,103	 	 	88,789	 	
General and administrative recoveries—related party	 	 	(40,047)	 	 	(72,543)	 	 	(78,880)	 	
Interest and other financing costs, net	 	 	55,253	 	 	49,572	 	 	20,559	 	
Other expenses, net	 	 	1	 	 	240	 	 	1,319	 	
Equity in (earnings) losses of subsidiaries	 	 	220,031	 	 	7,464	 	 	(311,157)	 	
Total costs and expenses	 	 	283,780	 	 	69,836	 	 	(279,370)	 	
Income (loss) before income taxes	 	 	(283,780)	 	 	(69,836)	 	 	279,370	 	
Income tax expense	 	 	 —	 	 	 —	 	 	 —	 	
Net income (loss)	 	$	(283,780)	 	$	(69,836)	 	$	279,370	 	
 
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KOSMOS ENERGY LTD.
CONDENSED PARENT COMPANY STATEMENTS OF CASH FLOWS
(In thousands)
 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	    	2016	    	2015	    	2014	 	
Operating activities	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	(283,780)	 	$	(69,836)	 	$	279,370	 	
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:	 	 	 	 	 	 	 	 	 	 	
Equity in (earnings) losses of subsidiaries	 	 	220,031	 	 	7,464	 	 	(311,157)	 	
Equity-based compensation	 	 	40,423	 	 	75,267	 	 	79,741	 	
Amortization	 	 	3,070	 	 	3,190	 	 	3,188	 	
Other	 	 	3,530	 	 	2,704	 	 	269	 	
Changes in assets and liabilities:	 	 	 	 	 	 	 	 	 	 	
(Increase) decrease in prepaid expenses and other	 	 	52	 	 	(34)	 	 	89	 	
(Increase) decrease due to/from related party	 	 	(15,201)	 	 	1,224	 	 	(3,915)	 	
Increase in accounts payable and accrued liabilities	 	 	312	 	 	2,721	 	 	10,593	 	
Net cash provided by (used in) operating activities	 	 	(31,563)	 	 	22,700	 	 	58,178	 	
Investing activities	 	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	 	 	(40,047)	 	 	(293,545)	 	 	(208,879)	 	
Net cash used in investing activities	 	 	(40,047)	 	 	(293,545)	 	 	(208,879)	 	
Financing activities	 	 	 	 	 	 	 	 	 	 	
Net proceeds from issuance of senior secured notes	 	 	 —	 	 	206,774	 	 	294,000	 	
Purchase of treasury stock	 	 	(1,981)	 	 	(18,110)	 	 	(11,096)	 	
Deferred financing costs	 	 	 —	 	 	(9,030)	 	 	(1,401)	 	
Net cash provided by (used in) financing activities	 	 	(1,981)	 	 	179,634	 	 	281,503	 	
Net increase (decrease) in cash and cash equivalents	 	 	(73,591)	 	 	(91,211)	 	 	130,802	 	
Cash and cash equivalents at beginning of period	 	 	74,683	 	 	165,894	 	 	35,092	 	
Cash and cash equivalents at end of period	 	$	1,092	 	$	74,683	 	$	165,894	 	

 

 

 
 
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Schedule II
Kosmos Energy Ltd.
Valuation and Qualifying Accounts
For the Years Ended December 31, 2016, 2015 and 2014
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Additions	 	 	 	 	 	 	 	
 	 	 	 	 	Charged to	 	Charged	 	Deductions	 	 	 	 	
 	 	Balance	 	Costs and	 	To Other	 	From	 	Balance	 	
Description	 	January 1,	 	Expenses	 	Accounts	 	Reserves	 	December 31,	 	
2016	 	 	    	   	 	    	 	 	    	   	 	    	 	 	    	 	
Allowance for doubtful receivables	 	$	 —	 	$	574	 	$	 —	 	$	 —	 	$	574	 	
Allowance for deferred tax assets	 	$	116,541	 	$	(29,024)	 	$	 —	 	$	 —	 	$	87,517	 	
2015	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Allowance for doubtful receivables	 	$	 —	 	$	 —	 	$	 —	 	$	 —	 	$	 —	 	
Allowance for deferred tax assets	 	$	75,941	 	$	40,600	 	$	 —	 	$	 —	 	$	116,541	 	
2014	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Allowance for doubtful receivables	 	$	 —	 	$	 —	 	$	 —	 	$	 —	 	$	 —	 	
Allowance for deferred tax assets	 	$	59,540	 	$	16,401	 	$	 —	 	$	 —	 	$	75,941	 	

Schedules other than Schedule I and Schedule II have been omitted because they are not applicable or the required information is presented in the consolidated financial statements or the notes to consolidated financial statements.
(3)Exhibits
See “Index to Exhibits” on page 141 for a description of the exhibits filed as part of this report.
 
Item 16.  Form 10-K Summary
None
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 	 	 	
 	KOSMOS ENERGY LTD.	
 	 	 	
Date: February 27, 2017	By:	/s/ Thomas P. Chambers
Thomas P. Chambers
Senior Vice President and Chief Financial Officer	
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Signature	 	 	 	 	Title	 	 	 	 	Date	 	 	
 	 	 	
/s/ Andrew G. Inglis
Andrew G. Inglis	Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)	February 27, 2017	
 	 	 	
/s/ Brian F. Maxted
Brian F. Maxted	Director and Chief Exploration Officer	February 27, 2017	
 	 	 	
/s/ Thomas P. Chambers
Thomas P. Chambers	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 27, 2017	
 	 	 	
/s/ Paul M. Nobel
Paul M. Nobel	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 27, 2017	
 	 	 	
/s/ Yves-Louis Darricarrére
Yves-Louis Darricarrére	Director 	February 27, 2017	
 	 	 	
/s/ Sir Richard B. Dearlove
Sir Richard B. Dearlove	Director	February 27, 2017	
 	 	 	
/s/ David I. Foley
David I. Foley	Director	February 27, 2017	
 	 	 	
/s/ David B. Krieger
David B. Krieger	Director	February 27, 2017	
 	 	 	
/s/ Joseph P. Landy
Joseph P. Landy	Director	February 27, 2017	
 	 	 	
/s/ Prakash A. Melwani
Prakash A. Melwani	Director	February 27, 2017	
 	 	 	
/s/ Adebayo O. Ogunlesi
Adebayo O. Ogunlesi	Director	February 27, 2017	
 	 	 	
/s/ Chris Tong
Chris Tong	Director	February 27, 2017	
 	 	 	
/s/ Christopher A. Wright
Christopher A. Wright	Director	February 27, 2017	
 
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INDEX OF EXHIBITS
 	 	
Exhibit
Number	Description of Document	
 	Governing Documents	
3.1 	Certificate of Incorporation of the Company (filed as Exhibit 3.1 to the Company’s Registration Statement on Form S‑1/A filed March 23, 2011 (File No. 333‑171700), and incorporated herein by reference).	
3.2 	Memorandum of Association of the Company (filed as Exhibit 3.2 to the Company’s Registration Statement on Form S‑1/A filed March 23, 2011 (File No. 333‑171700), and incorporated herein by reference).	
3.3 	Bye‑laws of the Company (filed as Exhibit 4 to the Company’s Registration Statement on Form 8‑A filed May 6, 2011 (File No. 001‑35167), and incorporated herein by reference).	
4.1 	Specimen share certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S‑1/A filed April 25, 2011 (File No. 333‑171700), and incorporated herein by reference).	
 	Operating Agreements	
 	Ghana	
10.1 	Petroleum Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 22, 2004 among the GNPC, Kosmos Ghana and the E.O. Group (filed as Exhibit 10.1 to the Company’s Registration Statement on Form S‑1/A filed March 3, 2011 (File No. 333‑171700), and incorporated herein by reference).	
10.2 	Operating Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 27, 2004 between Kosmos Ghana and E.O. Group (filed as Exhibit 10.2 to the Company’s Registration Statement on Form S‑1/A filed March 3, 2011 (File No. 333‑171700), and incorporated herein by reference).	
10.3 	Petroleum Agreement in respect of the Deepwater Tano Contract Area dated March 10, 2006 among GNPC, Tullow Ghana, Sabre and Kosmos Ghana (filed as Exhibit 10.3 to the Company’s Registration Statement on Form S‑1/A filed March 3, 2011 (File No. 333‑171700), and incorporated herein by reference).	
10.4 	Joint Operating Agreement in respect of the Deepwater Tano Contract Area, Offshore Ghana dated August 14, 2006, among Tullow Ghana, Sabre Oil and Gas Limited, and Kosmos Ghana (filed as Exhibit 10.4 to the Company’s Registration Statement on Form S‑1/A filed March 3, 2011 (File No. 333‑171700), and incorporated herein by reference).	
10.5 	Assignment Agreement in respect of the Deepwater Tano Block dated September 1, 2006, among Anadarko WCTP and Kosmos Ghana (filed as Exhibit 10.5 to the Company’s Registration Statement on Form S‑1/A filed March 3, 2011 (File No. 333‑171700), and incorporated herein by reference).	
10.6 	Unitization and Unit Operating Agreement covering the Jubilee Field Unit located offshore the Republic of Ghana dated July 13, 2009, among GNPC, Tullow, Kosmos Ghana, Anadarko WCTP, Sabre and E.O. Group (filed as Exhibit 10.6 to the Company’s Registration Statement on Form S‑1/A filed March 3, 2011 (File No. 333‑171700), and incorporated herein by reference).	
10.7 	Settlement Agreement, dated December 18, 2010 among Kosmos Ghana, Ghana National Petroleum Corporation and the Government of the Republic of Ghana (filed as Exhibit 10.32 to the Company’s Registration Statement on Form S‑1/A filed April 14, 2011 (File No. 333‑171700), and incorporated herein by reference).	
 	Morocco	
10.8 	Petroleum Agreement Regarding the Exploration for Exploitation of Hydrocarbons among Office National Des Hydrocarbures Et Des Mines acting on behalf of the Kingdom of Morocco, Kosmos Energy Deepwater Morocco and Canamens Energy Morocco SARL in the area of interest named “Essaouira Offshore” dated September 9, 2011 (filed as Exhibit 10.12 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30, 2013, and incorporated herein by reference).	
10.9 	Deed of Assignment in Petroleum Agreement for the Exploration for and Exploitation of Hydrocarbons in the zone of interest named “Essaouira Offshore” between Canamens Energy Morocco SARL and Kosmos Energy Deepwater Morocco dated December 19, 2012 (filed as Exhibit 10.13 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30, 2013, and incorporated herein by reference).	
10.10 	Petroleum Agreement Regarding the Exploration for an Exploitation of Hydrocarbons between Office National Des Hydrocarbures Et Des Mines acting on behalf of the State and Kosmos Energy Maroc Mer Profonde and Capricorn Exploration and Development Company Limited in the area of interest named “Boujdour Maritime” dated May 25, 2016 (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30, 2016, and incorporated herein by reference).	
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Exhibit
Number	Description of Document	
 	Sao Tome and Principe	
10.11 	Production Sharing Contract relating to Block 5 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe and Equator Exploration STP Block 5 Limited dated April 18, 2012 (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.12 	Amendment No. 1, dated November 24, 2014, to the Production Sharing Contract relating to Block 5 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe and Equator Exploration STP Block 5 Limited dated April 18, 2012 (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.13 	Amendment No. 2, dated September 15, 2015, to the Production Sharing Contract relating to Block 5 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe and Equator Exploration STP Block 5 Limited dated April 18, 2012 (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.14 	Deed of Assignment relating to Block 5 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe, Equator Exploration STP Block 5 Limited and Kosmos Energy Sao Tome and Principe dated February 19, 2016 (filed as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.15 	Amendment No. 3, dated February 19, 2016, to the Production Sharing Contract relating to Block 5 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe, Equator Exploration STP Block 5 Limited and Kosmos Energy Sao Tome and Principe dated April 18, 2012 (filed as Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.16*	Deed of Assignment relating to Block 5 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe, Equator Exploration STP Block 5 Limited, Galp Energia Săo Tomé e Príncipe, Unipessoal, LDA and Kosmos Energy Sao Tome and Principe dated December 13, 2016.	
10.17 	Production Sharing Contract relating to Block 6 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe and Galp Energia Săo Tomé e Príncipe, Unipessoal, LDA dated October 26, 2015 (filed as Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.18 	Addendum, dated November 9, 2015, to the Production Sharing Contract relating to Block 6 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe and Galp Energia Săo Tomé e  Príncipe, Unipessoal, LDA dated October 26, 2015 (filed as Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.19 	Deed of Assignment relating to Block 6 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe, Galp Energia Săo Tomé e Príncipe, Unipessoal, LDA and Kosmos Energy Sao Tome and Principe dated November 9, 2015 (filed as Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.20 	Production Sharing Contract relating to Block 11 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe and ERHC Energy EEZ, LDA dated July 23, 2014 (filed as Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.21 	Deed of Assignment relating to Block 11 Offshore Sao Tome between EHRC Energy EEZ, LDA and Kosmos Energy Sao Tome and Principe dated October 16, 2015 (filed as Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.22 	First Addendum, dated December 17, 2015, to the Production Sharing Contract relating to Block 11 Offshore Sao Tome between the Democratic Republic of Sao Tome and Kosmos Energy Sao Tome and Principe dated July 23, 2014 (filed as Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.23*	Deed of Assignment relating to Block 11 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe, Galp Energia Săo Tomé e Príncipe, Unipessoal, LDA and Kosmos Energy Sao Tome and Principe dated December 13, 2016.	
142

 
Table of Contents
 	 	
Exhibit
Number	Description of Document	
10.24 	Production Sharing Contract relating to Block 12 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe and Equator Exploration STP Block 12 Limited dated February 19, 2016 (filed as Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.25 	Deed of Assignment relating to Block 12 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe, Equator Exploration STP Block 12 Limited and Kosmos Energy Sao Tome and Principe dated March 31, 2016 (filed as Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.26 	First Amendment, dated March 31, 2016, to the Production Sharing Contract between the Democratic Republic of Sao Tome and Principe, Equator Exploration STP Block 12 Limited and Kosmos Energy Sao Tome and Principe dated February 19, 2016 (filed as Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, and incorporated herein by reference).	
10.27*	Deed of Assignment relating to Block 12 Offshore Sao Tome between the Democratic Republic of Sao Tome and Principe, Equator Exploration STP Block 12 Limited, Galp Energia Săo Tomé e Príncipe, Unipessoal, LDA and Kosmos Energy Sao Tome and Principe dated December 13, 2016.	
 	Senegal	
10.28 	Hydrocarbon Exploration and Production Sharing Contract for the Cayar Offshore Profond between the Republic of Senegal and Petro‑Tim Limited and Societe des Petroles du Senegal dated January 17, 2012 (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30, 2014, and incorporated herein by reference).	
10.29 	Hydrocarbon Exploration and Production Sharing Contract for the Saint Louis Offshore Profond between the Republic of Senegal and Petro‑Tim Limited and Societe des Petroles du Senegal dated January 17, 2012 (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30, 2014, and incorporated herein by reference).	
10.30 	Deed of Transfer between La Societe Des Petroles Du Senegal (Petrosen), Timis Corporation Limited and Kosmos Energy Senegal concerning the Hydrocarbons Exploration and Production Sharing Contracts and Joint Operating Agreements covering the Cayar Offshore and Saint Louis Offshore Permits dated August 25, 2014 (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30, 2014, and incorporated herein by reference).	
10.31*	Sale and Purchase Agreement relating to the sale and purchase of shares in Kosmos BP Senegal Limited (formerly Normandy Ventures Limited) between BP Indonesia Oil Terminal Investment Limited and Kosmos Energy Senegal dated December 15, 2016.	
 	Suriname	
10.32 	Production Sharing Contract for Petroleum Exploration, Development and Production relating to Block 42 Offshore Suriname between Staatsolie Maatshappij Suriname N.V. and Kosmos Energy Suriname dated December 13, 2011 (filed as Exhibit 10.20 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30, 2013, and incorporated herein by reference).	
10.33 	Production Sharing Contract for Petroleum Exploration, Development and Production relating to Block 45 Offshore Suriname between Staatsolie Maatshappij Suriname N.V. and Kosmos Energy Suriname dated December 13, 2011 (filed as Exhibit 10.21 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30, 2013, and incorporated herein by reference).	
10.34 	Deed of Assignment and Transfer relating to Blocks 42 and 45 Offshore Suriname between Kosmos Energy Suriname and Chevron Suriname Exploration Limited dated May 31, 2012 (filed as Exhibit 10.22 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30, 2013, and incorporated herein by reference).	
 	Mauritania	
10.35 	Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy Mauritania (Block C8) dated April 5, 2012 (filed as Exhibit 10.17 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30, 2013, and incorporated herein by reference).	
10.36 	Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy Mauritania (Bloc C12) dated April 5, 2012 (filed as Exhibit 10.18 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30, 2013, and incorporated herein by reference).	
143

 
Table of Contents
 	 	
Exhibit
Number	Description of Document	
10.37 	Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy Mauritania (Bloc C13) dated April 5, 2012 (filed as Exhibit 10.19 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended September 30, 2013, and incorporated herein by reference).	
10.38 	Deed of Novation and Assignment and Transfer dated March 25, 2015 between Kosmos Energy Mauritania, Chevron Mauritania Exploration Limited and SMHPM in relation to Block C8 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated March 25, 2015, and incorporated herein by reference).	
10.39 	Deed of Novation and Assignment and Transfer dated March 25, 2015 between Kosmos Energy Mauritania, Chevron Mauritania Exploration Limited and SMHPM in relation to Block C12 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated March 25, 2015, and incorporated herein by reference).	
10.40 	Deed of Novation and Assignment and Transfer dated March 25, 2015 between Kosmos Energy Mauritania, Chevron Mauritania Exploration Limited and SMHPM in relation to Block C13 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated March 25, 2015, and incorporated herein by reference).	
10.41*	Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy Mauritania (Bloc C16) dated October 11, 2016.	
10.42*	Farmout Agreement Relating to Blocks C6, C8, C12 and C13 Offshore Mauritania between BP Exploration (West Africa) Limited and Kosmos Energy Mauritania dated December 15, 2016.	
 	Drilling Rigs 	
10.43 	Deepwater Drilling Unit Contract Agreement, dated as of June 9, 2013, between Kosmos Energy Ventures and Alpha Offshore Drilling Services Company (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended June 30, 2013, and incorporated herein by reference).	
10.44 	Amendment No. 6 to Deepwater Drilling Unit Contract Agreement, dated September 29, 2015, between Kosmos Energy Ventures and Alpha Offshore Drilling Services Company (filed as Exhibit 1.1 to the Company’s Current Report on Form 8-K dated October 1, 2015, and incorporated herein by reference).	
 	Financing Agreements	
10.45 	Intercreditor Agreement, dated March 28, 2011 among BNP Paribas, Kosmos Finance International, Kosmos Operating, Kosmos International, Kosmos Development, Kosmos Ghana and the various financial institutions and others party thereto (filed as Exhibit 10.20 to the Company’s Registration Statement on Form S‑1/A filed April 25, 2011 (File No. 333‑171700), and incorporated herein by reference).	
10.46 	Facility Agreement, dated February 17, 2012, among Kosmos Energy Finance International, Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development, Kosmos Energy Ghana HC and International Finance Corporation (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended March 31, 2012, and incorporated herein by reference).	
10.47 	Deed of Transfer and Amendment, dated February 17, 2012, among Kosmos Energy Finance International, Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development, Kosmos Energy Ghana HC, BNP Paribas, Citibank N.A., Credit Suisse International, Société Générale London Branch and International Finance Corporation (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended March 31, 2012, and incorporated herein by reference).	
10.48 	Deed of Guarantee and Indemnity, dated as of November 23, 2012, among Kosmos Energy Ltd., and Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development, Kosmos Energy Ghana HC and Kosmos Energy Finance International, as Original Guarantors, and BNP Paribas, as Security and Intercreditor Agent (filed as Exhibit 10.29 to the Company’s Annual Report on Form 10‑K for the year ended December 31, 2012, and incorporated herein by reference).	
10.49 	Intercreditor Agreement, dated as of November 23, 2012, among Kosmos Energy Ltd., as HY Note Issuer and RCF Borrower, Kosmos Energy Finance International, as Original Senior Borrower, BNP Paribas, as Security Agent, Security and Intercreditor Agent and Proceeds Agent, and Standard Chartered Bank, as RCF Agent (filed as Exhibit 10.31 to the Company’s Annual Report on Form 10‑K for the year ended December 31, 2012, and incorporated herein by reference).	
10.50 	Multi‑Currency Revolving Letter of Credit Facility Agreement, dated as of July 3, 2013 and amended and restated on July 29, 2013, among Kosmos Energy Credit International, as the Original Borrower, Kosmos Energy Ltd., as the Original Guarantor, and Societe Generale, London Branch, as the Original Lender, Facility Agent, Security Agent and Account Bank (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended June 30, 2013, and incorporated herein by reference).	
144

 
Table of Contents
 	 	
Exhibit
Number	Description of Document	
10.51 	Charge on Cash Deposits and Account Bank Agreement, dated as of July 3, 2013, among Kosmos Energy Credit International and Societe Generale, London Branch, as Security Agent and Account Bank (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended June 30, 2013, and incorporated herein by reference).	
10.52 	Deed of Amendment and Restatement relating to the Revolving Credit Facility Agreement, dated March 14, 2014, among Kosmos Energy Ltd., as Original Borrower, certain of its subsidiaries listed therein, as Original Guarantors, Standard Chartered Bank, as Facility Agent, BNP Paribas, as Security and Intercreditor Agent, and the financial institutions listed therein, as Original Lenders (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended March 31, 2014, and incorporated herein by reference).	
10.53 	Amendment Letter, dated June 8, 2015, supplemental to and amending the Revolving Credit Facility Agreement, dated March 14, 2014, among Kosmos Energy Ltd., as Original Borrower, certain of its subsidiaries listed therein, as Original Guarantors, Standard Chartered Bank, as Facility Agent, BNP Paribas, as Security and Intercreditor Agent, and the financial institutions listed therein, as Original Lenders (filed as Exhibit 1.1 to the Company’s Current Report on Form 8-K dated June 8, 2015, and incorporated herein by reference).	
10.54 	Deed of Amendment and Restatement relating to the Facility Agreement and a Charge over Shares in Kosmos Energy Operating, dated March 14, 2014, among Kosmos Energy Finance International, as Original Borrower, Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development and Kosmos Energy Ghana HC, as Original Guarantors, Kosmos Energy Holdings, as Chargor, and BNP Paribas, as Facility Agent and Security Agent (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended March 31, 2014, and incorporated herein by reference).	
10.55 	Indenture, dated as of August 1, 2014, among the Company, Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development, Kosmos Energy Ghana HC and Kosmos Energy Finance International, Wilmington Trust, National Association, as trustee, transfer agent, registrar and paying agent and Banque Internationale à Luxembourg S.A., as Luxembourg listing agent, transfer agent and paying agent (including the Form of Notes) (filed as Exhibit 4.1 to the Company’s Current Report on Form 8‑K filed August 4, 2014 (File No. 001‑35167), and incorporated herein by reference).	
10.56 	KEL Intercreditor and Security Sharing Agreement, dated as of August 1, 2014, among the Company, BNP Paribas, as security and intercreditor agent, Standard Chartered Bank, as RCF Agent and Wilmington Trust, National Association, as trustee, transfer agent, registrar and paying agent (filed as Exhibit 4.2 to the Company’s Current Report on Form 8‑K filed August 4, 2014 (File No. 001‑35167), and incorporated herein by reference).	
 	Agreements with Shareholders and Directors	
10.57 	Form of Director Indemnification Agreement (filed as Exhibit 10.27 to the Company’s Registration Statement on Form S‑1/A filed April 14, 2011 (File No. 333‑171700), and incorporated herein by reference).	
10.58 	Shareholders Agreement, dated as of May 10, 2011, among Kosmos Energy Ltd. and the other parties signatory thereto (filed as Exhibit 9.1 to the Company’s Annual Report on Form 10‑K for the year ended December 31, 2012, and incorporated herein by reference).	
10.59 	Registration Rights Agreement, dated as of October 7, 2009, among Kosmos Energy Holdings and the other parties signatory thereto (filed as Exhibit 10.32 to the Company’s Annual Report on Form 10‑K for the year ended December 31, 2012, and incorporated herein by reference).	
10.60 	Joinder Agreement to the Registration Rights Agreement, dated as of May 10, 2011, among Kosmos Energy Ltd. and the other parties signatory thereto (filed as Exhibit 10.33 to the Company’s Annual Report on Form 10‑K for the year ended December 31, 2012, and incorporated herein by reference).	
10.61 	Amendment No. 1 to the Registration Rights Agreement, dated as of February 8, 2013, among Kosmos Energy Ltd. and the other parties signatory thereto (filed as Exhibit 10.34 to the Company’s Annual Report on Form 10‑K for the year ended December 31, 2012, and incorporated herein by reference).	
 	Management Contracts/Compensatory Plans or Arrangements	
10.62†	Long Term Incentive Plan (filed as Exhibit 99.1 to the Company’s Registration Statement on Form S‑8 filed May 16, 2011 (File No. 333‑174234), and incorporated herein by reference).	
145

 
Table of Contents
 	 	
Exhibit
Number	Description of Document	
10.63†	Long Term Incentive Plan (amended and restated as of January 23, 2015)  (filed as Exhibit 99 to the Company’s Registration Statement on Form S-8 filed October 2, 2015 (File No. 333-207259), and incorporated herein by reference).	
10.64*†	Long Term Incentive Plan (amended and restated as of January 23, 2017)	
10.65†	Annual Incentive Plan (filed as Exhibit 10.22 to the Company’s Registration Statement on Form S‑1/A filed March 30, 2011 (File No. 333‑171700), and incorporated herein by reference).	
10.66†	Form of Restricted Stock Award Agreement (Service-Vesting) (filed as Exhibit 10.50 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference).	
10.67†	Form of Restricted Stock Award Agreement (Performance-Vesting) (filed as Exhibit 10.51 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference).	
10.68†	Form of RSU Award Agreement (Service-Vesting) (filed as Exhibit 10.52 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference).	
10.69†	Form of RSU Award Agreement (Performance-Vesting) (filed as Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, and incorporated herein by reference).	
10.70†	Form of Directors RSU Award Agreement (Service-Vesting) (filed as Exhibit 10.54 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference).	
10.71†	Separation and Release Agreement, dated May 12, 2014 between Kosmos Energy, LLC and Darrell McKenna (filed as Exhibit 10.4 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended June 30, 2014, and incorporated herein by reference).	
10.72†	Offer Letter, dated September 1, 2011, between Kosmos Energy, LLC and Jason Doughty (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended June 30, 2014, and incorporated herein by reference).	
10.73†	Offer Letter, dated May 22, 2013, between Kosmos Energy, LLC and Christopher Ball (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended June 30, 2014, and incorporated herein by reference).	
10.74†	Offer Letter, dated January 10, 2014, between Kosmos Energy, LLC and Andrew Inglis (filed as Exhibit 10.58 to the Company’s Annual Report on Form 10‑K for the year ended December 31, 2013, and incorporated herein by reference).	
10.75†	Assignment Agreement, dated April 16, 2014, between Kosmos Energy, LLC and Brian F. Maxted (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10‑Q for the quarter ended June 30, 2014, and incorporated herein by reference).	
10.76†	Offer Letter, dated October 16, 2014, between Kosmos Energy, LLC and Thomas P. Chambers (filed as Exhibit 10.60 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, and incorporated herein by reference).	
10.77†	Offer Letter, dated February 11, 2008, between Kosmos Energy, LLC and Eric Haas (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, and incorporated herein by reference).	
10.78†	Kosmos Energy Ltd. Change in Control Severance Policy for U.S. Employees, dated December 19, 2013 (filed as Exhibit 10.66 to the Company’s Annual Report on Form 10‑K for the year ended December 31, 2013, and incorporated herein by reference).	
 	Other Exhibits	
14.1 	Code of Business Conduct and Ethics (filed as Exhibit 14.1 to the Company’s Annual Report on Form 10‑K for the year ended December 31, 2011, and incorporated herein by reference).	
21.1*	List of Subsidiaries.	
23.1*	Consent of Ernst & Young LLP.	
23.2*	Consent of Ryder Scott Company, L.P.	
31.1*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.	
31.2*	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.	
32.1**	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.	
32.2**	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.	
99.1*	Report of Ryder Scott Company, L.P.	
146

 
Table of Contents
 	 	
Exhibit
Number	Description of Document	
101.INS*	XBRL Instance Document.	
101.SCH*	XBRL Taxonomy Extension Schema Document.	
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.	
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.	
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.	
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.	

*     Filed herewith.
**   Furnished herewith.
†     Management contract or compensatory plan or arrangement.
 
147

Exhibit 10.16
 
DEED OF ASSIGNMENT
 
(PRODUCTION SHARING CONTRACT – BLOCK 5 EEZ)
 
The present Deed of Assignment is concluded between:
 
THE DEMOCRATIC REPUBLIC OF SAO TOME AND PRINCIPE, represented by the Agência Nacional do Petróleo de Săo Tomé e Príncipe, hereinafter referred to as  “ANP-STP” ;  
 
and 
 
EQUATOR EXPLORATION STP BLOCK 5 LIMITED, a company existing under the laws of the British Virgin Islands, registration number 1000133, with registered office at Craigmuir Chambers, Road Town, Tortola, British Virgin Islands with a branch registered in Sao Tome and Principe with the  Guiché Único   para Empresas  under no. 343/012 at Avenida da Independência Nº. 392, Săo Tomé – Săo Tomé e Príncipe, hereinafter referred to as  “EQUATOR” ;  
 
and
 
KOSMOS ENERGY SAO TOME AND PRINCIPE, a company existing under the laws of the Cayman Islands, whose registered office is located at 4 th  Floor, Century Yard, Cricket Square, Hutchins Drive, Elgin Avenue, George Town, Grand Cayman KY1-1209, Cayman Islands, with a branch registered in Sao Tome and Principe with the  Guiché Único para Empresas under nº 5492/2016 at Rua Soldado Paulo Ferreira, Edificio Francisco Cabral, 1º Andar CP. 410 Săo Tomé – Săo Tomé e Príncipe, hereinafter referred to as  “KOSMOS” ;  
 
and
 
Galp Energia Săo Tomé e Príncipe Unipessoal, Limitada, a company existing under the laws of Sao Tome and Principe, registered in the  Guiché Único para Empresas  with the number A100001/2015, with the tax number 517274968, with registered office in Avenida da Independência 392 II/III, Săo Tomé – Săo Tomé e Príncipe, hereinafter referred to as  “GALP”.
 
ANP-STP, EQUATOR, KOSMOS and GALP may collectively be referred to as the “Parties”  

 

WHEREAS
 
A.     THE DEMOCRATIC REPUBLIC OF SAO TOME AND PRINCIPE represented by ANP-STP and EQUATOR entered into the Production Sharing Contract signed with the Democratic Republic of Sao Tome and Principe on April 18, 2012 (the “Contract” ), in pursuance of which they have obtained the exclusive right to undertake petroleum operations in Block 5 within the territory of Sao Tome and Principe;
 
B.      On 19 February 2016 EQUATOR assigned and transferred to KOSMOS a sixty-five percent (65%) participating interest in the Contract;
 
C.      KOSMOS has agreed to assign to GALP a twenty percent (20%) participating interest in the Contract, and GALP has agreed to receive this twenty percent (20%) participating interest (the  “Assignment” );
 
D.      Article 19 of the Contract permits the parties to the Contract comprising the Contractor to assign and transfer in whole or in part their participating interest in the Contract with the respective rights, interests and obligations;
 
E.      Under article 19 of the Contract, ANP-STP, by its letter dated 16 November 2016, with the Ref Nº 183/ANP/GM/2016, authorized the Assignment and made known that it does not intend to exercise any preferential rights in relation to the Assignment;
 
F.      The Parties agree to the Assignment.
 
The Parties have entered into this Deed of Assignment subject to the following terms and conditions:
 
Article 1
 
The Assignment shall be effective on the date this Deed of Assignment is signed by all Parties (the  “Effective Date”).

 

Article 2
 
By virtue of this Deed of Assignment, KOSMOS assigns and transfers to GALP, and GALP accepts, the twenty percent (20%) participating interest referred to in Recital C, with all rights, interests and obligations (the  “Assigned Interest” ), so that the percentage interest held by the parties in the Contract as of the Effective Date shall be as follows:

ANP-STP	fifteen percent (15%);	
EQUATOR	twenty percent (20%);	
KOSMOS	forty-five percent (45%);	
GALP	twenty percent (20%).	
 
ANP-STP, EQUATOR and GALP agree that KOSMOS shall remain as Operator under the Contract.
 
Article 3
 
GALP acknowledges and accepts that it shall assume and fulfil all the obligations, responsibilities and duties from the Effective Date, under the Contract that may arise after this date related to the Assigned Interest.
 
GALP undertakes to indemnify and hold each of ANP-STP, EQUATOR and KOSMOS harmless from and against all such obligations, liabilities, duties, costs and expenses arising out of operations relating to the Contract which accrue after the Effective Date to the extent they are related to the Assigned Interest.
 
Article 4
 
KOSMOS declares and warrants that it has not transferred, assigned or pledged the Assigned Interest and KOSMOS undertakes to indemnify and shall hold ANP-STP, EQUATOR and GALP harmless from all direct claims, losses or damages that ANP-STP, EQUATOR and GALP may suffer or incur owing to a violation of the above declaration and warranty.

 

KOSMOS herein undertakes to indemnify and hold GALP harmless from all direct responsibilities and obligations relating to the Assigned Interest which accrue before the Effective Date.
 
Article 5
 
The Parties shall sign all other documents and shall carry out all other requirements that may be necessary or desirable in order to confirm and record the assignment of the Assigned Interest to make the Assignment effective in accordance with the laws of the Democratic Republic of Sao Tome and Principe.
 
Article 6
 
All the terms used in the present Deed of Assignment, which are not expressly defined herein, will have the same definition as that indicated in the Contract.
 
In witness hereof, the Parties have duly signed this Deed of Assignment in four (4) originals in the Portuguese language and in four (4) originals in the English language. The Portuguese version will prevail in case of discrepancy.

EQUATOR EXPLORATION STP BLOCK 5 LIMITED	
 	 	 	
Signature:	/s/ Pade Durotoye	 	
 	 	 	
Name:	PADE DUROTOYE	 	
 	 	 	
Position: 	MD/CEO	 	
 	 	 	
Date: 	December 09, 2016	 	

KOSMOS ENERGY SAO TOME AND PRINCIPE	
 	 	 	
Signature:	/s/ Jon W. Cappon	 	
 	 	 	
Name:	JON W. CAPPON	 	
 	 	 	
Position:	VICE PRESIDENT / COUNTRY MANAGER	 	
 	 	 	
Date:	November 18, 2016	 	

 

 	 	 	
Galp Energia Săo Tomé e Príncipe Unipessoal, Limitada	
 	 	 	
Signature:	/s/ Thore E. Kristiansen                 /s/Filipe Silva	 	
 	 	 	
Name:	THORE E. KRISTIANSEN          FILIPE SILVA	 	
 	 	 	
Position:	EXECUTIVE DIRECTOR            EXECUTIVE DIRECTOR	 	
 	 	 	
Date:	November 22, 2016                        November 22, 2016	 	
 
By its agreement to this Deed of Assignment, the Agência Nacional do Petróleo de Săo Tomé e Príncipe, representing THE DEMOCRATIC REPUBLIC OF SAO TOME AND PRINCIPE and as a party in the Contract ,   confirms the authorization to the above referred Assignment of the Assigned Interest and that it will not exercise any preferential rights in relation to the Assignment. It further expresses its agreement to the Assignment.

Signature:	/s/ Orlando Sousa Pontes	 	
 	 	 	
Name:	ORLANDO SOUSA PONTES	 	
 	 	 	
Position:	EXECUTIVE DIRECTOR	 	
 	 	 	
Date:	December 13, 2016	 	

Exhibit 10.23
 
DEED OF ASSIGNMENT
 
(PRODUCTION SHARING CONTRACT – BLOCK 11 EEZ)
 
The present Deed of Assignment is concluded between:
 
THE DEMOCRATIC REPUBLIC OF SAO TOME AND PRINCIPE, represented by the Agência Nacional do Petróleo de Săo Tomé e Príncipe, hereinafter referred to as  “ANP-STP”;   
 
and
 
KOSMOS ENERGY SAO TOME AND PRINCIPE, a company existing under the laws of the Cayman Islands, whose registered office is located at 4 th  Floor, Century Yard, Cricket Square, Hutchins Drive, Elgin Avenue, George Town, Grand Cayman KY1-1209, Cayman Islands, Islands with a branch registered in Sao Tome and Principe, with the  Guiché Único para Empresas  under nº 5492/2016 at Rua Soldado Paulo Ferreira, Edificio Francisco Cabral, 1º Andar CP. 410 Săo Tomé - Săo Tomé e Príncipe, hereinafter referred to as “ KOSMOS” ;
 
and
 
Galp Energia Săo Tomé e Príncipe Unipessoal, Limitada, a company existing under the laws of República Democrática de S. Tomé e Príncipe, registered in the  Guiché Único para Empresas  with the number A100001/2015, with the tax number 517274968, with registered office in Avenida da Independência 392 II/III, Săo Tomé – Săo Tomé e Príncipe   hereinafter referred to as “GALP” .
 
ANP-STP, KOSMOS and GALP and may collectively be referred to as “Parties” 
 
WHEREAS
 
A.        THE DEMOCRATIC REPUBLIC OF SAO TOME AND PRINCIPE represented by the Agência Nacional do Petróleo de Săo Tomé e Príncipe, (“ANP-STP”) and ERHC ENERGY EEZ, LDA (“ERHC”) entered into the Production Sharing Contract signed with the Democratic Republic of Sao Tome and Principe on 23 July 2014 (the “Contract”), in pursuance of which ERHC obtained the exclusive right to undertake

 

petroleum operations in Block 11 within the territory of Sao Tome and Principe;
 
B.        On 16 October 2015 ERHC transferred and assigned to KOSMOS the entirety of its eighty-five percent (85%) participating interest in the Contract as well as the entirety of its rights and obligations in the Contract;
 
C.        KOSMOS has an eighty-five percent (85%) participating interest in the Contract, and has agreed to assign and transfer to GALP, which agreed to receive, a twenty percent (20%) participating interest in the Contract (the “Assignment”);
 
D.        Article 19 of the Contract permits the parties to the Contract comprising the Contractor to assign and transfer in whole or in part their participating interest in the Contract with the respective rights, interests and obligations;
 
E.        Under article 19 of the Contract, ANP-STP, by its letter dated 16 November 2016, with the Ref. Nº 183/ANP/GM/2016, authorized the Assignment and made known that it does not intend to exercise any preferential rights in relation to the Assignment;
 
F.        The Parties agree to the Assignment.
 
In witness whereof, the Parties have agreed the following between themselves in consideration of the obligations set out in the present deed of assignment:
 
Article 1
 
The Assignment shall be effective on the date this Deed of Assignment is signed by all Parties (the “Effective Date”).
 
Article 2
 
By virtue of this Deed of Assignment, KOSMOS assigns and transfers to GALP, and GALP accepts, the twenty percent (20%) participating interest referred to in Recital C, with all rights, interests and obligations (the “Assigned Interest”), so that the percentage interest held by the parties in the Contract as of the Effective Date shall be as follows:

 
 	 	
ANP-STP	fifteen percent (15%);	
KOSMOS	sixty-five percent (65%);	
GALP	twenty percent (20%).	

 

ANP-STP and GALP agree that KOSMOS shall remain as Operator under the Contract.
 
Article 3
 
GALP acknowledges and accepts that it shall assume and fulfil all the obligations, responsibilities and duties from the Effective Date, under the Contract that may arise after this date related to the Assigned Interest.
 
GALP undertakes to indemnify and hold each of ANP-STP and KOSMOS harmless from and against all such obligations, liabilities, duties, costs and expenses arising out of operations relating to the Contract which accrue after the Effective Date to the extent they are related to the Assigned Interest.
 
Article 4
 
KOSMOS declares and warrants that it has not transferred, assigned or pledged the Assigned Interest and KOSMOS undertakes to indemnify and shall hold ANP-STP and GALP harmless from all direct claims, losses or damages that ANP-STP and GALP may suffer or incur owing to a violation of the above declaration and warranty.
 
KOSMOS herein undertakes to indemnify and hold GALP harmless from all direct responsibilities and obligations relating to the Assigned Interest which accrue before the Effective Date.
 
Article 5
 
The Parties shall sign all other documents and shall carry out all other requirements that may be necessary or desirable in order to confirm and record the assignment of the Assigned Interest to make the Assignment effective in accordance with the laws of the Democratic Republic of Sao Tome and Principe.

 

Article 6
 
All the terms used in the present Deed of Assignment, which are not expressly defined herein, will have the same definition as that indicated in the Contract.
 
In witness hereof, the Parties have duly signed this deed of assignment in three (3) originals in the Portuguese language and in three (3) originals in the English language. The Portuguese version will prevail in case of discrepancy.

KOSMOS ENERGY SAO TOME AND PRINCIPE	 	
 	 	
Signature:	/s/ Jon W. Cappon	 	 	
 	 	
Name:	JON W. CAPPON	 	 	
 	 	
Position:	VICE PRESIDENT / COUNTRY MANAGER	 	 	
 	 	
Date:	November 18, 2016	 	 	

Galp Energia Săo Tomé e Príncipe Unipessoal, Limitada	 	
 	 	
Signature:	/s/ Thore E. Kristiansen                 /s/Filipe Silva	 	 	
 	 	
Name:	THORE E. KRISTIANSEN          FILIPE SILVA	 	 	
 	 	
Position: 	EXECUTIVE DIRECTOR            EXECUTIVE DIRECTOR	 	 	
 	 	
Date: 	November 22, 2016                        November 22, 2016	 	 	
 
By its agreement to this Deed of Assignment, the Agência Nacional do Petróleo de Săo Tomé e Príncipe, representing THE DEMOCRATIC REPUBLIC OF SAO TOME AND PRINCIPE and as a party in the Contract ,   confirms the authorization to the above referred Assignment of the

 

Assigned Interest and that it will not exercise any preferential rights in relation to the Assignment. It further expresses its agreement to the Assignment.

Signature:	/s/ Orlando Sousa Pontes	 	 	
 	 	
Name:	ORLANDO SOUSA PONTES	 	 	
 	 	
Position:	EXECUTIVE DIRECTOR	 	 	
 	 	
Date:	December 13, 2016	 	 	

Exhibit 10.27
 
DEED OF ASSIGNMENT
 
(PRODUCTION SHARING CONTRACT – BLOCK 12 EEZ)
 
The present Deed of Assignment is concluded between:
 
THE DEMOCRATIC REPUBLIC OF SAO TOME AND PRINCIPE, represented by the Agência Nacional do Petróleo de Săo Tomé e Príncipe, hereinafter referred to as  “ANP-STP” ;  
 
and 
 
EQUATOR EXPLORATION STP BLOCK 12 LIMITED, a company existing under the laws of the Commonwealth of The Bahamas whose registered office is at Lyford Manor (West Bldg), Western Road, Lyford Cay, P. O. Box CB-13007, Nassau, The Bahamas with a branch registered in Sao Tome and Principe with the  Guiché Único   para Empresas  under nº 5541/2016 at Avenida da Independência nº 392, Săo Tomé – Săo Tomé e Príncipe, hereinafter referred to as “EQUATOR” ;  
 
and
 
KOSMOS ENERGY SAO TOME AND PRINCIPE, a company existing under the laws of the Cayman Islands, registered in the Commercial Registry of the Cayman Islands with the number WT-301785, with registered office in 4th Floor, Century Yard, Cricket Square, Hutchins Drive, Elgin Avenue, George Town, Grand Cayman KY1-1209, Cayman Islands with a branch registered in Sao Tome and Principe with the  Guiché Único Para Empresas  under nº 5492/2016 at Rua Soldado Paulo Ferreira, Edificio Francisco Cabral, 1º Andar CP. 410 Săo Tomé - Săo Tomé e Príncipe, hereinafter referred to as “KOSMOS” ;
 
and
 
Galp Energia Săo Tomé e Príncipe Unipessoal, Limitada, a company existing under the laws of República Democrática de S. Tomé e Príncipe, registered in the  Guiché Único para Empresas  with the number A100001/2015, with the tax number 517274968, with registered office in Avenida da Independência 392 II/III, Săo Tomé – Săo Tomé e Príncipe, hereinafter referred to as “GALP” .
 
ANP-STP, EQUATOR, KOSMOS and GALP may collectively be referred to as the “Parties”  

 

WHEREAS
 
A.       THE DEMOCRATIC REPUBLIC OF SAO TOME AND PRINCIPE represented by the Agência Nacional do Petróleo de Săo Tomé e Príncipe, (“ANP-STP”) and EQUATOR entered into the Production Sharing Contract signed with the Democratic Republic of Sao Tome and Principe on 19 th . February 2016 (the “Contract”), in pursuance of which EQUATOR obtained the exclusive right to undertake petroleum operations in Block 12 within the territory of Sao Tome and Principe;
 
B.        On 31 March 2016 EQUATOR assigned and transferred a sixty-five percent (65%) participating interest in the Contract to KOSMOS;
 
C.        KOSMOS has agreed to assign to GALP a twenty percent (20%) participating interest in the Contract, and GALP has agreed to receive this participating interest (the “Assignment”);
 
D.        Article 19 of the Contract permits the parties to the Contract comprising the Contractor to assign and transfer in whole or in part their participating interest in the Contract with the respective rights, interests and obligations;
 
E.        Under article 19 of the Contract, ANP-STP, by its letter dated 16 November 2016, with the Ref. Nº 183/ANP/GM/2016, authorized the Assignment and made known that it does not intend to exercise any preferential rights in relation to the Assignment;
 
F.         The Parties agree to the Assignment.
 
The Parties have entered into this Deed of Assignment subject to the following terms and conditions:
 
Article 1
 
The Assignment shall be effective on the date this Deed of Assignment is signed by all Parties (the “ Effective Date” ).

 

Article 2
 
By virtue of this Deed of Assignment, KOSMOS assigns and transfers to GALP, and GALP accepts, the twenty percent (20%) participating interest referred to in Recital C, with all rights, interests and obligations (the “Assigned Interest”), so that the percentage interest held by the parties in the Contract as of the Effective Date shall be as follows:
 
ANP-STP	twelve and a half percent (12.5%);	
EQUATOR	twenty-two and a half percent (22.5%);	
KOSMOS	forty-five percent (45%);	
GALP	twenty percent (20%).	
 
ANP-STP, EQUATOR and GALP agree that KOSMOS shall remain as Operator under the Contract.
 
Article 3
 
GALP acknowledges and accepts that it shall assume and fulfil all the obligations, responsibilities and duties from the Effective Date, under the Contract that may arise after this date related to the Assigned Interest.
 
GALP undertakes to indemnify and hold each of ANP-STP, EQUATOR and KOSMOS harmless from and against all such obligations, liabilities, duties, costs and expenses arising out of operations relating to the Contract which accrue after the Effective Date to the extent they are related to the Assigned Interest.
 
Article 4
 
KOSMOS declares and warrants that it has not transferred, assigned or pledged the Assigned Interest and KOSMOS undertakes to indemnify and shall hold ANP-STP, EQUATOR and GALP harmless from all direct claims, losses or damages that ANP-STP, EQUATOR and GALP may suffer or incur owing to a violation of the above declaration and warranty.

 

KOSMOS herein undertakes to indemnify and hold GALP harmless from all direct responsibilities and obligations relating to the Assigned Interest which accrue before the Effective Date.
 
Article 5
 
The Parties shall sign all other documents and shall carry out all other requirements that may be necessary or desirable in order to confirm and record the assignment of the Assigned Interest to make the Assignment effective in accordance with the laws of the Democratic Republic of Sao Tome and Principe.
 
Article 6
 
All the terms used in the present Deed of Assignment, which are not expressly defined herein, will have the same definition as that indicated in the Contract.
 
In witness hereof, the Parties have duly signed this deed of assignment in four (4) originals in the Portuguese language and in four (4) originals in the English language. The Portuguese version will prevail in case of discrepancy.
 
/s/ Pade Durotoye	 	 	
EQUATOR EXPLORATION STP BLOCK 12 LIMITED	
 	 	 	
Signature:	/s/ Pade Durotoye	 	
 	 	 	
Name:	PADE DUROTOYE	 	
 	 	 	
Position:	MD/CEO	 	
 	 	 	
Date:	December 09, 2016	 	
 	 	 	
KOSMOS ENERGY SAO TOME AND PRINCIPE	
 	 	 	
Signature:	/s/ Jon W. Cappon	 	
 	 	 	
Name:	JON W. CAPPON	 	
 	 	 	
Position:	VICE PRESIDENT / COUNTRY MANAGER	 	
 	 	 	
Date:	November 18, 2016	 	

 

/s/ Thore E. Kristiansen                 /s/Filipe Silva	 	 	
Galp Energia Săo Tomé e Príncipe Unipessoal, Limitada	
 	 	 	
Signature:	/s/ Thore E. Kristiansen                 /s/Filipe Silva	 	
 	 	 	
Name:	THORE E. KRISTIANSEN          FILIPE SILVA	 	
 	 	 	
Position:	EXECUTIVE DIRECTOR            EXECUTIVE DIRECTOR	 	
 	 	 	
Date:	November 22, 2016                        November 22, 2016	 	
 
By its agreement to this Deed of Assignment, the Agência Nacional do Petróleo de Săo Tomé e Príncipe, representing THE DEMOCRATIC REPUBLIC OF SAO TOME AND PRINCIPE and as a party in the Contract ,   confirms the authorization to the above referred Assignment of the Assigned Interest and that it will not exercise any preferential rights in relation to the Assignment. It further expresses its agreement to the Assignment.

Signature:	/s/ Orlando Sousa Pontes	 	
 	 	 	
Name:	ORLANDO SOUSA PONTES	 	
 	 	 	
Position:	EXECUTIVE DIRECTOR	 	
 	 	 	
Date:	December 13, 2016	 	

Exhibit 10.31
Dated 15  December 2016

 

KOSMOS ENERGY SENEGAL
and
BP INDONESIA OIL TERMINAL INVESTMENT LIMITED
and
NORMANDY VENTURES LIMITED

SALE AND PURCHASE AGREEMENT
relating to the sale and purchase of shares in
Normandy Ventures Limited

 

 

CONTENTS
 	 	 	
 	 	Page No	
1	Interpretation	1 	
2	Sale and purchase	12 	
3	Consideration	12 	
4	First Completion	13 	
5	Parties’ undertakings prior to Second Completion	13 	
6	Conditions	15 	
7	Second Completion	18 	
8	Deferred Consideration Amounts	18 	
9	Payment	25 	
10	Parties’ warranties	25 	
11	Further assurance	28 	
12	Variation	29 	
13	Confidentiality and Announcements	29 	
14	Notices	30 	
15	Tax; Costs	31 	
16	Contracts (Rights of Third Parties) Act 1999	33 	
17	Counterparts	33 	
18	Miscellaneous	33 	
19	Governing law and Dispute Resolution	35 	

 

THIS AGREEMENT is made on 15th December 2016
BETWEEN
1          Kosmos Energy Senegal, a company existing under the laws of the Cayman Islands (“ Kosmos ”); and
2          BP Indonesia Oil Terminal Investment Limited, a company incorporated in England and Wales  under registered number 09978028 whose registered office is at Chertsey Rd, Sunbury on Thames, Middlesex TW16 7BP UK (the “ BP ”); and
3          Normandy Ventures Limited, a company incorporated in England and Wales under registered number 10520822 whose registered office is at C/o Wilmington Trust SP Services (London) Limited, King’s Arms Yard, London, EC2R 7AF (“ JVCo ”);
each a “Party” and together the “Parties”.
WHEREAS:
(A)      At the date of this Agreement, JVCo is wholly-owned by Kosmos and Kosmos has subscribed for, and is the legal and beneficial owner of, 10,000 Ordinary Shares which have been issued and allotted by JVCo to Kosmos fully paid.
(B)      In order to facilitate the JV Partners’ investments in JVCo, the Seller has agreed to sell, and the Purchaser has agreed to purchase, the Sale Shares on the terms and subject to the conditions of this Agreement.
WHEREBY IT IS AGREED as follows:
1          Interpretation
1.1       In this Agreement:
 	 	
“Affiliate”	means a legal entity which Controls, or is Controlled by, or which is Controlled by an entity which Controls, a Party, and “Affiliates” shall be construed accordingly;	
“Answer”	Means a written response made by Kosmos to BP in respect of any question or clarification sought by BP in respect of or in relation to the Interests, the Interest Documents or the Senegal Area, as set out in Exhibit G.	
“Anti-Corruption Laws and Obligations”	means:
(a)       the OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions, 1997;	
 
3

 

 

 	(b)       the Foreign Corrupt Practices Act of 1977 of the United States of America, as amended by the Foreign Corrupt Practices Act Amendments of 1988 and 1998, and as may be further amended and supplemented from time to time;
(c)       the Bribery Act 2010 of the United Kingdom and any regulations or guidance issued pursuant to such legislation, as may be amended and supplemented from time to time; and
(d)       any act, rule or regulation of the United States of America, the United Kingdom, the Republic of Senegal or any other relevant jurisdiction related to prevention of bribery, corruption, or money laundering,
provided that, in the event that a Party acting with respect to this Agreement is outside the jurisdiction or scope of any of the aforementioned laws, such laws shall be interpreted as though such Party were within the jurisdiction and scope of such law;	
“Approval”	means the issuance of the approval of the Government required in order to effect the legal assignment and transfer of the Interests from Kosmos to JVCo;	
“Associated Person”	means a person acting on behalf of the first Person or the first Person’s Affiliates, whether as personnel of any tier, as an officer, director or under a power of attorney or other similar authorization and specifically including consultants, representatives, agents, employees or other similar persons who have the right or power to act on behalf of the first Person or its Affiliate;	
“BP Warranties”	means the warranties set out in Schedule 4;	
“Brent”	means the arithmetic average of the high and low spot daily assessments of Brent (Dated) quotations as published in Platt’s Crude Oil Marketwire for the relevant period of time;	
“Business Day”	means each calendar day except Saturdays, Sundays, and any other day on which banks are generally closed for business in London, the United Kingdom, and New York City, USA;	
“Commercial Production”	means any production from the Senegal Area pursuant to a development and exploitation plan contemplated under and approved in accordance with the Senegal Area JOAs.	
 
4

 

“Completion”	means First Completion or Second Completion, as the context requires;	
“Completion Date”	means the First Completion Date or the Second Completion Date, as the context requires;	
“Conditions”	has the meaning given in Clause 6.1;	
“Consideration Amount”	means the First Completion Consideration Amount, the Second Completion Consideration Amount or a Deferred Consideration Amount, as the context requires;	
“Contracts”	means together the Petroleum Agreements and any extension, renewal or amendment thereto, and all exploration authorizations granted pursuant to the Petroleum Agreements or any successor title that governs all or part of the Senegal Area, as all such instruments and titles are governed by the Hydrocarbon Code;	
“Control”	means the ownership directly or indirectly of more than fifty percent (50%) of the voting rights in a legal entity. “ Controls ”, “ Controlled by ” and other derivatives shall be construed accordingly;	
“Data”	means all accounts, books, data and reports in the possession, custody or control of Kosmos and its Affiliates relating to the Interests including correspondence, petroleum engineering, reservoir engineering, drilling, geoscientific, seismic and all other kinds of technical data and reports, samples, well logs and analyses in whatever form the same are maintained, including third party information, including seismic, which Kosmos or its Affiliates has the right to disclose, acquired pursuant to the Interest Documents, subject to the exclusion of work product of, or attorney-client communications with, legal counsel for Kosmos or any Affiliate of Kosmos;	
“Deferred Consideration Amounts”	(a)      the Interim Period Costs Consideration;
(b)      the Exploration & Appraisal Carry Consideration;
(c)      the Development Carry Consideration; and
(d)      the Success Fee Consideration,	
 
5

 

 	and each a “Deferred Consideration Amount ”;	
“Development Carry Consideration”	has the meaning given in Clause 8.4;	
“Disclosure Documents”	means the Disclosure Letter and the documents stored in electronic form on a hard drive provided to each Party by Intralinks Inc., that represent the entire contents of Kosmos’s data room at 16.55 (GMT) m. (London time)/ 10.55 am Dallas time (CST) on 12th December 2016;	
“Disclosure Letter”	means the letter described as such, dated as of the date of this Agreement and addressed to BP by Kosmos, which sets out certain disclosures against Kosmos’s Warranties;	
“Effective Date”	means 1 July 2016;	
“Eligible Discovery”	means a discovery of Hydrocarbons (as defined under the Contracts) in the Senegal Area, other than the Tortue Discovery Area (from the surface to the equivalent of the oldest stratigraphy currently penetrated in the development area in the Guembeul #1A Well) and the Teranga Discovery Area (from the surface to equivalent of the oldest stratigraphy currently penetrated in the development area in the Teranga #1 Well) as shown and described on Exhibit C, Parts 1 and 2;	
“Encumbrances”	means all liens, charges (fixed or floating), mortgages, pledges, encumbrances or security or net profit interests or royalty or overriding interests, carried interests, production payments, claims, options, pre-emption rights or equities or any agreement to create any of the foregoing other than (in each case) those arising under the provisions of the Interest Documents and the farm out agreement dated 19 August 2014 and other arrangements between Kosmos and Timis Corporation entered into at the same time as the farm out agreement and as notified in writing on 13 th  December 2016 on behalf of Kosmos to BP “ Encumbrance ” and “ Encumber ” shall be construed accordingly;	
“Exploitation Perimeter”	shall have the meaning given to the French term “Périmètre d’Exploitation” in the Contracts, which French term was translated as “Operations Perimeter” in the English version of the Contracts provided to BP;	
 
6

 

“Exploration & Appraisal Carry Consideration”	has the meaning given in Clause 8.3;	
“Firm Work Programme (Development)”	means the Tortue development studies required to support a late 2017 investment decision on the Tortue area as set out in Exhibit A 2;	
“Firm Work Programme (Exploration and Appraisal)”	means the work programme as set out in Exhibit A 1;	
“First Completion”	means completion of the sale and purchase of the Sale Shares, and the payment of the First Consideration Amount, in each case pursuant to, and in accordance with, the terms of this Agreement;	
“First Consideration Amount”	means US$ 49.99, being the aggregate nominal value of the Sale Shares;	
“Good Industry Practice”	means the exercise of that degree of skill, diligence, prudence and foresight which would reasonably and ordinarily be expected to be applied by a skilled and experienced person engaged in the same type of undertaking;	
“Government”	means the government of the Republic of Senegal and any political subdivision, agency or instrumentality thereof, including PETROSEN;	
“Government Official”	means, whether appointed, elected or otherwise, any:
(a)       minister, civil servant, director, officer, principal, agent or employee or other official of: (i) any government (whether central, federal, state, provincial or local) ministry, body, department, agency, instrumentality or part of any of them; (ii) any public international organization; (iii) any department, agency or body of any government-owned or controlled company, agency, enterprise, joint venture, or partnership; and (iv) any company, agency, enterprise, joint venture, or partnership in which a government owns an interest of more than thirty percent, and/or of any public international organization (such as the World Bank or United Nations);
(b)       person acting in any official, legislative,	
 
7

 

 
 	
 	administrative or judicial capacity for or on behalf of any government department, agency, body, instrumentality or public international organization, including without limitation any judges or other court officials, military personnel and customs, police, national security or other law enforcement personnel;
(c)       officer or employee of a political party or any person acting in an official capacity on behalf of a political party; and/or
(d)       candidate for political office;	
“Hydrocarbon Code”	means Petroleum Code (Law No. 98-05 dated 8 January 1998) as modified and completed;	
“Initial Asset Transfer Agreement”	means the agreement dated on or around the date of this Agreement pursuant to which Kosmos agrees to transfer the Initial Interests to JVCo, in the form set out in Part 1 of  Exhibit F;	
“Initial Asset Transfer Completion”	means completion of the transfer of the Initial Interests from Kosmos to JVCo pursuant to the terms of the Initial Asset Transfer Agreement;	
“Initial Asset Transfer Completion Date”	means the date on which Initial Asset Transfer Completion occurs pursuant to the terms of the Initial Asset Transfer Agreement;	
“Initial Interests”	means an undivided legal and beneficial interest of sixty percent (60%) in the rights and obligations under the Contracts and an undivided interest of sixty percent (60%) participating interest and a sixty-six decimal sixty-seven percent (66.67%) Paying Interest in the rights and obligations under the Senegal JOAs;	
“Interests”	means the Initial Interests and the TC Interests;	
“Interest Documents”	means the Contracts and the Senegal Area JOAs;	
“Interim Period”	means the period commencing from 1 July, 2016 until, but not including the Second Completion Date;	
“Interim Period Costs”	means all costs properly incurred by Kosmos directly in relation to JVCo’s Paying Interest share under the Senegal Area JOAs for Joint Operations (as defined under the Senegal Area JOAs) undertaken by Kosmos	
 
8

 

 	pursuant to the terms of the Senegal Area JOAs during the Interim Period if applicable, and determined pursuant to Clause 8.2;	
“Interim Period Costs Consideration”	means a cash amount in US dollars which is equal to 49.99 per cent. of the Interim Periods Costs;	
“JV Partners”	means Kosmos and BP (each a “JV Partner”);	
“JVCo Group”	means JVCo and its subsidiaries from time to time;	
“Kosmos’s Account”	means the account information notified by Kosmos to BP from time to time with at least five Business Days’ notice;	
“Kosmos Mauritania”	means Kosmos Energy Mauritania, a company existing under the laws of the Cayman Islands;	
“Kosmos Payment Failure”	means: (i) any failure by Kosmos to pay any amount owed by Kosmos to BP under this Agreement; or (ii) any failure by the Farmor (as defined in the Mauritania Farmout Agreement) to pay any amount owed by the Farmor to the Farmee (as defined in the Mauritania Farmout Agreement) in respect of the Mauritania Farmout Agreement (other than Article 4.7B thereof);	
“Kosmos Asset Warranties”	means the warranties set out in Part 1 of Schedule 3;	
“Kosmos Share Warranties”	means the warranties set out in Part 2 of Schedule 3;	
“Kosmos Warranties”	means the Kosmos Asset Warranties and the Kosmos Share Warranties;	
“LNG”	means processed Natural Gas (as defined under the Contracts) consisting primarily of methane (CH 4 ) in a liquid state at or below its boiling point and at a pressure of approximately one (1) atmosphere;	
“Long Stop Date”	means 30 September 2017;	
“Mauritania Area”	means the area covered by the Mauritania Contracts, copies of which are included in the Disclosure Documents;	
“Mauritania Contracts”	means the Exploration and Production Contracts entered into by Kosmos Mauritania, SMHPM and the Islamic	
 
9

 

 	Republic of Mauritania for the exploration and exploitation of hydrocarbons in the Blocks C6, C8, C12 and C13, offshore Mauritania;	
“Mauritania JOAs”	means (a) the three (3) Amended and Restated Joint Operating Agreements each dated 1 December 2014 entered into by Kosmos Mauritania and SMHPM for operations in the Blocks C8, C12 and C13 portions of the Mauritania Area; and (b) the Joint Operating Agreement to be entered into on terms substantially similar to the joint operating agreements set out in (a) above, by Kosmos Mauritania, SMHPM and, if such joint operating agreement has yet to be executed prior to completion of the Mauritania Farmout Agreement, by BP Exploration (West Africa) Limited for operations in the Block C6 portion of the Mauritania Area;	
“Mauritania Operator”	means the operator under the Mauritania Contracts and the Mauritania JOAs;	
“Mauritania Farmout Agreement”	means the Farmout Agreement concerning Blocks C6, C8, C12 and C13, Offshore Mauritania between Kosmos Mauritania and BP Exploration (West Africa) Limited of even date with this Agreement;	
“Ordinary Shares”	means the ordinary shares of US$ 0.01 in the capital of JVCo;	
“Participating Interest”	means as to any party to the Contracts or the Senegal Area JOAs, the undivided interest of such party expressed as a percentage of the total interest of all parties in the rights and obligations derived from the Contracts or the Senegal Area JOAs as the context so requires;	
“Paying Interest”	means as to any party to the Senegal Area JOAs, other than PETROSEN, the undivided interest of such party in the payment obligations under the Senegal Area JOAs, including in respect of the Participating Interest share of PETROSEN in the Contracts, until PETROSEN elects to participate in an Exploitation Perimeter from which time the Paying Interests will be aligned with such party’s Participating Interests;	
“Person”	means an individual, corporation, company, government entity, state enterprise, or any other legal entity;	
 
10

 

“Petroleum Agreements”	means the Hydrocarbon Exploration and Production Sharing Contract granted by the Republic of Senegal dated January 17, 2012 covering the Saint Louis Offshore Profond Block and the Hydrocarbon Exploration and Production Sharing Contract granted by the Republic of Senegal dated January 17, 2012 covering the Cayar Offshore Profond Block;	
“PETROSEN”	or La Société des Pétroles du Sénégal  means, the oil company of the Republic of Senegal, a company governed by the laws of Senegal and having its registered office in Dakar, at Route du Service Géographique, Hann BP 2016, Senegal;	
“Quarter”	means a period of three calendar months each commencing on 1 January, 1 April, 1 July and 1 October of each Calendar Year (as defined in the Contracts);	
“Sale Shares”	means 4,999 Ordinary Shares;	
“Second Completion”	means completion of the payment of the Second Consideration Amount pursuant to, and in accordance with, the terms of this Agreement;	
“Second Completion Date”	means the fifth Business Day following the date on which the Conditions are satisfied (or waived in accordance with Clause 6.2);	
“Second Consideration Amount”	has the meaning given in Clause 7.2;	
“Senegal Area”	means the area covered by the Contracts, as more particularly described in Exhibit D;	
“Senegal Area JOAs”	means the two Joint Operating Agreements, each dated 26 September 2012, entered into by and between PETRO-TIM Limited (Kosmos’ predecessor in title) and, PETROSEN for operations in the Saint Louis Offshore Profond and in the Cayar Offshore Profond portions of the Senegal Area, as amended and supplemented and novated from time to time;	
“Success Fee Consideration”	means a fee per Barrel (as defined under the Contracts) of total production of all liquid Hydrocarbons (as defined under the Contract) in the natural state or obtained from Natural Gas by condensation or separation with an API gravity equal to or greater than 22.3°, but excluding LNG, from each Eligible Discovery calculated on the basis of	
 
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 	the average price of Brent during the relevant Quarter of production multiplied by:
(i)        in respect of each Barrel up to the aggregate gross cumulative production from all Eligible Discoveries and all Eligible Discoveries (as such term is defined in the Mauritania Farmout Agreement) of one Billion Barrels (1bnbbl), decimal zero zero eight seven five US Dollars (US$ 0.00875), which yields a Success Fee of decimal five two five US Dollars (US$ 0.525) per Barrel of production at a Brent price of sixty Dollars (US$ 60); provided that the Success Fee per Barrel in respect of the first one Billion Barrels (1bnbbl)shall not exceed one Dollar and five cents (US$ 1.05) per Barrel regardless of the average price of Brent; and
(ii)       in respect of each Barrel over and above the aggregate gross cumulative production from all Eligible Discoveries and all Eligible Discoveries (as such term is defined in the Mauritania Farmout Agreement) of one Billion Barrels (1bnbbl), decimal zero zero zero zero eight seven five US Dollars (US$0.0000875), which yields a Success Fee of decimal zero zero five two five US Dollars (US$ 0.00525) per Barrel of production at a Brent price of sixty Dollars (US$ 60); provided that the Success Fee per Barrel in respect of the Barrels over and above one Billion Barrels (1bnbbl) shall not exceed one cent (US$ 0.01) per Barrel regardless of the average price of Brent]	
“Surviving Provisions”	means Clauses 1, 10.3, 10.6, 11, 12, 13, 15, 16, 17, 18 (excluding 18.1 and 18.2) and 19;	
“Tax”	means any tax, royalty, levy, charge, impost, duty, fee, deduction, compulsory loan or withholding which is assessed, levied, imposed or collected by the Government tax authorities or any tax authorities of any other jurisdiction and includes any interest, fine, penalty,	
 
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 	charge, fee or other amount imposed in respect of the above and “ Taxes ” shall be construed accordingly;	
“TC Asset Transfer Agreement”	means the agreement dated on or around the date of this Agreement pursuant to which Kosmos agrees to transfer the TC Interests to JVCo, in the form set out in Part 2 of  Exhibit F;	
"TC Asset Transfer Completion "	means completion of the acquisition of the TC Interests as contemplated by the TC Asset Transfer Agreement;	
"TC Asset Transfer Completion Date "	means the date on which TC Asset Transfer Completion occurs;	
“TC Interests”	means an undivided legal and beneficial interest of five percent (5%) in the rights and obligations under the Contracts and an undivided interest of five percent (5%) participating interest and a five decimal fifty-six percent (5.56%) Paying Interest in the rights and obligations under the Senegal JOAs, which interest is separate and distinct from the Initial Interests;	
“TC Option”	means the option right of Kosmos to acquire from Timis Corporation the TC Interests pursuant to a Farm-out Agreement entered into between Kosmos and Timis Corporation in relation to interests in the Senegal Area;	
“TC Option Completion”	means completion of the acquisition of the TC Interests, as contemplated pursuant to the TC Option;	
“TC Option Completion Date”	means the date on which TC Option Completion occurs; and	
“Wholly-Owned Affiliate”	means, in relation to any entity, any other entity that is wholly owned and controlled by such entity or that is wholly owned and controlled by a third person which has common control over the first two entities.	
 
1.2       In this Agreement, unless otherwise specified:
(A)      “subsidiary” has the meaning given in the UK Companies Act 2006;
(B)      references to Clauses are to clauses of this Agreement;
(C)      references to “$” and “US$” are to US dollars;
(D)      headings to Clauses are for convenience only and do not affect the interpretation of this Agreement;
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(E)      words in the singular shall include the plural and vice versa;
(F)       the words "include" and "including" shall be inclusive without limiting the generality of the description proceeding such term and are used in an illustrative sense and not a limiting sense;
(G)      performance of an obligation of any kind by a Party must be carried out at that Party’s cost, unless this Agreement states otherwise;
(H)      the Schedules and Exhibits form part of this Agreement and have full force and effect as expressly set out in the main body of this Agreement; and
(I)        references in this Agreement to any agreement shall, where the context permits, be construed as a reference to such agreement as the same may be supplemented, amended or novated from time to time.
2          Sale and purchase
2.1       Kosmos shall sell, with full title guarantee, and BP shall purchase, the Sale Shares free from all Encumbrances, together with all rights attached or accruing to them at First Completion, such that, immediately following First Completion, the JV Partners’ respective holdings of Ordinary Shares shall be as follows:
 	 	 	
JV Partner	Ordinary Shares	Percentage of Ordinary Share capital	
Kosmos	5,001	50.01	
BP	4,999	49.99	
 
2.2       Kosmos waives all rights of pre-emption over any of the Sale Shares conferred upon it by the articles of association of the Company or in any other way. 
3          Consideration
3.1       The total consideration for the Sale Shares shall be:
(A)      the payment by BP of the First Consideration Amount in accordance with Clause 4;
(B)      the payment by BP of the Second Consideration Amount in accordance with Clause 6; and
(C)      the payment by BP of the Deferred Consideration Amounts in accordance with Clause 8.
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3.2       Any payment made by either JV Partner under this Agreement, including any payments in respect of claims made under this Agreement, shall (so far as possible) be treated as an adjustment to the consideration for the Sale Shares to the extent of the payment.
4         First Completion
4.1      First Completion shall take place immediately following execution of this Agreement. 
4.2      At First Completion:
(A)      BP shall pay the First Consideration Amount to Kosmos (or to such person as directed by Kosmos) in accordance with Clause 9;
(B)      Kosmos shall deliver to BP (or to such person as directed by BP) duly executed transfers in respect of the Sale Shares in favour of BP (or such person as BP may nominate);
(C)      Kosmos shall procure that the board of directors of JVCo passes a Board resolution approving the transfer of the Sale Shares to BP pursuant to this Agreement and (subject to stamping of the transfers) gives instructions for JVCo to update its register of members to reflect that BP has become the registered holder of the Sale Shares; and
(D)      JVCo shall comply with any other requirements in connection with the transfer of the Sale Shares to which JVCo is subject under applicable law.
4.3      Pending registration of the transfer of the Sale Shares, Kosmos shall:
(A)      hold the legal title to the Sale Shares on trust for BP; and
(B)      on request, provide BP with a voting power of attorney to enable BP to exercise all voting and other rights exercisable by the registered holder of the Sale Shares.
5          Parties’ undertakings prior to Second Completion
5.1      The JV Partners shall each exercise all such rights as are respectively available to them in their capacities as shareholders in JVCo to procure that, between the date of this Agreement and Second Completion, neither JVCo (nor any member of the JVCo Group) shall conduct any business or do any act or thing (or omit to do any act or thing) without the prior written consent of both JV Partners, and in particular, but without limitation to the generality of the foregoing, the JV Partners shall procure that neither JVCo (nor any member of the JVCo Group) shall:
(A)      alter, amend, vary, terminate, assign any interest under, or waive any rights under, the Initial Asset Transfer Agreement or the TC Asset Transfer Agreement;
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(B)      enter into, alter, amend, vary, terminate, assign any interest under, or waive any rights under, any other agreement, contract or commitment;
(C)      acquire, dispose of or Encumber any asset;
(D)      incur any liability or obligation (whether actual or contingent); or
(E)      make any amendment to its capital structure, constitutional documents or tax residence,
save if and to the extent the relevant member of the JVCo Group is required by applicable law or regulation, or in order to comply with its obligations under this Agreement, the Initial Asset Transfer Agreement or the TC Asset Transfer Agreement, to do the relevant act or thing (or omit to do the relevant act or thing).
5.2      The Parties shall use all reasonable endeavours (acting reasonably and in good faith) to negotiate and agree as soon as reasonably practicable the terms of a legally binding shareholders’ agreement and any relevant ancillary documentation (such as constitutional documents, pro forma shareholder loan agreements and services agreements) reflecting the principles described in Clause 5.3  for the purposes of regulating the management of JVCo and the JVCo Group, the relationship of the JV Partners as shareholders in JVCo and certain aspects of the affairs of, and the JV Partners’ dealings with, the JVCo Group (the “ SHA ”). 
5.3      The Parties agree that the SHA will have the objective of achieving a level of governance and control consistent, insofar as practical, with the level of governance and control that the JV Partners would have, were they to hold their respective proportionate interests in JVCo directly as participating interests in the Contracts and the Senegal Area JOAs, whilst reflecting the principles that:
(A)       JVCo is an “Affiliate” of Kosmos for the purposes of all existing contracts, agreements and laws to which Kosmos is party or subject in respect of the Senegal Area;
(B)       JVCo exercises its rights under the Senegal Area JOAs and votes as a single block;
(C)       the JV Partners shall have equal representation on the board of directors of JVCo, with all decisions of the JVCo taken on a joint and equal basis by the JV Partners (or their respective representatives), save in respect of (i) matters which the JV Partners agree should be delegated and (ii) decisions in respect of contracts or disputes which concern a JV Partner, in respect of which the relevant JV Partner shall recuse itself (and/or procure that that its representatives recuse themselves) from relevant decision-making;
(D)      transfers of Ordinary Shares by the JV Partners will be subject to pre-emption rights and, in the case of Kosmos, will be prohibited to the extent that such transfer would otherwise result in (i) the transfer of the Interests to JVCo being
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voided and such Interests being returned to Kosmos pursuant to Article 14.2(b) of the Senegal Area JOAs, or (ii) pre-emption rights over the Interests under a contract or agreement to which Kosmos is party at the date of this Agreement becoming exercisable, unless such rights have been waived;
(E)       provisions will be included in the SHA to provide protections to a JV Partner in the event of a funding default or insolvency by the other JV Partner that are equivalent to and give the same economic benefit as the protections that co-venturers would typically enjoy in a joint operating agreement for an unincorporated joint venture; and
(F)       Kosmos shall not carry out any business other than that of an oil and gas exploration and production company in Senegal and of holding (directly or indirectly) interests in JVCo and/or the Interests, and matters incidental thereto; and
(G)      the provisions of Schedule 1 will be reflected in the SHA and/ or relevant ancillary documentation.
5.4       The Parties intend that the SHA will be finalised and entered into on or before Second Completion, but if it is not:
(A)       the provisions of Clauses 5.2 and 5.3 shall continue to apply;
(B)       the Parties shall proceed to Second Completion, and the Parties’ rights and obligations under this Agreement will not be affected, notwithstanding that the SHA has not been entered into; and
(C)       the Parties shall give effect to the objective and principles described in Clause 5.3 and the provisions of Schedule 1.
5.5       Kosmos will comply with Schedule 2.
5.6       Save as contemplated pursuant to Clauses 4.2 and 6.8, pending Second Completion, neither JV Partner will dispose of any legal or beneficial interest in any Ordinary Shares without the prior written consent of the other JV Partner.
6          Conditions
6.1       Payment of the Second Consideration Amount and each of the Deferred Consideration Amounts is in all respects conditional upon:
(A)      issuance of a decree (Arrête) by the Senegal Minister of Energy and Development of Renewable Energy Resources approving the transfer of Kosmos’s Initial Interests under the Contracts to JVCo (or such approval being deemed effective pursuant to the Contracts) and written approval of such Minister designating JVCo as operator of the Senegal Area and the occurrence of the Initial Asset Transfer Completion; and
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(B)       no notice of termination having been given in accordance with Clause 6.8 prior to the date on which the Condition at sub-clause (A) above is satisfied or waived,
(the “Conditions” and each a “Condition”).
6.2       Each Party shall use commercially reasonable efforts to execute all documents, and do and procure to be done all such acts and things as are reasonably within its power to ensure the Condition in Clause 6.1(A) are satisfied as soon as is reasonably practicable after execution of this Agreement. The Parties shall keep each other informed of progress towards the satisfaction of the Conditions and shall notify one another as soon as is reasonably practicable after they become aware that a Condition has been satisfied. The Conditions may only be waived by agreement in writing between the JV Partners.  Without prejudice to the generality of the foregoing, Kosmos, or a Kosmos Affiliate (other than JVCo) shall offer to provide the Senegal Minister of Energy and Development of Renewable Energy Resources with a guarantee for JVCo’s Paying Interest share of the amount required under the Contracts.
6.3       Notwithstanding any other provision of this Agreement, if, prior to the Second Completion Date, Kosmos or any other person is or becomes the subject of any investigation, inquiry or enforcement proceeding by a governmental, administrative or regulatory body regarding an offence or alleged offence relating to the Interests under any of the Anti-Corruption Laws and Obligations that is likely to result in a material, detrimental impact to the Interests, the Interest Documents or this Agreement, BP shall have the right to terminate this Agreement on notice pursuant to Clause 6.8.
6.4       Notwithstanding any period of Force Majeure under Clause 18.1, if each of the Conditions are not satisfied (or waived pursuant to Clause 6.2) on or before the Longstop Date, then either JV Partner shall have the right to terminate this Agreement on notice pursuant to Clause 6.8.
6.5       Notwithstanding any other provision of this Agreement, BP shall have the right to terminate this Agreement prior to the Second Completion Date on notice pursuant to Clause 6.8, if:
(A)      any of the Kosmos Asset Warranties (other than the warranties in paragraph 4.6(B), 4.9(BB), 4.11(A) insofar as it relates to the TC Interests, and 4.16D of Schedule 3) was at the date of this Agreement, or has since become, untrue in any material respect and is likely to prevent or inhibit the ability of JVCo to take title to the Interests; or
(B)      any of the Kosmos Share Warranties was at the date of this Agreement untrue to an extent which is material in the context of the transactions contemplated by this Agreement; or
(C)      Kosmos is in breach of any material undertaking in this Agreement and the breach is incapable of being cured before the Second Completion Date, has continued without cure for a period of 30 days after the notice of breach from
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the JVCo or BP or remains uncured two (2) days prior to the Second Completion Date.
6.6       If the Government imposes conditions for approval of the assignment and transfer of the Interests or transition of operatorship as contemplated hereunder materially in excess of those which are usually imposed in similar circumstances or if such approval contains unusual and onerous conditions which either JV Partner is not willing to accept, then the JV Partners shall in good faith meet to consider whether to agree to any such conditions for approval by the Government, and if they are unable to agree to such request within 30 days of the notification by the Government of such conditions, the relevant JV Partner shall have the right to terminate this Agreement on notice pursuant to Clause 6.8.
6.7       Notwithstanding any period of Force Majeure under Clause 18.1 if any Party receives notice from the Government of a rejection of the transfer of the Initial Interests pursuant to the Initial Asset Transfer Agreement, then either JV Partner shall have the right to terminate this Agreement on notice pursuant to Clause 6.8.
6.8       A JV Partner may terminate this Agreement pursuant to Clause 6.3, 6.4, 6.5, 6.6 or 6.7 (other than the Surviving Provisions) by giving ten (10) days’ notice to the other Parties.  Unless such notice is withdrawn prior to its expiry then, at noon (UK time) (or such other time as the JV Partners may agree in writing) on the Business Day immediately following the expiry of the notice (the “ Unwind Time ”):
(A)      BP shall sell, with full title guarantee, and Kosmos shall purchase, the Sale Shares free from all Encumbrances, together with all rights attached or accruing to them at the Unwind Time and BP shall deliver to Kosmos duly executed transfers in respect of the Sale Shares in favour of Kosmos and share certificates for the Sale Shares in the name of BP (the “ Unwind Sale ”);
(B)      in consideration for the Unwind Sale, Kosmos shall pay BP an amount equal to the First Consideration Amount by telegraphic transfer for same date value in US dollars in immediately available funds to such account at such bank as BP shall have notified to Kosmos;
(C)      if any BP nominees have been appointed as directors of JVCo prior to the Unwind Time, BP shall procure that such nominees resign as directors of JVCo and waive any claims they may have in connection with their loss of office; and
(D)      this Agreement shall automatically terminate (whereupon all obligations of the Parties under this Agreement shall terminate) but (for the avoidance of doubt) all rights and liabilities of the Parties which have accrued before termination shall continue to exist, save that any obligation to pay any Consideration Amount which has, as at the date of termination, not been paid shall not survive and shall automatically terminate.
6.9       Promptly following completion of the matters set out in Clause 6.8, JVCo shall update its register of members to reflect that Kosmos has become the registered holder of the
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Sale Shares and JVCo shall comply with any other requirements in connection with the transfer of the Sale Shares to which JVCo is subject under applicable law;
7          Second Completion
7.1       Subject always to the provisions of Clause 6.1, Second Completion shall take place on the Second Completion Date. 
7.2       At Second Completion, BP shall pay the sum of forty-one million, nine hundred thousand Dollars (US$ 41,900,000) (the “ Second Consideration Amount ”) to Kosmos (or to such person as directed by Kosmos) in accordance with Clause 9.
7.3       On First Completion, Kosmos shall procure that JVCo appoints Jasper Peijs and John Brame as directors of JVCo provided that such directors have consented to act.
7.4       On or before Second Completion, but in any event no sooner than five Business Days after signing of this Agreement, BP shall deliver to Kosmos:
(A)       a duly executed guarantee from BP Exploration Operating Company Limited in the form set out in Exhibit I Part 1; and
(B)       a duly executed “back-to-back” guarantee from BP Exploration Operating Company Limited in the form set out in Exhibit I Part 2.
8          Deferred Consideration Amounts
8.1       Subject always to the provisions of Clause 6.1, the Parties agree that the Deferred Consideration Amounts shall be payable by BP in accordance with the following provisions of this Clause 8 and Clause 9.
8.2      Interim Period Costs Consideration
(A)      Kosmos shall keep BP advised of the costs expended by Kosmos during the Interim Period.  Specifically, Kosmos shall provide BP with a written statement of the amount of the Dollar balance resulting from the initial calculation of the Interim Period Costs (the “ Monthly Interim Costs Completion Statement ”) no later than thirty (30) days following the end of each calendar month during the Interim Period. Kosmos and BP agree that if the information required for such timely preparation of a Monthly Interim Costs Completion Statement is not available, Kosmos’s good faith estimate of such information shall be substituted.
(B)      Within sixty (60) days after the Second Completion Date, or within such other period as may be agreed in writing by the Parties, Kosmos shall provide BP with a written statement giving the final amount of the Interim Period Costs (the “ Final Completion Statement ”).  Upon BP’s request, Kosmos shall provide BP with copies of reports, billing statements and correspondence and any other relevant documentation in Kosmos’s possession in support of the Final Completion Statement within ten (10) Business Days of such request, which
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shall be made no later than ten (10) Business Days from the date the Final Completion Statement is supplied to BP.  BP shall have the right, for a period of ninety (90) days following the date of delivery of the Final Completion Statement, to audit the Interim Period Costs on prior notice and during reasonable business hours in Kosmos’s offices; and Kosmos shall provide such confirmation of the said Interim Period Costs as may be requested by BP in order to confirm the amount of Interim Period Costs. Kosmos and BP shall endeavor in good faith to resolve any item of adjustment to the Interim Period Costs in the Final Completion Statement within one hundred twenty (120) days following the date of delivery of the Final Completion Statement.  The agreed amount of the Interim Period Costs shall be subject to no adjustment or amendment. In the event that the Kosmos and BP are unable to agree upon any item of adjustment within the above period, such amount shall be determined in accordance with the procedures for settling disputed invoices under the Senegal Area JOAs.
(C)       Kosmos shall provide BP with copies of all operator reports, billing statements and correspondence and any other relevant documentation in support of the Monthly Interim Costs Completion Statement and the Final Completion Statement at the same time such statements are supplied.
(D)      The Interim Period Costs Consideration shall be paid by BP to Kosmos in accordance with Clause 9 within five (5) Business Days of the delivery of the Final Completion Statement (pursuant to Clause 8.2(B)), but without prejudice to BP's subsequent rights of audit and dispute under Clause 8.2(B).
8.3       Exploration and Appraisal Carry Consideration
(A)      The “Exploration and Appraisal Carry Consideration” shall be an amount equal to 50.01 per cent of, Kosmos’s Paying Interest share (prior to Initial Asset Transfer Completion), and JVCo’s Paying Interest share (subsequent to Initial Asset Transfer Completion), of costs otherwise due and payable by Kosmos or JVCo (as applicable) after the Effective Date under the terms of the Senegal Area JOAs (including, for these purposes, Timis Corporation’s remaining interest share of the first one hundred and twenty million Dollars (US$120,000,000) of gross costs (including all general and administration costs and expenses (G&A)) to drill one exploration well or appraisal well (including testing) in the Senegal Area, the costs of which are to be carried pursuant to the TC Option, but excluding Timis Corporation’s remaining interests shares in respect of other costs in respect of the Senegal Area) pursuant to an approved work programme and budget thereunder in connection with all activities other than those activities covered under Clause 8.4 (the “ Carried Exploration Costs ”) PROVIDED THAT:
(i)        the aggregate amount of (x) the Exploration and Appraisal Carry Consideration paid by BP under this Clause and (y) the Exploration and Appraisal Carry (as such term is defined in the Mauritania Farmout Agreement) paid by the Farmee (as such term is defined in the
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Mauritania Farmout Agreement) (but excluding, for these purposes, amounts payable pursuant to Clause 8.3(B)(ii)) (the “ Combined Exploration Total ”) shall not exceed two hundred and twenty-one million Dollars ($US 221,000,000) (the “ Combined Exploration Limit ”);
(ii)       if the Mauritania Farmout Agreement terminates in accordance with its terms for any reason other than breach by BP Exploration (West Africa) Limited, the aggregate amount of the Exploration and Appraisal Carry Consideration paid by BP under this Clause (excluding, for these purposes, amounts payable pursuant to Clause 8.3(B)(ii)) (the “ Standalone Exploration Total ”) shall not exceed fifty-seven million, two hundred thousand Dollars ($US 57,200,000) (the “ Standalone Exploration Limit ”); and
(iii)      the Exploration and Appraisal Carry Consideration shall only apply in respect of Carried Exploration Costs that are due and payable on or before 31 December 2022.
(B)      The Exploration and Appraisal Carry Consideration shall be payable by BP whenever JVCo is required to make any payment in respect of Carried Exploration Costs.  BP will pay the Exploration and Appraisal Carry Consideration in sufficient time for JVCo to make such payments when due.  Kosmos hereby directs BP to pay the Exploration and Appraisal Carry Consideration (other than the payments described in paragraphs (C) and (D) below) direct to JVCo on Kosmos’s behalf and Kosmos hereby undertakes not to revoke such payment direction without BP’s prior written consent.  Payments made by BP direct to JVCo in this way:
(i)        shall discharge BP’s obligation to make the relevant payment of Exploration and Appraisal Carry Consideration;
(ii)       subject to the payment direction issued by Kosmos pursuant to this Clause 8.3(B) not having previously been revoked, shall be accompanied by an equivalent payment from BP (on its own account) to JVCo equal to 49.99% of JVCo's Paying Interest Share of costs otherwise due and payable by JVCo after the Effective Date under the terms of the Senegal Area JOAs; and
(iii)      shall be paid and structured in a tax efficient manner (including by loan or a capital injection or a combination of both) from Kosmos to JVCo and the own account payment made by BP referred to in sub-paragraph (ii) above shall be paid from BP to JVCo and structured in a tax efficient manner (including by loan or a capital injection or a combination of both).
(C)      If the Combined Exploration Total as at 1 January 2023 is less than the Combined Exploration Limit and sub-paragraph (A)(ii) above does not apply, BP shall pay an amount equal to the shortfall by no later than 1 February 2023
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either to Kosmos’s Account in accordance with Clause 9 or, at Kosmos’s election, all or a portion of the shortfall will be paid to Kosmos Mauritania under the Mauritania Farmout Agreement with the balance being paid to Kosmos pursuant to this Clause and Clause 9.
(D)      If sub-paragraph (A)(ii) above does apply and the Standalone Exploration Total as at 1 January 2023 is less than the Standalone Exploration Limit, BP shall pay an amount equal to the shortfall to Kosmos’s Account in accordance with Clause 9 by no later than 1 February 2023.
8.4       Development Carry Consideration
(A)      The “Development Carry Consideration” shall be an amount equal to 50.01 per cent of Kosmos’s Paying Interest share (prior to Initial Asset Transfer Completion), and JVCo’s Paying Interest share (subsequent to Initial Asset Transfer Completion), of costs that are properly incurred and due and payable by Kosmos or JVCo (as applicable) after the Effective Date under the terms of the Senegal Area JOAs pursuant to an approved work programme and budget thereunder in connection with achieving Commercial Production of Hydrocarbons (as defined under the Contracts) from the Tortue Discovery Area as shown in Exhibit C, Part 1, including the Firm Work Programme (Development) in Exhibit A 2, or any alternative development in the Senegal Area (the “ Carried Development Costs ”) PROVIDED THAT:
(i)        the aggregate amount of (x) the Development Carry Consideration paid by BP under this Clause and (y) the Development Carry (as such term is defined in the Mauritania Farmout Agreement) paid by the Farmee (as such term is defined in the Mauritania Farmout Agreement) (but excluding, for these purposes, amounts payable pursuant to Clause 8.4(B)(ii)) shall not exceed five hundred and thirty-three million, four hundred thousand Dollars ($US 533,400,000);
(ii)       if the Mauritania Farmout Agreement terminates in accordance with its terms for any reason other than breach by BP Exploration (West Africa) Limited, the aggregate amount of the Development Carry Consideration paid by BP under this Clause (but excluding, for these purposes, amounts payable pursuant to Clause 8.4(B)(ii)) shall not exceed one hundred and eighty-three million, four hundred thousand Dollars ($US 183,400,000); and
(iii)      the Development  Carry Consideration shall only apply in respect of Carried Development Costs that are due and payable on or before the date on which first Commercial Production from a development within an Exploitation Perimeter is achieved from the Senegal Area and/or the Mauritania Area.
(B)      The Development Carry Consideration shall be payable by BP whenever JVCo is required to make any payment in respect of Carried Development Costs.  BP
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will pay the Development Carry Consideration in sufficient time for JVCo to make such payments when due.  Kosmos hereby directs BP to pay the Development Carry Consideration direct to JVCo on Kosmos’s behalf and Kosmos hereby undertakes not to revoke such payment direction without BP’s prior written consent.  Payments made by BP direct to JVCo in this way:
(i)        shall discharge BP’s obligation to make the relevant payment of Development Carry Consideration;
(ii)       subject to the payment direction issued by Kosmos pursuant to this Clause 8.4(B) not having previously been revoked shall be accompanied by an equivalent payment from BP (on its own account) to JVCo equal to 49.99% of JVCo's Paying Interest Share of costs otherwise due and payable by JVCo after the Effective Date under the terms of the Senegal Area JOAs; and
(iii)      shall be paid and structured in a tax efficient manner (including by loan or a capital injection or a combination of both) from Kosmos to JVCo and the own account payment made by BP referred to in sub-paragraph (ii) above shall be paid from BP to JVCo and structured in a tax efficient manner (including by loan or a capital injection or a combination of both).
(C)      For the avoidance of any doubt, there shall be no double-counting of amounts payable under Clause 8.3 and this Clause 8.4, with the intention that BP shall not be required to pay more than once in respect of the same costs.
8.5       Success Fee Consideration
(A)      The Success Fee Consideration in respect of each Eligible Discovery shall be paid quarterly by BP, or BP’s Affiliate, to Kosmos, or (at Kosmos’s election) Kosmos’s Affiliate, by electronic transfer in immediately available funds into Kosmos’s Account no later than thirty (30) days following the end of each Quarter after the date Commercial Production exceeds twenty thousand Barrels per day (20mbd) from such Eligible Discovery and in respect of each Barrel (as defined under the Contracts) of gross production of liquid Hydrocarbons (as defined under the Contracts) in the natural state or obtained from Natural Gas by condensation or separation with an API gravity equal to or greater than 22.3°, but excluding LNG, produced from such Eligible Discovery in the immediately preceding Quarter.
(B)      The obligation to pay Success Fee Consideration falling within limb (i) of such definition shall expire on the earlier of (a) when the aggregate gross cumulative production from all Eligible Discoveries and all Eligible Discoveries (as such term is defined in the Mauritania Farmout Agreement) exceeds one Billion Barrels (1bnbbl); and (b) in respect of an Eligible Discovery, fifteen (15) years after the date of first production from such Eligible Discovery.  The obligation to pay Success Fee Consideration falling within limb (ii) of such definition shall
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expire five (5) years after the date when the aggregate gross cumulative production from all Eligible Discoveries and all Eligible Discoveries (as such term is defined in the Mauritania Farmout Agreement) exceeds one Billion Barrels (1bnbbl).
(C)      If an index is required to be used in the calculation of Brent, and such index ceases to be published, either Kosmos or BP may request the adoption of such substitute index as most closely resembles the original index prior to it ceasing to be published or changing. If the Parties are unable to agree within sixty (60) days of such request, the matter shall be referred for determination under Article 11.2.
(D)      To the extent that a Success Fee (as defined in the Mauritania Farmout Agreement) is payable under the Mauritania Farmout Agreement and Success Fee Consideration is payable under this Agreement in respect of the same discovery, there shall be no double-counting of amounts payable under the Mauritania Farmout Agreement with amounts payable under this Agreement with the intention that BP shall not be required to pay more than once in respect of the same production.
8.6      Other Costs and Cost Recovery
(A)      On and from the Effective Date JVCo shall assume and be liable for its Participating Interest share of costs incurred under the Contracts or Senegal Area JOAs pursuant to their terms.   Any costs for which Kosmos or JVCo would otherwise be liable under the terms of the Senegal Area JOAs between the Effective Date and the Second Completion Date shall be funded by Kosmos (as to 50.01% for its own account and 49.99% on behalf of BP) and 49.99% of such costs shall be paid to Kosmos by BP after the Second Completion Date pursuant to Clause 8.2.
(B)      JVCo shall be entitled to recover its Participating Interest share of costs incurred under the Contracts upon commencement of production from the relevant portion of the Senegal Area regardless of whether the costs were incurred before or after the Effective Date. For the avoidance of doubt, such Participating Interest share shall be the Participating Interest held at the time such costs become recoverable under the Contracts after the commencement of production and to the extent that any person (the " Receiving Party ") receives the Participating Interest share of costs that should otherwise have been paid to JVCo, the Receiving Party shall pay such sums to JVCo within five (5) Business Days of receipt thereof.
8.7      Change in Participating Interest
(A)      If JVCo owns less than a 65% Participating Interest as at 01 July 2018 (or such later date as the JV Partners may agree) other than as a result of JVCo selling part or all of its Participating Interest, then:
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(i)        the amount payable by BP under Clause 7.2;
(ii)       the maximum amount payable by BP pursuant to Clause 8.3(A) (ii);
(iii)      the maximum amount payable by BP pursuant to Clause 8.4(A)(ii); and
(iv)      the multiplier in limb (i) of the definition of Success Fee Consideration,
shall, in each case, be reduced in proportion to the amount by which the Participating Interest so owned is less than 65%, and:
(a)       the maximum amount payable by BP pursuant to Clause 8.3(A)(i) shall be reduced by the same amount by which the maximum amount referred to in (ii) above is reduced; and
(b)       the maximum amount payable by BP pursuant to Clause 8.4(A)(i) shall be reduced by the same amount by which the maximum amount referred to in (iii) above is reduced; and
(c)       all calculations resulting from the reduction in (iv) above shall be applied within the limb(i) of the definition of Success Fee Consideration.
(B)      By way of example, if JVCo owns a 64% Participating interest as at the 01 July 2017, the amounts referred to above would be adjusted as follows:
 	 	 	 	
 	 	Original Amount	Revised Amount	
 	Clause 7.2	$41,900,000	$41,300,000	
 	Clause 8.3(A)(ii)	$57,200,000	$56,400,000	
 	Clause 8.4(A)(ii)	$183,400,000	$180,600,000	
 	Clause 8.3(A)(i)	$221,000,000	$220,200,000	
 	Clause 8.4(A)(i)	$533,400,000	$530,600,000	
 	Limb (i) of Success Fee Consideration	$0.00875	$0.00862	
 	 	$0.525	$0.517	
 	 	$1.05	$1.03	
 
(C)       If the Second Consideration Amount has already been paid when the adjustments described above are made, Kosmos shall repay to BP an amount equal to the amount by which the Second Consideration Amount is so adjusted.
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(D)      If the Participating Interest of JVCo subsequently increases to or above 65%, the adjustments described above will be reversed and appropriate adjusting payments made.
9          Payment
Where a Consideration Amount is expressed to be payable in accordance with or pursuant to this Clause 9, the relevant Consideration Amount payable by BP shall be paid to Kosmos (or to such person as Kosmos shall specify in writing) by telegraphic transfer for same date value on the due date for payment in US dollars in immediately available funds to Kosmos’s Account.
10        Parties’ warranties
10.1     Kosmos’s Warranties and Undertakings
Subject to the provisions of this Clause 10, and save as disclosed under the terms of the Kosmos Disclosure Letter, Kosmos warrants and undertakes to BP as at the date of this Agreement that:
(A)      the Kosmos Warranties and the warranty at paragraph 1 of Exhibit B are true and accurate in all respects as at the date of this Agreement;
(B)      save as provided in Clause 10.1(C), the Kosmos Asset Warranties and the warranty at paragraph 1 of Exhibit B shall be deemed to be repeated at the Initial Asset Transfer Completion Date; and
(C)      the Kosmos Asset Warranty at paragraphs 4.6(B), 4.9(BB), 4.16(D) and (insofar as it relates to the TC Interests) 4.11(A) of Part 1 of Schedule 3 shall be deemed to be repeated at the TC Asset Transfer Completion Date.
10.2     BP’s Warranties and Undertakings
BP warrants and undertakes to Kosmos as at the date of the Agreement that the BP Warranties and the warranty at paragraph 1 of Exhibit B are true and accurate in all respects, and the BP Warranties and the warranty at paragraph 1 of Exhibit B shall be deemed to be repeated at the Second Completion Date.
10.3     Breach of Warranty
(A)      Each of the JV Partners agrees to indemnify and hold the other JV Partner harmless against any costs, charges, expenses, duties, losses, liabilities and obligations which such other JV Partner pays, suffers or is liable for at any time which arise out of or in connection with the breach by the indemnifying Party of, in the case of Kosmos, any of the Kosmos Share Warranties, or, in the case of BP, any of the BP Warranties.
(B)      Kosmos covenants to pay and hold BP harmless against an amount equal to the Relevant Portion of any costs, charges, expenses, duties, losses, liabilities
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and obligations ("Relevant Losses") which JVCo pays, suffers or is liable for at any time which arise out of or in connection with the breach by Kosmos of any of the Kosmos Asset Warranties. For these purposes, the Relevant Portion shall be the lesser of (i) 49.99% and (ii) if the proportionate interest in the Ordinary Share capital of JVCo held by BP and its Affiliates is less than 49.99%, an amount equal to BP's (together with its Affiliates') then proportionate interest share of the ordinary shares of JVCo plus the amount of any liability BP has to the acquirer(s) of the Ordinary Shares in respect of the same Relevant Losses.
(C)      Kosmos shall have no liability in respect of any claim made by BP for a breach of the Kosmos Warranties, and BP shall have no liability in respect of any claim made by Kosmos for a breach of BP Warranties, unless such claim:
(i)        equals or exceeds one million Dollars (US$1,000,000); or
(ii)       when aggregated with all other valid claims the Party concerned  may have against the other Party that are each of a value under one million Dollars (US$1,000,000), would mean such aggregate equals or exceeds one million Dollars (US$1,000,000),
and in either case the Party concerned shall be entitled to recover the whole amount of the relevant claim(s) not only the amount the relevant claim(s) (alone or aggregated) exceed one million Dollars (US$1,000,000).
(D)      Kosmos shall not be liable in respect of a claim for breach of a Kosmos Warranty set out in paragraphs 4.18(A) or 4.18(B) of Schedule 3 Part 1 or the warranty at paragraph 1 of Exhibit B to the extent that, as at the date of this Agreement, BP was actually aware: (i) of the facts or circumstances giving rise to the claim for breach of such Kosmos Warranty or the warranty set out at paragraph 1 of Exhibit B; and (ii) that such facts or circumstances would give rise to a claim for breach of such Kosmos Warranty or the warranty at paragraph 1 of Exhibit B.
10.4      Undertakings in relation to breaches
(A)      Kosmos undertakes that:
(i)        it shall not at any time before the Second Completion Date do (or permit or suffer to subsist or be done) any act or thing which would constitute a breach of any of the Kosmos Asset Warranties or the warranty at paragraph 1 of Exhibit B or which would make any of the Kosmos Asset Warranties untrue or misleading at any time; and
(ii)       upon becoming aware before the Second Completion Date of the actual or impending occurrence or non-occurrence of any matter, event or circumstance (including any omission to act) which:
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(a)       would or might reasonably be expected to cause or constitute a breach of any Kosmos Asset Warranty or the warranty at paragraph 1 of Exhibit B;
(b)       would or might reasonably be expected to make any of the Kosmos Asset Warranties or the warranty at paragraph 1 of Exhibit B untrue or misleading;
(c)       would have caused or constituted a breach of any Kosmos Asset Warranty or the warranty at paragraph 1 of Exhibit B had it been known to Kosmos before the date of this Agreement; or
(d)       would or might reasonably be expected to adversely affect (or has so affected) the Interests,
it will immediately give BP notice of such matter, event or circumstance with sufficient details to enable BP accurately to assess its impact.
(B)      BP undertakes that:
(i)        it shall not at any time before the Second Completion Date do (or permit or suffer to subsist or be done) any act or thing which would constitute a breach of any of the BP Warranties or the warranty at paragraph 1 of Exhibit B or which would make any of the BP Warranties or the warranty at paragraph 1 of Exhibit B untrue or misleading at any time; and
(ii)       upon becoming aware before the Second Completion Date of the actual or impending occurrence or non-occurrence of any matter, event or circumstance (including any omission to act) which:
(a)       would or might reasonably be expected to cause or constitute a breach of any BP Warranty or the warranty at paragraph 1 of Exhibit B;
(b)       would or might reasonably be expected to make any of the BP Warranties or the warranty at paragraph 1 of Exhibit B untrue or misleading;
(c)       would have caused or constituted a breach of any BP Warranty or the warranty at paragraph 1 of Exhibit B had it been known to BP before the date of this Agreement; or
(d)       would or might reasonably be expected to adversely affect (or has so affected) the Interests,
it will immediately give Kosmos notice of such matter, event or circumstance with sufficient details to enable Kosmos accurately to assess its impact. 
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10.5     Disclaimer of Other Representations and Warranties
(A)      Except for the Kosmos Warranties and the warranty in paragraph 1 of Exhibit B, Kosmos makes no, and disclaims any, warranty or representation of any kind, either express, implied, statutory, or otherwise, including, the accuracy or completeness of any data, reports, records, projections, information, or materials now, heretofore, or hereafter furnished or made available to JVCo or BP in connection with this Agreement.
(B)      Except for the BP Warranties and the warranty in paragraph 1 of Exhibit B, BP makes no, and disclaims any, warranty or representation of any kind, either express, implied, statutory, or otherwise, including, without limitation, the accuracy or completeness of any data, reports, records, projections, information, or materials now, heretofore, or hereafter furnished or made available to Kosmos in connection with this Agreement.
10.6     Fraud and Wilful Concealment
Notwithstanding anything to the contrary herein, nothing in this Agreement shall limit any Party’s liability for fraud or willful concealment.
10.7     Set-off
BP is hereby authorized and entitled at any time and from time to time, to the fullest extent permitted by law, to withhold and set-off from any payment otherwise due to be made to Kosmos pursuant to Clauses 6 to 8 of this Agreement or from any payment due to be made by BP’s Affiliate to Kosmos Mauritania pursuant to clauses 4.3 to 4.6 of the Mauritania Farmout Agreement an amount equal to the amount owing pursuant to any and all Kosmos Payment Failures.
11        Further assurance
11.1     Each of the JV Partners shall at its own cost, from time to time on request, do or procure the doing of all acts and/or execute or procure the execution of all documents in a form reasonably satisfactory to the other JV Partner which the other JV Partner (acting reasonably) may consider necessary for giving full effect to this Agreement and the transactions contemplated by it.
11.2     Each of the JV Partners agrees to co-operate in good faith with the other in order to finalise the structure for the proposed joint venture between them, with the common intention that the Parties will seek to implement a structure that is efficient and cost-effective. The Parties recognise that this may involve changes to the structure currently envisaged in this Agreement, such as the introduction of a new joint venture holding company above JVCo or a new asset-owning subsidiary of JVCo.
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12        Variation
No variation to or waiver under this Agreement shall be effective unless made in writing and signed by or on behalf of all the Parties.
13        Confidentiality and Announcements
13.1     Except as otherwise provided in the Contracts and the Senegal Area JOAs, each Party agrees that the existence of and all terms of this Agreement and all information disclosed under this Agreement by either Party (except information in the public domain or lawfully in possession of a Party prior to the date of this Agreement) shall be considered confidential information and shall not be disclosed to any other person or entity without the prior written consent of the other Parties. This obligation of confidentiality shall remain in force during the term of the Contracts and for a period of three (3) years thereafter. Notwithstanding the foregoing, confidential information may be disclosed without consent and without violating the obligations contained in this Clause 13 in the following circumstances:
(A)      to an Affiliate provided the Affiliate is bound to the provisions of this Article 9 and the Party disclosing is responsible for the violation of an Affiliate;
(B)      to a governmental agency or other entity when required by the Contracts;
(C)      to the extent such information is required to be furnished in compliance with applicable laws or regulations, or pursuant to any legal proceedings or because of any order of any court binding upon a Party;
(D)      to attorneys engaged, or proposed to be engaged, by any Party where disclosure of such information is essential to such attorneys' work for such Party and such attorneys are bound by an obligation of confidentiality;
(E)      to contractors and consultants engaged, or proposed to be engaged, by any Party where disclosure of such information is essential to such contractor’s or consultant’s work for such Party;
(F)       to a bank or other financial institution to the extent appropriate to a Party arranging for funding;
(G)      to the extent such information must be disclosed pursuant to any rules or requirements of any government or stock exchange having jurisdiction over such Party, or its Affiliates; provided that such Party shall comply with the requirements of Clause 13.3;
(H)      to its respective employees, subject to each Party taking sufficient precautions to ensure such information is kept confidential;
(I)        to the other parties to the Contracts and the Senegal Area JOAs and the Government; and
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(J)        to the other parties, including the Government of the Islamic Republic of Mauritania, to the Mauritania Contracts, solely to the extent as may be required to satisfy the conditions precedent specified in the Mauritania Farmout Agreement.
13.2     Disclosure pursuant to Clauses 13.1 (v) and (vi) shall not be made unless prior to such disclosure the disclosing Party has obtained a written undertaking from the recipient party to keep the information strictly confidential for at least as long as the period set out above and to use the information for the sole purpose described in Clauses 13.1(v) and (vi), whichever is applicable, with respect to the disclosing Party.
13.3     No public announcement or statement regarding the terms or existence of this Agreement shall be made without prior written consent of all Parties; provided that, notwithstanding any failure to obtain such approval, no Party shall be prohibited from issuing or making any such public announcement or statement to the extent it is necessary to do so in order to comply with the applicable laws, rules or regulations of any government, legal proceedings or stock exchange having jurisdiction over such Party or its Affiliates, however, any such required public announcement or statement shall include only that portion of information which the disclosing Party is advised by written opinion of counsel (including in-house counsel) is legally required.  Such opinion, along with the proposed public announcement or statement, shall be delivered to the other Party no later than two days prior to any such public announcement or statement.
14       Notices
14.1     All notices authorized or required between the Parties by any of the provisions of this Agreement shall be:
(A)      in writing (in English) and addressed to the relevant Party as set out in this Clause (unless such party gives notice in writing of a change of address or addressee as set out below);
(B)      must be signed or in the case of a facsimile, appear to have been signed, by an authorized representative of the sender;
(C)      regarded as given and received:
(i)        if delivered by hand or by express courier, when delivered to the addressee; or
(ii)       if sent by post, three Business Days from and including the date of postage; or
(iii)      if sent by facsimile transmission, when the transmission is successfully transmitted as reported by the sender’s machine,
but if the delivery or receipt is on a day which is not a Business Day or is after 4.00pm (addressee’s time) it is regarded as received at 9:00am on the following Business Day.
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E-mail notification of any notices delivered pursuant to this Article will also be provided for information only.
14.2     A facsimile transmission is not regarded as successfully transmitted if the addressee telephones the sender within four (4) hours after the transmission is received or regarded as received under Clause 14.1(C)(iii) and informs the sender that it is not legible or incomplete.  E-mail addresses are provided for convenience only.
KOSMOS:
 	 	
Kosmos Energy Senegal	 	
c/o Wilmington Trust (Cayman Islands)	c/o Kosmos Energy, LLC	
4th Floor, Century Yard	8176 Park Lane, Suite 500	
Cricket Square, Hutchins Drive	Dallas, TX  75231 USA	
Elgin Avenue, George Town	Grand Cayman KY1-1209	
 
E-mail: kosmosgeneralcounsel@kosmosenergy.com	
Fax: +1 214 445-9705	
Attn.: General Counsel	
E-mail: SenegalNotifications@kosmosenergy.com	
Fax:  +1 214 445-9705	
Attn.: Jesse Noah, Vice President, Exploration, North Africa	
 
BP:  
BP Exploration Operating Company Limited
Lakeview Building
Chertsey Road
Sunbury-on-Thames
Middlesex
TW16 7LN
United Kingdom
E-mail: andy.lane@uk.bp.com
Fax: +44 (0) 1932 763043
Attn.:      Andy C. Lane, Head of Business Development, Gas Value Chain
JVCo:  
Shall be to both JV Partners as above
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15        Tax; Costs
15.1     Kosmos shall pay, and shall indemnify and hold JVCo and BP harmless against any liability for any capital gains tax (or equivalent tax) which may be, or become, payable in connection with the sale, assignment or transfer of the Interests pursuant to the Initial Asset Transfer Agreement or the TC Asset Transfer Agreement and in respect of any costs (including reasonable legal costs), expenses, loss or damage occasioned by its failure to pay, or any delay in paying, such tax.
15.2     BP shall be responsible for payment in a timely fashion of any and all transfer taxes, such as stamp duties and taxes (or equivalent duties and taxes) (including interest, penalties and/or fines thereof) (the “ Share Transfer Taxes ”) payable on or in respect of the sale and purchase or transfer of the Sale Shares including the execution and enforcement of this Agreement and shall indemnify and hold JVCo and Kosmos harmless in respect of any costs (including reasonable legal costs), expenses, loss or damage occasioned by its failure to pay, or any delay in paying, such Share Transfer Taxes.
15.3     The JV Partners shall be responsible for payment to JVCo in a timely fashion of any and all transfer taxes, such as stamp duties and taxes (or equivalent duties and taxes) (including interest, penalties and/or fines thereof) (the “ Asset Transfer Taxes ”) payable on or in respect of the assignment and transfer of the Interests to JVCo pursuant to the Initial Asset Transfer Agreement or the TC Asset Transfer Agreement. Each JV Partner shall indemnify and hold JVCo and the other JV Partner harmless in respect of any costs (including reasonable legal costs), expenses, loss or damage occasioned by its failure to pay, or any delay in paying, such Asset Transfer Taxes, in each case on the basis that (i) 50.01% of any and all such amounts shall be for the account of Kosmos and (ii) 49.99% any and all such amounts shall be for the account of BP.
15.4     Except as otherwise stated in this Agreement, each Party shall pay its own costs and expenses in relation to the preparation, execution and carrying into effect of this Agreement and all other documents entered into pursuant to, or in connection with, it.
15.5     If, for United States federal income tax purposes, this Agreement and the operations under this Agreement are regarded as a partnership and if the Parties have not agreed to form a tax partnership, each Party elects to be excluded from the application of all of the provisions of Subchapter “K”, Chapter 1, Subtitle “A” of the United States Internal Revenue Code of 1986, as amended (the “ Code ”), to the extent permitted and authorized by Section 761(a) of the Code and the regulations promulgated under the Code.  JVCo, if it is a U.S. Party, is authorized and directed to execute and file for each Party such evidence of this election as may be required by the Internal Revenue Service, including all of the returns, statements, and data required by United States Treasury Regulations Sections 1.761-2 and 1.6031(a)-1(b)(5) and shall provide a copy thereof to each U.S. Party.  However, if JVCo is not a U.S. Party, the Party who holds the greatest Participating Interest among the U.S. Parties shall fulfill the obligations of JVCo under this Clause 15.5.  Should there be any requirement that any Party give further evidence of this election, each Party shall execute such documents and furnish such other evidence as may be required by the Internal Revenue Service or as may be necessary to evidence this election.
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15.6     No US Party shall give any notice or take any other action inconsistent with the foregoing election described at Clause 15.5.  If any income tax laws of any state or other political subdivision of the United States or any future income tax laws of the United States or any such political subdivision contain provisions similar to those in Subchapter “K”, Chapter 1, Subtitle “A” of the Code, under which an election similar to that provided by Section 761(a) of the Code is permitted, each Party shall make such election as may be permitted or required by such laws.  In making the foregoing election or elections, each U.S. Party states that the income derived by it from operations under this Agreement can be adequately determined without the computation of partnership taxable income.
15.7     Unless approved by every Non-U.S. Party, no activity shall be conducted under this Agreement that would cause any Non-U.S. Party to be deemed to be engaged in a trade or business within the United States under United States income tax laws and regulations.
16        Contracts (Rights of Third Parties) Act 1999
The Parties do not intend that any term of this Agreement should be enforceable, by virtue of the Contracts (Rights of Third Parties) Act 1999, by any person who is not a party to this Agreement.
17        Counterparts
This Agreement may be executed in any number of counterparts, and by the Parties on separate counterparts, but shall not be effective until each Party has executed at least one counterpart.  Each counterpart shall constitute an original of this Agreement, but all the counterparts shall together constitute but one and the same instrument.
18        Miscellaneous
18.1     Force Majeure
If as a result of Force Majeure, any Party is rendered unable, wholly or in part, to carry out its rights or obligations under this Agreement, other than the obligation to pay any amounts due, then the rights or obligations of the Party giving such notice, so far as and to the extent that the rights or obligations are affected by such Force Majeure, shall be suspended during the continuance of any inability so caused and for such reasonable period thereafter as may be necessary for the Party to put itself in the same position that it occupied prior to the Force Majeure, but for no longer period.  The Party claiming Force Majeure shall notify the other Parties of the Force Majeure within a reasonable time after the occurrence of the facts relied on and shall keep all Parties informed of all significant developments. Such notice shall give reasonably full particulars of the Force Majeure and also estimate the period of time which the Party will probably require to remedy the Force Majeure.  The affected Party shall use all reasonable diligence to remove or overcome the Force Majeure situation as quickly as possible in a commercially reasonable manner but shall not be obligated to settle any labor dispute except on terms acceptable to it. All such disputes shall be handled within the sole
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discretion of the affected Party.  For the purposes of this Agreement, “Force Majeure”  shall have the same meaning as is set out in the Contracts.
18.2     BP Payment Default
If BP fails to make any payment (or part thereof) that becomes due and payable pursuant to the terms of this Agreement by the due date for payment it shall pay interest on such sum for the period from and including the due date up to the date of actual payment at the rate per annum which is the aggregate of the one (1) month term, London Interbank Offered Rate (LIBOR rate) for U.S. dollar deposits (as published in London by the Financial Times  or if not published, then by  The Wall Street Journal ) and five (5) percentage points. The interest will accrue from day to day on the basis of the actual number of days elapsed and a 365-day year and shall be payable and compounded monthly.  If the aforesaid rate is contrary to any applicable usury law, the rate of interest to be charged shall be the maximum rate permitted by such applicable law.
18.3     Relationship of Parties
The rights, duties, obligations and liabilities of the Parties under this Agreement shall be individual, not joint or collective.  It is not the intention of the Parties to create, nor shall this Agreement be deemed or construed to create, a mining or other partnership, or association or a trust.  This Agreement shall not be deemed or construed to authorize any Party to act as an agent, servant or employee for any other Party for any purpose whatsoever except as explicitly set forth in this Agreement.  In their relations with each other under this Agreement, the Parties shall not be considered fiduciaries except as expressly provided in this Agreement.
18.4     Joint Preparation
Each provision of this Agreement shall be construed as though all Parties participated equally in the drafting of the same. Consequently, the Parties acknowledge and agree that any rule of construction that a document is to be construed against the drafting party shall not be applicable to this Agreement.
18.5     Severance of Invalid Provisions
If and for so long as any provision of this Agreement shall be deemed to be judged invalid for any reason whatsoever, such invalidity shall not affect the validity or operation of any other provision of this Agreement except only so far as shall be necessary to give effect to the construction of such invalidity, and any such invalid provision shall be deemed severed from this Agreement without affecting the validity of the balance of this Agreement.
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18.6     Assignment
(A)      Subject to Clauses 18.6(B) and 18.6(C), there shall be no modification or assignment of this Agreement or the rights and obligations under it except by written consent of the Parties.
(B)      BP shall be entitled to assign, novate or transfer its rights and obligations under this Agreement to a Wholly-Owned Affiliate of BP, and Kosmos shall sign any documentation reasonably required in order to effect such assignment, novation or transfer.
(C)      Subject always to Clause 5.3(D), Kosmos shall be entitled to assign, novate or transfer its rights and obligations under this Agreement to a Wholly-Owned Affiliate of Kosmos, provided that any assignment, novation or transfer of any of Kosmos's obligations under this Agreement shall be subject to and conditional upon Kosmos having first delivered to BP a legally binding and enforceable guarantee from the ultimate parent company of Kosmos and the Wholly-Owned Affiliate (in a form reasonably acceptable to BP) guaranteeing the performance and payment of all obligations and liabilities of Kosmos under this Agreement. Subject to satisfaction of the requirements of this Clause, BP shall sign any documentation reasonably required in order to effect such assignment, novation or transfer. In the event that a Kosmos parent guarantee is delivered to BP in accordance with this Clause, the obligations of Kosmos under Clause 10.7 shall cease to apply from the effective date of such Kosmos parent guarantee.
18.7     Priority
In the event of any conflict between the provisions of the main body of this Agreement and its Schedules or Exhibits, the provisions of the main body shall prevail. In the event of any conflict between the Schedules and the Exhibits, the provisions of the Schedules shall prevail.  In the event of any conflict between this Agreement and the Senegal Area JOAs, this Agreement shall prevail. In the event of any conflict between this Agreement and the Contracts, this Agreement shall prevail unless such would be in violation of the laws or regulations of the Republic of Senegal or the terms of the Contracts.
18.8     Entirety
With respect to the subject matter contained herein, this Agreement and the other agreements to be entered into pursuant to it constitute the entire agreement of the Parties; and supersede all prior understandings and negotiations of the Parties, including the confidentiality agreement made between the Parties dated 5 April 2016.
19        Governing law and Dispute Resolution
19.1     This Agreement, and any non-contractual rights or obligations arising out of or in connection with it or its subject matter, shall be governed by and construed in accordance with the laws of England and Wales, excluding any choice of law rules which would refer the matter to the laws of another jurisdiction.
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19.2      (A)     Any and all claims, demands, causes of action, disputes, controversies and other matters in question arising out of or relating to this Agreement, including any question regarding its breach, existence, validity or termination, which the Parties do not resolve amicably within a period of twenty (20) days from the giving of a notice by one Party to the other Parties notifying the dispute, shall be resolved by three arbitrators in accordance with the Arbitration Rules of the International Chamber of Commerce. Each JV Partner shall appoint one arbitrator within thirty (30) days of the filing of the arbitration, and the two arbitrators so appointed shall select the presiding arbitrator within thirty (30) days after the latter of the two arbitrators have been appointed. If a JV Partner fails to appoint its appointed arbitrator or if the two appointed arbitrators cannot reach an agreement on the presiding arbitrator within the applicable time period, then the remainder of the three arbitrators not yet appointed shall be appointed in accordance with said Rules. The seat of arbitration shall be London, England.  The proceedings shall be in the English language.  The resulting arbitral award shall be final and binding, and judgment upon such award may be entered in any court having jurisdiction thereof.  A dispute shall be deemed to have arisen when either Party notifies the other Parties in writing to that effect.  Any monetary award issued by the arbitrator shall be payable in United States Dollars.  It is expressly agreed that the arbitrators shall have no authority to award special, indirect, consequential, exemplary or punitive damages.  The Parties waive any right to refer any question of law and any right of appeal on the law and/or merits to any court.
(B)      All discussions, negotiations and arbitration conducted between the Parties under this Clause (including a settlement resulting from negotiation or an arbitral award, documents exchanged or produced during an arbitration proceeding, and memorials, briefs or other documents prepared for the arbitration) are confidential and may not be disclosed by the Parties, their employees, officers, directors, counsel, consultants, and expert witnesses, except (under Clause 13) to the extent necessary to enforce this Clause or any arbitration award, to enforce other rights of a Party, or as required by law or stock exchange; provided, however, that breach of this confidentiality provision shall not void any settlement or award.
IN WITNESS WHEREOF the Parties have entered into this Agreement on the date set out on page 1 above.
SIGNED by
for and on behalf of
Kosmos Energy Senegal
 	)
)	/s/ Jason E. Doughty
…………………………………………..
JASON E. DOUGHTY	
SIGNED by
for and on behalf of
BP Indonesia Oil Terminal Investment Limited
 	)
)	/s/ Andrew Lane
…………………………………………..
ANDREW LANE	
SIGNED by
for and on behalf of
Normandy Ventures Limited	)
)	/s/ Jason E. Doughty
…………………………………………..
JASON E. DOUGHTY	
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SCHEDULE 1
1          Acceptance of Prior Terms
Subject to the Kosmos Warranties and applicable laws, JVCo hereby ratifies, confirms and accepts the terms of the Contract and the Senegal Area JOAs.
2          Firm Work Programme (Exploration and Appraisal) and Firm Work Programme (Development)
Notwithstanding articles 5.1.4, 5.6 and 6.7 of the Senegal Area JOAs, the Parties agree that JVCo shall  participate in the Firm Work Programme (Exploration and Appraisal) and Firm Work Programme (Development), unless otherwise mutually agreed.  The Parties agree that JVCo will support an amendment to the Work Program and Budget approved under the Senegal Area JOAs to accomplish the Firm Work Programme (Exploration and Appraisal) and Firm Work Programme (Development).
3          Obligations in Respect of Tortue Development and Senegal JOAs
3.1       The Parties support the Tortue development concept for phase 1 proposed and supported by Kosmos and an indicative work program aimed to reach a final investment decision (" FID ") by the end of 2017.  Notwithstanding the foregoing, in BP’s view the following key decisions for the first phase development of Tortue require study or screening for the potential full field development (" FFD ") solution: (i) location of breakwater and pre-treatment facility; (ii) scope of phase 1 pre-treatment facility; (iii) breakwater configuration capable of expansion; and (iv) LNG cooling solution capable of expansion.  These key decisions will be informed by the following key activities: (i) metocean survey/ report results; (ii) G&G site survey results at breakwater and Tortue sites; (iii) agreement with third party contractors for liquefaction; (iv) FFD concept screening to allow expansion of LNG facilities; (v) FFD concept process safety, environmental studies and operations philosophy; and (vi) FFD flow assurance and water breakthrough risk mitigation studies.  BP proposes (and Kosmos agrees) that these key decisions and their supporting studies and surveys are completed by JVCo by the end of first quarter 2017 so they are able to feed into a prompt FID decision. For the avoidance of doubt, each Party shall have complete discretion (to be exercised as it sees fit) in how it exercises its vote or decision under the SHA in respect of the FID decision.
3.2       The Parties shall cause JVCo to use reasonable endeavours to negotiate and agree with PETROSEN a revised joint operating agreement for each of the Saint-Louis Offshore Profond Block and the Cayar Offshore Profond Block to replace the Senegal Area JOAs on the basis of the 2012 model international joint operating agreement published by the Association of International Petroleum Negotiators, with a view to such revised joint operating agreement coming into force as soon as practicable.
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4         Option to Sell LNG
4.1      Upon Second Completion, BP offers to work with JVCo and the other parties to the Interest Documents in a possible Tortue development, to develop a LNG marketing strategy and to use its experience and relationships in the market to jointly sell the LNG produced from the Tortue development.  BP is an experienced LNG industry player and already undertakes this role as the operator of other LNG projects also governed by a production sharing contract.
4.2      Additionally, BP’s LNG trading business will offer to purchase some or all of the LNG produced from the Tortue development on a free on board “FoB” basis through a long term LNG purchase agreement.  BP’s LNG trading business believes the natural market for this LNG is in Europe and would plan to offer to purchase on the basis of delivery to the European market. BP’s LNG trading business has industry leading trading capability and track record, and will attempt to divert purchased LNG cargos to other more attractive markets outside of Europe where possible, the benefits of any upside value achieved (net of shipping and regasification costs) will be shared equally between buyer and seller.
4.3      The foregoing is subject to applicable law joint selling limitations.
4.4      The provisions of this paragraph 4 shall only become effective upon the Second Completion Date.
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SCHEDULE 2
INTERIM PERIOD OBLIGATIONS
During the Interim Period, Kosmos shall:
(A)      having notified BP in advance of the subject matter thereof, consult with BP in relation to any material decision (including any voting matter under the Interest Documents) in connection with the Interests (including decisions relating to the location and timing of any exploration wells), and take due consideration of BP’s representations in respect thereof;
(B)      consult with BP in relation to the negotiation of a term sheet, charter agreement, tolling agreement and other definitive agreements with any third party contractors for the liquefaction services, and take due consideration of BP’s representations in respect thereof.  Additionally Kosmos will take all steps within its control to afford BP the opportunity to attend and participate in such negotiations;
(C)      not incur, commit to incur or approve or amend any work programme, budget, expenditure or capital commitment relating to the Interests involving expenditure or agree to do any of the foregoing, in any case other than:
(i)        any expenditure permitted and approved under the Senegal Area JOAs and disclosed to BP at the date of this Agreement;
(ii)       any expenditure required to carry out the Firm Work Programme (Exploration and Appraisal);
(iii)      any expenditure required to carry out the Firm Work Programme (Development);
(iv)      any such expenditure in respect of which BP has given its prior approval (not to be unreasonably withheld or delayed);
(v)       any expenditure necessitated by any emergency (in which case Kosmos shall consult with BP to the extent practicable in the circumstances);
(D)      conduct operations regarding the Initial Interests in the ordinary and usual course, past practice and with the intention that the same be protected and maintained in accordance with Good Industry Practice and all applicable laws;
(E)      not (by act or omission) breach any of the provisions of the Contracts or Senegal Area JOAs or new agreements concluded in the Interim Period in accordance with this Schedule (and notify BP in a timely manner of any facts or circumstances of which it is aware or becomes aware which indicate that there has been a breach of any of the Contracts or Senegal Area JOAs by any other party or that such a breach by Kosmos has occurred);
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(F)       take all steps within its control (and Kosmos shall procure that its Affiliates take all steps within their control) to maintain and renew all governmental licenses, permits, authorizations, consents and permissions necessary to own and operate the Initial Interests;
(G)      not amend, terminate or replace any of the Contracts, Senegal Area JOAs or new agreements concluded in the Interim Period in accordance with this Schedule or waive or surrender any right or grant any consent thereunder, or agree to do any of the foregoing, without the written consent of BP (such consent not to be unreasonably withheld or delayed);
(H)      not, without BP’s written consent (not to be unreasonably withheld or delayed), create any Encumbrance in relation to, sell, lease or otherwise dispose of all or any part of, the Interests, or purport to or agree to do any of the same;
(I)        in respect of the Interests, not enter into or become a party to any new licenses, operating agreements, farm-in or farm-out agreements, unitization agreements, liquefaction agreements, charterparties, development agreement or any other agreement or undertaking or any of them (by whatever name called) or trade, relinquish, surrender, sell, assign, transfer or amend the Interests (or agree to do any of the foregoing in the future) without the prior written approval of BP (such approval not to be unreasonably withheld or delayed); and
(i)        keep BP informed in a timely manner of all material matters in relation to the Interests,
(ii)       to the maximum extent permitted by law and confidentiality obligations under agreements, provide BP with copies of all communications with the Government, Senegal Minister of Energy and Development of Renewable Energy Resources and PETROSEN in relation to the Interest Documents,
and Kosmos undertakes to notify BP in writing promptly if it or any of its Affiliates becomes aware of any circumstance arising after the date of the Agreement which is or is reasonably likely to result in a breach of any of the covenants in this Schedule.
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SCHEDULE 3
KOSMOS WARRANTIES
Part 1 – Kosmos Asset Warranties
1.         Incorporation and Capacity
(A)      Kosmos is duly incorporated with limited liability and validly existing under the laws of the Cayman Islands.
(B)      The documents which contain or establish Kosmos’s constitution incorporate provisions which authorise, and all necessary corporate action has been taken to authorise, Kosmos to execute and deliver this Agreement and perform the transaction contemplated by this Agreement, which Agreement will constitute legally binding obligations on Kosmos and not cause Kosmos to violate any applicable law, judgment, order, permit or any other agreement, consent or instrument binding on Kosmos.
2.         Performance
Subject to fulfilment of the Conditions, the signing and delivery of this Agreement and the performance of any of the transactions contemplated by this Agreement will not contravene or constitute a default under any provision contained in any agreement, instrument, law, judgment, order, licence, permit or consent by which Kosmos or any of its Affiliates or their respective assets is bound or affected or cause any limitation on Kosmos or the powers of its directors, whether imposed by or contained in any document which contains or establishes its constitution or in any law, order, judgment, agreement, instrument or otherwise to be exceeded and which would result in Kosmos being unable to perform its obligations under this Agreement.
4.5       Solvency
No order has been made, petition presented or meeting convened for the purpose of considering a resolution for the winding up or for the appointment of a liquidator or provisional liquidator of Kosmos.
4.6       Sole Ownership
(A)      Kosmos is a party to the Interest Documents and the sole legal and beneficial owner of the Initial Interests. Immediately after the Initial Asset Transfer Completion, JVCo shall be a party to the Interest Documents and the sole legal and beneficial owner of the Initial Interests free from Encumbrances.
(B)      Kosmos will be the sole legal and beneficial owner of the TC Interests upon TC Asset Transfer Completion free from Encumbrances.
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4.7       Right to Assign
Following fulfilment of the Conditions, Kosmos will have the right, subject to Approval, to transfer and assign full legal and beneficial ownership of the Initial Interests to JVCo.
4.8       No Encumbrance
Subject to the provisions of the Interest Documents, no Encumbrance is in existence and in force over the Initial Interests nor, subject as aforesaid, is there in effect any agreement or commitment to create the same; nor are there any other matters which restrict Kosmos’s ability freely to dispose of the Initial Interests.
4.9       Interests and Interest Documents
(A)      Kosmos has not committed any breach of the Interest Documents nor received notice (in its role as operator under the Contracts and Senegal Area JOAs) and not otherwise aware that any of the other parties to any of the above-mentioned documents has committed any breach.
(B)      The Initial Interests and all rights and interests of Kosmos thereunder or deriving therefrom are in full force and effect. Immediately after Initial Asset Transfer Completion, the Initial Interests and all rights and interests of JVCo thereunder or deriving therefrom are in full force and effect.
(BB)    Immediately after TC Asset Transfer Completion, the TC Interests and all rights and interests of JVCo thereunder or deriving therefrom are in full force and effect.
(C)      No notice has been given to Kosmos or, that Kosmos is aware of, to any party to the Interest Documents (other than Kosmos and JVCo) by the Government of any intention to terminate, amend or revoke the Contracts.
(D)      No area under the Contracts is in the course of being surrendered or relinquished in whole or in part, and there is no proposal to do so.
(E)       Kosmos has not given any notice of withdrawal from the Contracts.
(F)       Kosmos is not aware of any facts which would have a material adverse impact on the value of the Interests.
(G)      The Contracts are currently in the first renewal phase of the exploration period and no party to the Contracts has issued a notice under the Contracts to apply for an extension of any current Exploration Period (as defined in the Contracts) or for entry into a new phase of the Exploration Period.
(H)      All guarantees required pursuant to the terms of the Contracts have been provided by Kosmos, accepted by the Government and are in full force and effect.
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(I)        No vote to remove Kosmos in its capacity as operator under the Contracts or Senegal Area JOAs is pending or has been proposed, and Kosmos, in its capacity as operator under the Contracts or Senegal Area JOAs, has not intimated that it intends to resign as such.
4.10     Not Used
(A)      The Senegal Area is the accurate delineated area covering the Contracts and is not, in full or in part, subject to any competing or overlaying claim by a third party or group of parties.
4.11     No Litigation
(A)      Kosmos is not a party to any litigation or arbitration or administrative proceedings in respect of which a writ or summons or other formal pleading has been served or judgement issued, nor is there any claim (whether or not formulated within a formal pleading as aforesaid) or dispute in relation to, and which is likely materially to prejudice or detrimentally affect in any manner, the Interests, and Kosmos is not aware that any such litigation, arbitration, administrative proceedings, claim or dispute are threatened or pending either by or against Kosmos, and there are no facts known to Kosmos which are likely to give rise to any claim or dispute which is likely  so to prejudice or detrimentally affect in any manner the Interests, and none of the parties to the Interest Documents is a party to any litigation, arbitration or administrative proceedings or any claim or dispute or judgment in relation to, and which is likely to prejudice or detrimentally affect in any manner, the Interests.
(B)      There are no overlaps, competing claims or disputes in relation to the Senegal Area from any third party.
4.12     Insurance
(A)      The insurance policies maintained by Kosmos in respect of the Initial Interests have at all material times afforded to Kosmos adequate cover against such risks as companies carrying on the same type of business as Kosmos commonly cover, and the full terms of all such insurance policies are included in the Disclosure Documents.
(B)      All premiums due in respect of those insurance policies have been fully paid and there are no circumstances which may lead to liability under any such insurances being avoided by the insurers and none of the insurances is subject to any special or unusual terms or restrictions.
(C)      No claim is outstanding under any of the insurances and no circumstances exist which are likely to give rise to any such claim.
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4.13     Interest Documents
The Interest Documents are the only documents of which Kosmos is aware which govern or relate to the creation, existence and validity of the Interests and are the only agreements to which Kosmos is party relating to the Interests, and Kosmos has made available to BP accurate and complete copies of the Interest Documents, save that, where Kosmos has provided any translation of a document, Kosmos has done so as a courtesy to BP and Kosmos makes no warranty as to the accuracy of such translation.
4.14     Provision of Information
(A)      Kosmos has in its possession or has access to all Data and information relating to the Interests (including complete copies of all material geological, geophysical, well and field development data and any other information in the possession of Kosmos or any of its Affiliates relating to the evaluation of the proven, probable and possible reserves in the Senegal Area and on reservoir volume and performance) to which it is entitled under the terms of the Interest Documents and all such Data and information is included in the Disclosure Documents.
(B)      Each Answer is true and accurate in every material respect.
4.15     No Force Majeure
Kosmos is not aware of any force majeure event or other event which would excuse or has excused performance of any of the obligations of Kosmos which have arisen under any of the Interest Documents and this Agreement.
4.16     Tax
(A)      Kosmos has, since it acquired the Initial Interests, complied with all statutory requirements, regulations, orders, provisions, directions or conditions in relation to the Initial Interests concerning Tax including the making on time of accurate returns and payments and the proper maintenance and preservation of records and Kosmos has not been given any penalty, notice or warning regarding the same.
(B)      Kosmos is not involved in any dispute, and is not the subject of any enquiries, with any Tax authority or any other appropriate fiscal authority, whether of the Republic of Senegal or elsewhere, concerning any matter likely to affect the Interests in any way other than routine enquiries of a minor nature following the submission of computations and returns.
(C)      All documents under which Kosmos derives title to the Initial Interests and which attract transfer tax have been duly stamped, if required, and are in the possession of Kosmos or under its control.
(D)      All documents under which Kosmos derives title to the TC Interest on the TC Option Completion Date and which attract transfer tax have been duly stamped, if required, and are in the possession of Kosmos or under its control.
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4.17     Environmental
(A)      Kosmos has not been notified of the occurrence of any environmental incident concerning the Interests and operations related thereto.
(B)      Kosmos has not received any demands, notices, orders or directives under any environmental laws, whether or not with respect to any breach thereof, nor in relation to any environmental liabilities which require any remedial work, clean up or any other such work, repairs, construction or capital expenditures with respect to the Interests or the operations related thereto or use or ownership thereof which have not been fully complied with.
(C)      No complaint has been filed by any governmental department, body or agency or any non-governmental group or organization in respect of the Initial Interests concerning any environmental damage, injury, alleged damage or breach of any legislation, rules, regulations and orders relating to the environment.
4.18     Bribery and Anti-Corruption
(A)      Neither Kosmos nor any of its Affiliates nor their respective Associated Persons:
(i)        has been, is or will be engaged in any activity, practice or conduct related to the Interest Documents or to this Agreement that would constitute a violation of the Anti-Corruption Laws and Obligations either with respect to itself or with respect to BP;
(ii)       has paid, offered, promised or authorized the payment, directly or indirectly, of any monies or anything of value to any Government Official (as defined in the Senegal Area JOAs), for the purpose of improperly influencing any act or decision of such Government Official or improperly inducing such Government Official to use his or her influence with a government or instrumentality thereof to obtain or retain business or direct business to any person in connection with the Interest Documents or this Agreement; or
(iii)      Kosmos is not aware that it is the subject of any investigation, inquiry or enforcement proceedings by any government, administrative or regulatory body regarding any offence or alleged offence under the Anti-Corruption Laws and Obligations related to the Interest Documents or this Agreement, and no such investigation, inquiry or proceedings has been threatened, and there are no circumstances likely to give rise to any such investigation, inquiry or proceedings.  Kosmos has made BP aware of an inquiry undertaken by the Senegalese  National Anti-Corruption and Fraud Office (OFNAC) which, in Kosmos’s understanding and belief, does not amount to an investigation or inquiry in which Kosmos is the subject.
(B)      Kosmos is not aware after due inquiry, that any person:
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(i)        has engaged in any activity, practice or conduct related to the Interest Documents or to this Agreement that would violate the terms of the Anti-Corruption Laws and Obligations, even if that person is outside the jurisdiction or scope of those laws;
(ii)       has paid, offered, promised or authorized the payment, directly or indirectly, of any monies or anything of value to any Government Official, for the purpose of improperly influencing any act or decision of such Government Official or improperly inducing such Government Official to use his or her influence with a government or instrumentality thereof to obtain or retain business or direct business to any person in connection with the Interest Documents or this Agreement.
(C)      No principal, shareholder (or other equity holder), director, officer or employee of Kosmos is or will become during the term of this Agreement a Government Official in the Republic of Senegal.
4.19     No Fees
Kosmos has not incurred any obligation or entered into any agreement for any investment banking, brokerage, finder’s fee, commission, agency or similar payment in respect of any transaction contemplated by this Agreement for which BP or JVCo may incur any liability.
4.20     Operator
(A)      All material permits and licences required to carry out Joint Operations (as defined under the Contracts) are held by Kosmos as operator and valid and subsisting and there has been no material violation thereof.
(B)      Kosmos as operator has complied with the Contracts and all applicable laws (including environmental laws) in carrying out the Joint Operations (as defined under the Contracts).
(C)      No sole risk activities (as defined under the Senegal Area JOAs) have been approved under the Interest Documents and no notices have been received for sole risk activities, or so far as the Kosmos as operator is aware, are likely to be issued.
4.21     Timis Corporation
No cash payment has been made by, or on behalf of, Kosmos or JVCo to Timis Corporation and, following exercise of the TC Option, JVCo will have no liability to Timis Corporation save in respect of the obligation to carry Timis Corporation in respect of Timis Corporation’s remaining interest share of the first one hundred and twenty million Dollars (US$120,000,000) of gross costs (including all general and administration costs and expenses (G&A)) to drill one well exploration well or appraisal well (including testing) in the Senegal Area for which JVCo will be liable.
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Part 2 – Kosmos Share Warranties
4.21     Kosmos further warrants to BP at the date of this Agreement that:
(A)       JVCo is validly incorporated, in existence and duly registered;
(B)       Kosmos is the sole legal and beneficial owner of the Sale Shares;
(C)       there is no Encumbrance on, over or affecting the Sale Shares;
(D)       there is no agreement or commitment outstanding which calls for the allotment, issue or transfer of, or accords to any person the right to call for the allotment, issue or transfer of, any shares (including Ordinary Shares) or debentures in or securities of JVCo;
(E)       the copy of the articles of association of JVCo provided to BP on or before the date of this Agreement is complete and accurate in all respects and fully sets out the rights and restrictions attaching to the share capital of JVCo;
(F)       No order has been made, petition presented or meeting convened for the purpose of considering a resolution for the winding up or for the appointment of a liquidator or provisional liquidator of JVCo.
(F)       the statutory books (including all registers and minute books) of JVCo have been properly kept and contain an accurate and complete record of the matters which should be dealt with in those books and no notice or allegation that any of them is incorrect or should be rectified has been received;
(G)      all documents which should have been delivered by JVCo to the Registrar of Companies in England and Wales have been properly so delivered; and
(H)      JVCo has not conducted any business or entered into any contracts or commitments, and has no assets, obligations or liabilities, save for those arising out of or in connection with its incorporation, this Agreement, the Initial Asset Transfer Agreement or the TC Asset Transfer Agreement.
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SCHEDULE 4
BP Warranties
1          Incorporation and Capacity
1.1       BP is duly incorporated with limited liability and validly existing under the laws of England and Wales.
1.2       The documents which contain or establish BP’s constitution incorporate provisions which authorize, and all necessary corporate action has been taken to authorize, BP to execute and deliver this Agreement and perform the transaction contemplated by this Agreement, which agreement will constitute legally binding obligations on BP and not cause BP to violate any applicable law, judgment, order, permit or any other agreement, consent or instrument binding on BP.
2          Performance
Subject to fulfilment of the Conditions, the signing and delivery of this Agreement and the performance of any of the transactions contemplated by this Agreement will not contravene or constitute a default under any provision contained in any agreement, instrument, law, judgment, order, licence, permit or consent by which BP or any of its Affiliates or their respective assets is bound or affected or cause any limitation on BP or the powers of its directors, whether imposed by or contained in any document which contains or establishes its constitution or in any law, order, judgment, agreement, instrument or otherwise to be exceeded and which would result in BP being unable to perform its obligations under this Agreement.
3          Solvency
No order has been made, petition presented or meeting convened for the purpose of considering a resolution for the winding up or for the appointment of a liquidator or provisional liquidator of BP.
4          No Litigation
No litigation, arbitration, administrative proceeding, dispute or judgment against BP or to which BP is a party which might by itself or together with any such other proceedings have a material adverse effect on its business, assets or condition and which would materially and adversely affect its ability to observe or perform its obligations under this Agreement and the transactions contemplated hereby, is subsisting or threatened or pending against BP or any of its assets.
5         Anti Bribery and Corruption
5.1       Neither BP nor any of its Affiliates nor their respective Associated Persons:
(A)      has been, is or will be engaged in any activity, practice or conduct related to the Interest Documents or to this Agreement that would constitute a violation of the
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Anti-Corruption Laws and Obligations either with respect to itself or with respect to Kosmos or JVCo;
(B)      has paid, offered, promised or authorized the payment, directly or indirectly, of any monies or anything of value to any Government Official (as defined in the Senegal Area JOAs), for the purpose of improperly influencing any act or decision of such Government Official or improperly inducing such Government Official to use his or her influence with a government or instrumentality thereof to obtain or retain business or direct business to any person in connection with the Interest Documents or this Agreement; or
(C)      BP is not aware that it is the subject of any investigation, inquiry or enforcement proceedings by any government, administrative or regulatory body regarding any offence or alleged offence under the Anti-Corruption Laws and Obligations related to the Interest Documents or this Agreement, and no such investigation, inquiry or proceedings has been threatened, and there are no circumstances likely to give rise to any such investigation, inquiry or proceedings.  Kosmos has made BP aware of an inquiry undertaken by the Senegalese National Anti-Corruption and Fraud Office (OFNAC) which, in Kosmos’s understanding and belief, does not amount to an investigation or inquiry in which Kosmos is the subject.
5.2       No principal, shareholder (or other equity holder), director, officer or employee of BP is or will become during the term of this Agreement a Government Official in the Republic of Senegal.
6          No Fees
BP has not incurred any obligation or entered into any Agreement for any investment banking, brokerage, finder’s fee, commission, agency or similar payment in respect of any transaction contemplated by this Agreement for which Kosmos may incur any liability.
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EXHIBIT A
Part 1
Firm Work Programme (Exploration and Appraisal)
1         Exploration Wells
1.1      One  Exploration Well to target outboard basin floor fan fairways in the Senegal Area.
(A)      The Exploration Well to be drilled to the top of 106_Albian
2         DST
A drill stem test (“DST”) within the Tortue Discovery Area, provided the DST may be satisfied in Mauritania
3         Wells and Schedule
3.1      The objective, design and duration of each Exploration Well and the DST to be determined pursuant to the Senegal Area JOAs, BP, Kosmos and JVCo to consult, including with the Steering Committee, if necessary, on all recommendations to the Operating Committee
3.2      It is anticipated that the drilling and testing program for the Exploration Wells and the DST will be continuous and conducted in an agreed order.
3.3      The program will commence in 2017, unless mutually agreed otherwise by BP and Kosmos.  If for technical reasons beyond the Parties control the entire program cannot be completed in 2017, then the program will be completed as soon thereafter as practicable.
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EXHIBIT A
Part 2
Firm Work Programme (Development)
1          Development Studies
1.1       JVCo in cooperation with the Mauritania Operator, without duplication of efforts or costs, shall conduct the following activities:
(A)      Studies to establish (a) location of breakwater and pre-treatment facility; (b) scope of phase 1 pre-treatment facility; (c) breakwater configuration capable of expansion; and (d) LNG cooling solution capable of expansion
(B)      metocean survey/ report results;
(C)      G&G site survey results at breakwater and Tortue sites;
(D)      Negotiate and finalize  all agreements required with third party contractors on FLNG vessel(s);
(E)      concept screening to allow expansion of LNG facilities;
(F)      concept process safety, environmental studies and operations philosophy;
(G)      flow assurance and water breakthrough risk mitigation studies; and
(H)      Any other activities or studies to enable an investment decision on Tortue by the end of 2017.
2          Schedule
JVCo in cooperation with the Mauritania Operator, without duplication of efforts or costs, will aim to complete this program by the end of first quarter 2017 to enable an investment decision on Tortue by the end of 2017.
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EXHIBIT B
ABC Obligations
1          Neither Party nor any of its Affiliates nor their respective Associated Persons:
(A)      has been, is or will be engaged in any activity, practice or conduct related to the Interest Documents or to this Agreement that would constitute a violation of the Anti-Corruption Laws and Obligations either with respect to itself or with respect to the other Parties;
(B)      has paid, offered, promised or authorized, or will pay, offer, promise or authorize, the payment, directly or indirectly, of any monies or anything of value to any Government Official (as defined in the Senegal Area JOAs), for the purpose of improperly influencing any act or decision of such  Government Official or improperly inducing such Government Official to use his or her influence with a government or instrumentality thereof to obtain or retain business or direct business to any person in connection with the Interest Documents or this Agreement; or
(C)      has been or is  the subject of any investigation, inquiry or enforcement proceedings by any government, administrative or regulatory body regarding any offence or alleged offence under the Anti-Corruption Laws and Obligations related to the Interest Documents or this Agreement, and no such investigation, inquiry or proceedings has been or will be threatened, and to the best of such Party’s knowledge, information and belief (after making reasonable enquiries) there are no circumstances likely to give rise to any such investigation, inquiry or proceedings.  Both Parties are aware of an inquiry undertaken by the Senegalese  National Anti-Corruption and Fraud Office (OFNAC) which, in both Parties’ understanding and belief, does not amount to an investigation or inquiry in which a Party is the subject.
2          Each Party shall as soon as possible notify the other Parties of any suspected violations, including any investigation or proceeding initiated by a governmental authority relating to an alleged violation of applicable Anti-Corruption Laws and Obligations by such Party, or its Affiliates, or any Associated Persons, concerning operations and activities under the Senegal Area JOAs and the Contracts. Such Party shall use reasonable efforts to keep the other Parties informed as to the progress and disposition of such investigation or proceeding, except that such Party shall not be obligated to disclose to the other Parties any information that would be considered legally privileged.
3          Each Party shall defend, indemnify and hold harmless the other Parties for any claims, damages, losses, penalties, costs (including reasonable legal costs and attorneys’ fees), and liabilities arising from, or related to:
(A)      any breach by such Party of the warranties and undertakings set out in paragraph 1;
56

 

(B)      such Party’s admission of allegations made by a governmental authority concerning operations and/or activities under this Agreement or the Interest Documents [(or any agreements relating thereto)] that such Party or its Associated Persons have violated Anti-Corruption Laws and Obligations applicable to such Party; or
(C)      the final adjudication concerning operations and/or activities under this Agreement or the Interest Documents (or any agreements relating hereto) that such Party or its Affiliates or their directors, officers, employees and personnel have violated Anti-Bribery Laws and Obligations applicable to such Party, such indemnity obligations shall survive termination or expiration of this Agreement. 
4          Each Party undertakes to each other Party that, to the extent it has not already done so, it shall:
(A)      Devise and maintain adequate internal controls concerning such Party’s undertakings under paragraph 1;
(B)      design, implement and maintain comprehensive, “best practice” written policies, resources and procedures to ensure compliance with applicable Anti-Corruption Laws and Obligations and which will address, without limitation, sponsorship and donations, gifts and entertainment, hosting of Public Officials, anti-money laundering, whistle-blowing and responding to demands for improper payments or allegations of bribery, in each case in connection with the activities and operations conducted under or in relation to the Interest Documents and this Agreement (“ Anti-Corruption Policies ”); and
(C)      Retain books and records evidencing compliance with these paragraphs 1 -7 for a period of at least six (6) Calendar Years.
5          Each Party shall promptly respond in reasonable detail to any reasonable request from any other Party concerning a notice sent by such Party under paragraph 2 and shall furnish applicable documentary support for such Party’s response, including showing such Party’s compliance with the undertakings set out in paragraph 1.
6          Each Party warrants that in connection with the Joint Operations it shall obligate any contractor, including but not limited to any sub-agent, representative or other service provider it may engage, that:
(A)      it will conduct appropriate due diligence prior to appointing or engaging such contractor to reasonably assure itself that they are duly qualified to perform the tasks for which they will be engaged and that they are of good reputation; and
(B)      it will impose and secure from the contractor when appropriate given the risk, in writing compliance with the Anti-Corruption Laws and Obligations or a similar obligation.
57

 

7          Each Party undertakes to the other Party that, from time to time and at the reasonable request of each other Party, it shall:
(A)      provide written certification (by providing a certificate of compliance in the form agreed between the Parties and attached at Appendix A and signed by its authorized representative)) that it has complied with its undertakings under paragraph 1; and
(B)      in support of such compliance, provide the other Party with reasonable access to its personnel and to the facilities, warehouses and offices directly or indirectly serving the operation of the Senegal Area JOAs and the Contracts and the books, records and other information relating to the Senegal Area JOAs and the Contracts, together with the right, where reasonably requested, to make and retain copies of such books, records and information.
58

 

Appendix A to Exhibit B
FORM OF CERTIFICATE OF ANTI-BRIBERY COMPLIANCE
[Certifying Party Letterhead]
To:      [.......................], [.......................], [.......................], and [.......................]
Re:      Periodic Certification
Dear Sir,
Pursuant to paragraph 7 of Exhibit M of the Sale and Purchase Agreement dated [.......................] between Kosmos Energy Senegal, [JVco] Limited and BP ____________ (“Agreement”), the undersigned hereby confirms that throughout the twelve (12) months ending 31st December [.......................], [Certifying Party], its Affiliates and their respective directors, officers, employees and personnel, have complied with their warranties and covenants set out in paragraph 1 of Exhibit B of the Agreement.
The certificate is issued by the undersigned duly authorized representative for and on behalf of [Certifying Party] to the best of his or her knowledge after having made due enquiry as to the matters set out above, but without personal liability on the part of such authorized representative.
Yours faithfully,
Name and Title:...................................................................................................
[an executive director or officer of Certifying Party]
59

 

EXHIBIT C
ELIGIBLE DISCOVERY
Part 1
Tortue Discovery Area

60

 

EXHIBIT C
ELIGIBLE DISCOVERY
Part 2
Teranga Discovery Area

61

 

EXHIBIT D
SENEGAL AREA

62

 

EXHIBIT E
Not Used
63

 

EXHIBIT F
FORM OF ASSET TRANSFER AGREEMENT
[To be provided]
64

 

EXHIBIT G
Questions and Answers
[See Attached]
65

 

EXHIBIT I
Guarantees
Part 1 – Guarantee of BP payment obligations under this Agreement
66

 

DATED                                         20[  ]
BP ENTITY
in favour of
KOSMOS ENERGY SENEGAL

GUARANTEE
relating to payment obligations of [BP entity] under a sale and purchase agreement dated [ ] December 2016 relating to the sale and purchase of shares in [JVCo] Limited

67

 

CONTENTS
1.      Definitions and Interpretation
2.      Guarantee
3.      Limitation on Exercise of Guarantor’s Rights
4.      Valid Demand under the Guarantee
5.      Costs and Expenses
6.      No Implied Waivers
7.      Amendment to the Agreement
8.      Release and Discharge
9.      Assignment and Transfer
10.    Communications
11.    Third Party Rights
12.    Governing Law and Jurisdiction
68

 

THIS GUARANTEE is made as a Deed the                  day of 20[ ]
By:
(1)      [BP Exploration Operating Company], a company incorporated in England whose registered office is at [Chertsey Road, Sunbury on Thames, Middlesex TW16 7BP] (the " Guarantor ")
in favour of:
(2)      KOSMOS ENERGY SENEGAL a company incorporated in the Cayman Islands  (the “ Beneficiary ”)
WHEREAS:
(A)     The Beneficiary and [INSERT LEGAL NAME OF BP ENTITY WHOSE OBLIGATIONS ARE BEING GUARANTEED] (" BP ”), a wholly-owned [direct/indirect] subsidiary of the Guarantor have entered into a sale and purchase agreement dated [ ] December 2016 relating to the sale and purchase of shares in [JVCo] Limited (the " Agreement "); and
(B)     The Guarantor has agreed to guarantee for the benefit of the Beneficiary the payment obligations of BP under the Agreement under the terms of conditions of this Guarantee.
(C)     The Guarantor and the Beneficiary intend this document to take effect as a deed (even though the Beneficiary may only execute it under hand).
NOW THIS DEED PROVIDES as follows.
1.        DEFINITIONS AND INTERPRETATION
1.1      Definitions
In this Guarantee, unless the context otherwise requires:
[“Maximum Aggregate Liability” means the Consideration payable under the Agreement and any enforcement costs arising pursuant to this Guarantee.]
“Valid Demand” means a demand issued by the Beneficiary in accordance with Clause 4.
1.2      Interpretation of certain references
(a)      A reference to a “Clause” is a reference to a clause in this Guarantee.
(b)      This “Guarantee” includes this Guarantee as amended, supplemented, novated, restated or replaced by any document from time to time and any document which amends, supplements, novates, restates or replaces this Guarantee.
(c)      A “law” includes common or customary law and any constitution, decree, judgment, legislation, order, ordinance, regulation, statute, treaty or other legislative measure, in each case of any jurisdiction whatever.
69

 

(d)      Any “obligation” of any Person under this Guarantee or any other document referenced herein is a reference to an obligation expressed to be assumed by that
Person or imposed on that Person under this Guarantee or that other document, as the case may be.
(e)      A “Person” includes any individual, company, corporation, firm, partnership, joint venture, association, organisation, trust, state or agency of a state.
2.       GUARANTEE
2.1     Guarantee
As consideration for the Beneficiary’s entry into the Agreement and subject to Clause 2.2, the Guarantor hereby irrevocably and unconditionally guarantees for the benefit of the Beneficiary, that if BP defaults in the payment of any sum due and payable by BP to the Beneficiary under the Agreement, calculated in accordance with the terms of the Agreement, allowing for set-offs or other defences which could have been asserted under the Agreement by BP, the Guarantor shall, within 30 days of receipt of a Valid Demand by the Beneficiary, pay to the Beneficiary such sum (the “ Guaranteed Obligations ”).
2.2     Maximum Aggregate Liability
[The Guarantor’s liability to pay the Beneficiary under this Guarantee in aggregate shall not exceed the Maximum Aggregate Liability.]
2.3     Guarantor as Principal Debtor
As between the Guarantor and the Beneficiary but without affecting BP’s obligations, the Guarantor shall be liable under this Guarantee as if it were the sole principal debtor and not merely a surety. Accordingly, the liability of the Guarantor under this Guarantee shall not be released, affected or discharged by any act, matter or omission which (but for this clause) would have released, affected or discharged the liability of the Guarantor including:
(a)      subject to Clause 7, any change in the time, manner or place of payment of, or in any other term of, all or any of the Guaranteed Obligations, or any other amendment or waiver of, or any consent to departure from, the terms of such Guaranteed Obligations including but not limited to the grant of time, concession or other indulgence to BP by the Beneficiary or concurring in, accepting or varying any compromise, arrangement or settlement or omitting to claim or enforce payment from a principal debtor or any other Person; or
(b)      any present or future guarantee, indemnity, mortgage, charge or other security or right or remedy held by or available to the Beneficiary being or becoming wholly or in part void, voidable or unenforceable on any ground whatsoever or by the Beneficiary from time to time dealing with, varying, realising, releasing or failing to perfect or enforce any of the same; or
70

 

(c)      any invalidity, unenforceability, illegality or voidability of the Agreement;  or
(d)      any change, restructuring or termination of the corporate structure or existence of BP or the bankruptcy, insolvency, dissolution, reorganisation, moratorium, liquidation or similar proceeding involving BP.
2.4      Guarantor’s Obligations Additional
This Guarantee shall be in addition to and not in substitution for any other rights, remedy, security or guarantees which the Beneficiary may now or hereafter hold from or on account of BP in respect of BP's obligations under the Agreement and may be enforced without first having recourse to such other rights, remedy, security or guarantees.
2.5      Guarantor’s Obligations Continuing
The Guarantor’s obligations under this Guarantee are and remain in full force and effect by way of continuing security:
(a)      until the earlier of the following:
(i)      all sums payable by BP to the Beneficiary under the Agreement have been paid in full; and
(ii)     [the Guarantor has paid under this Guarantee an aggregate sum equal to the Maximum Aggregate Liability]; and
(b)      notwithstanding absorption, amalgamation or any other changes in the Guarantor’s constitution.
2.6      Avoidance of Payments
If all or part of any payment received or recovered by the Beneficiary in respect of the Guaranteed Obligations is, on the subsequent bankruptcy, insolvency, corporate reorganisation or other similar event of BP, avoided or set aside under any laws relating to bankruptcy, insolvency, corporate reorganisation or other such similar events, and the amount of such payment is required to be refunded to BP or other persons entitled through BP, such payment shall not be considered as discharging or diminishing the liability of the Guarantor and this Guarantee shall continue to apply as if such amount had at all times remained owing by BP.
3.       LIMITATION ON EXERCISE OF GUARANTOR’S RIGHTS
Notwithstanding any payment or payments made by the Guarantor hereunder, so long as any Guaranteed Obligation remains outstanding:
(a)      the Guarantor hereby irrevocably waives any right of subrogation to the rights of the Beneficiary against BP and any right to be reimbursed or indemnified by BP or by any other guarantor of all or any part of the Guaranteed Obligations; and
(b)      if, notwithstanding the foregoing, any amount is received or recovered by the Guarantor as a result of exercising such rights, such amount shall be held by
71

 

the Guarantor in trust for the Beneficiary and shall, forthwith upon receipt by the Guarantor, be paid to the Beneficiary, to be applied against the Guaranteed Obligations in such order as the Beneficiary may determine.
4.       DEMAND UNDER THE GUARANTEE
Any demand made of the Guarantor under this Guarantee shall:
(A)      be made by notice in writing (which notice may not be sent before any grace periods and periods of remediation applicable to the relevant default by BP provided in the Agreement shall have elapsed) stating the reasons for making such demand, identifying the payment obligations under the Agreement which BP has defaulted, and setting out a calculation of the amount owing by BP and under demand; and
(B)      be delivered or sent by post or facsimile to the Guarantor at its address as provided under Clause 10.
5.       COSTS AND EXPENSES
The Guarantor shall pay the Beneficiary within 30 days of written notice all costs and expenses reasonably incurred by the Beneficiary in connection with the enforcement or preservation of its rights hereunder[, provided that in no event shall the Guarantor be liable  to pay any sum where imposition of such liability would result in the Guarantor’s aggregate liability under this Guarantee exceeding the Maximum Aggregate Liability].
6.       NO IMPLIED WAIVERS
Except as to applicable statutes of limitation, no failure on the part of the Beneficiary to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any right hereunder preclude any other or further exercise thereof or the exercise of any other right.
7.       RELEASE AND DISCHARGE
Subject to Clause 2.5, the Beneficiary undertakes, upon the Guarantor’s request, to:
(i)      sign and execute such deeds or instruments as the Guarantor may reasonably require in order to give effect to a discharge of the Guarantor’s obligations under this Guarantee; and
(ii)     return the original of this Guarantee to the Guarantor following such discharge.
8.       ASSIGNMENT AND TRANSFER
(a)      Burden and Benefit
72

 

This Guarantee shall be binding upon the Guarantor, its successors and assigns and shall inure to the benefit of the Beneficiary, its successor and assigns.  Any reference in this Guarantee to the Guarantor and the Beneficiary shall be construed to refer to its relevant successors and assigns accordingly.
(b)      Transfer by Guarantor
The Guarantor shall not (without the prior written consent of the Beneficiary, such consent not to be unreasonably withheld or delayed) assign, novate or transfer to any entity its rights or obligations under this Guarantee.
(c)      Transfer by Beneficiary
The Beneficiary shall not (without the prior written consent of the Guarantor, such consent not to be unreasonably withheld or delayed) assign, novate or transfer to any entity its rights or obligations under this Guarantee, except the Beneficiary shall, by giving prior written notice to the Guarantor, assign, novate or transfer its rights or obligations under this Guarantee to a Person to whom all its rights with respect to the Guaranteed Obligations have also been transferred in accordance with the Agreement.
9.        COMMUNICATIONS
9.1      Addresses
(a)      Guarantor
Any demand or other communication made of the Guarantor under this Guarantee shall be delivered or sent by post or facsimile to the Guarantor at its office located at XXXXX, or to such other address and/or addressed to such other officers as may be provided in writing by the Guarantor to the Beneficiary for such purpose and shall be deemed to have been made when received by the Guarantor.
(b)      Beneficiary
Any communication made of the Beneficiary under this Guarantee shall be delivered or sent by post or facsimile to the Beneficiary at its office located at [ Beneficiary to insert details ], Fax Number [ Beneficiary to insert details ], Attention [ Beneficiary to insert details ], or to such other address and/or addressed to such other officers as may be provided in writing by the Beneficiary to the Guarantor for such purpose and shall be deemed to have been made when received by the Beneficiary.
10.     THIRD PARTY RIGHTS
Except as expressly provided for under this Guarantee, a Person who is not the Beneficiary has no right under the Contracts (Rights of third Parties) Act 1999 to enforce or enjoy the benefit of any term of this Guarantee.
73

 

11.     GOVERNING LAW AND JURISDICTION
This Guarantee shall in all respects be governed by and construed in accordance with the laws of England and each of the Guarantor and the Beneficiary, hereby irrevocably agree that the courts of England are to have exclusive jurisdiction to settle any disputes which may arise out of or in connection with this Guarantee, and that any legal action or proceedings arising out of or in connection with this Guarantee may be brought in those courts and each of the Guarantor and the Beneficiary irrevocably submit to the exclusive jurisdiction of each such court.
IN WITNESS WHEREOF, this Guarantee has been executed and delivered as a Deed as of the date indicated in the beginning
EXECUTED AS A DEED by
 	 	
……………………………… 	 	 	
 	 	 	
[Name, position]	 	 	
 	 	 	
as attorney  for and on behalf of	 	 	
 	 	 	
BP XXX XXXX XXX XXX 	 	……………………………… 	
 	 	 	
under a power of attorney dated [day, month, year]	 	Signature of Attorney	
 	 	 	
in the presence of	 	 	
 	 	 	
……………………………… 	 	 	
 	 	 	
Signature of Witness	 	 	
 	 	 	
Name of Witness:	 	 	
 	 	 	
Address of Witness:	 	 	

SIGNED by	 	 	
 	 	 	
………………………………	 	 	
 	 	 	
[Name, position]	 	 	
 	 	 	
for and on behalf of	 	 	
 	 	 	
[BENEFICIARY]	 	 	
 
74

 

EXHIBIT I
Guarantees
Part 2 – Back to back guarantee of Kosmos guarantee
[Note – to be added once Part 1 guarantee is settled with amendments reflecting fact that guarantee is limited to 49.99% of payments made by Kosmos under the Kosmos guarantee given to support JVCo’s obligations ]
75

Exhibit 10.41
ISLAMIC
REPUBLIC
OF
MAURITANIA
HONOR – BROTHERHOOD –
JUSTICE
EXPLORATION AND PRODUCTION CONTRACT
BETWEEN
THE ISLAMIC REPUBLIC OF MAURITANIA
AND
KOSMOS ENERGY MAURITANIA
Bloc C6

 

 

INDEX
ARTICLE 1 :   DEFINITIONS	5 	
 	 	 	
ARTICLE 2 :   SCOPE OF APPLICATION OF THE CONTRACT	8 	
 	 	 	
ARTICLE 3 :   EXPLORATION AUTHORIZATION	9 	
 	 	 	
ARTICLE 4 :   EXPLORATION WORKS OBLIGATION	11 	
 	 	 	
ARTICLE 5 :   ESTABLISHMENT AND APPROVAL OF ANNUAL WORK PROGRAMS	13 	
 	 	 	
ARTICLE 6 :   OBLIGATIONS OF THE CONTRACTOR IN THE CONDUCT OF PETROLEUM OPERATIONS	14 	
 	 	 	
ARTICLE 7 :   RIGHTS OF THE CONTRACTOR IN THE CONDUCT OF PETROLEUM OPERATIONS	17 	
 	 	 	
ARTICLE 8 :   MONITORING OF PETROLEUM OPERATIONS AND ACTIVITY REPORTS – CONFIDENTIALITY	18 	
 	 	 	
ARTICLE 9 :   APPRAISAL OF A DISCOVERY AND GRANTING OF AN EXPLOITATION AUTHORIZATION	23 	
 	 	 	
ARTICLE 10 :  RECOVERY OF PETROLEUM COSTS AND PRODUCTION SHARING	28 	
 	 	 	
ARTICLE 11 :  TAX REGIME	30 	
 	 	 	
ARTICLE 12 :  PERSONNEL	32 	
 	 	 	
ARTICLE 13 :  BONUS	33 	
 	 	 	
ARTICLE 14 :  PRICE AND MEASUREMENT OF HYDROCARBONS	34 	
 	 	 	
ARTICLE 15 :  NATURAL GAS	36 	
 	 	 	
ARTICLE 16 :  TRANSPORT OF HYDROCARBONS BY PIPELINES	39 	
 	 	 	
ARTICLE 17 :  OBLIGATION FOR SUPPLYING THE DOMESTIC MARKET	40 	
 	 	 	
ARTICLE 18 :  IMPORTATION AND EXPORTATION	40 	
 	 	 	
ARTICLE 19 :  FOREIGN EXCHANGE	41 	
 	 	 	
ARTICLE 20 :  BOOK-KEEPING, MONETARY UNIT, ACCOUNTING	41 	
 	 	 	
2

 

ARTICLE 21 :  PARTICIPATION OF THE STATE	42 	
 	 	 	
ARTICLE 22 :  ASSIGNMENT	45 	
 	 	 	
ARTICLE 23 :  OWNERSHIP, USAGE AND ABANDONMENT OF PROPERTY	47 	
 	 	 	
ARTICLE 24 :  LIABILITY AND INSURANCE	49 	
 	 	 	
ARTICLE 25 :  TERMINATION OF THE CONTRACT	50 	
 	 	 	
ARTICLE 26 :  APPLICABLE LAW AND STABILIZATION OF TERMS	51 	
 	 	 	
ARTICLE 27 :  FORCE MAJEURE	51 	
 	 	 	
ARTICLE 28 :  ARBITRATION AND EXPERTISE	52 	
 	 	 	
ARTICLE 29 :  TERMS FOR APPLICATION OF THE CONTRACT	53 	
 	 	 	
ARTICLE 30 :  ENTRY INTO FORCE	55 	
 	 	 	
APPENDIX 1 :  EXPLORATION PERIMETER	57 	
 	 	 	
APPENDIX 2 :  ACCOUNTING PROCEDURE	59 	
 	 	 	
APPENDIX 3 :  MODEL BANK GUARANTEE	81 	
 
3

 

BETWEEN
The Islamic Republic of Mauritania (hereafter referred to as « the State »), represented for purposes of these presents by the Minister in Charge of Crude Hydrocarbons
ON THE ONE HAND,
AND
Kosmos Energy Mauritania, a company under the Cayman Islands laws, having its registered headquarters at 4th Floor Century Yard, Cricket Square, PO Box 32322, George Town, Grand Cayman KY1, 1209 (hereafter referred to as « the Contractor »), represented herein by Andrew J. INGLIS, having all powers and being endowed with full authority for these purposes.
ON THE OTHER HAND,
The State and the Contractor being hereafter collectively referred to as « Parties » or individually « Party ».
WHEREAS:
The State, owner of the deposits and natural accumulations of hydrocarbons contained in the soil and the subsoil of the national territory, wishes to promote the discovery and the production of hydrocarbons in order to promote economic expansion within the framework instituted by Law No. 2010-033 of 20 July 2010 containing the Crude Hydrocarbons Code as thereafter modified;
The Contractor wishes to explore and to exploit, within the framework of this exploration-production contract and pursuant to the Crude Hydrocarbons Code, the hydrocarbons which may be contained in the perimeter described in Appendix 1 of this Contract, and has shown it possesses the technical and financial means necessary for this purpose.
IT HAS BEEN AGREED AS FOLLOWS:
4

 

ARTICLE 1 : DEFINITIONS
The terms utilized in this text have the following meaning:
1.1       « Calendar Year » means a period of twelve (12) consecutive months commencing on the first (1st) of January and terminating on the thirty-first (31st) of the following December.
1.2       « Contract Year » means a period of twelve (12) consecutive months beginning on the Effective Date or the anniversary date of said Effective Date.
1.3       « Appendices » (also called Annexes) means the appendices to this Contract consisting of:
 	§	 	The Exploration Perimeter constituting Appendix 1	

 	§	 	The Accounting Procedure constituting Appendix 2	

 	§	 	The model bank guarantee constituting Appendix 3	
1.4       « Exploration Authorization » means the authorization referred to in Article 3 of this Contract by which the State authorizes the Contractor to carry out, on an exclusive basis, all works of prospection and exploration of Hydrocarbons within the Exploration Perimeter.
1.5       « Exploitation Authorization » means the authorization granted to the Contractor to carry out, on an exclusive basis, all works of development and of exploitation of the deposits of Hydrocarbons within the Exploitation Perimeter.
1.6       « Barrel» means « U.S. barrel », or 42 American gallons (159 liters) measured at the temperature of 60°F (15.6 °C) and at atmospheric pressure.
1.7       « BTU » means the British unit of energy « British Thermal Unit » in such manner that a million BTU (MMBTU) is equal to approximately 1055 joules.
1.8       « Annual Budget » means the detailed estimate of the cost of Petroleum Operations defined in an Annual Work Program.
1.9       « Crude Hydrocarbons Code » means Law No. 2010-033 of 20 July 2010 containing the Crude Hydrocarbons Code, its amendments and its application texts.
1.10     « Environmental Code » means Law No. 2000-045 of 26 July 2000 containing the Environmental Code, its amendments and its application texts.
1.11     « Contractor » means collectively or individually the company(ies) signing this Contract as well as any entity or company to which an interest would be assigned in application of Articles 21 and 22 of this Contract.
1.12     « Contract » means this text as well as its appendices and amendments.
In the case of contradiction between the provisions of this text and those of its appendices, the
5

 

provisions of this text shall prevail.
1.13     « Petroleum Costs » means all the costs and expenses incurred by the Contractor in execution of Petroleum Operations provided for in this Contract and determined according to the Accounting Procedure, the subject of Appendix 2 to this Contract.
1.14     « Effective Date » means the date of entry into force of this Contract such as it is defined in Article 30.
1.15     « Dollar » means the dollar of the United States of America ($).
1.16     « State » means the Islamic Republic of Mauritania.
1.17     « Gross Negligence » means imprudence or negligence of such gravity that it raises a presumption of malicious intent on the part of the person responsible for such action .
1.18     « Wet Gas » means Natural Gas containing a fraction of elements becoming liquid at ambient pressure and temperature, justifying the creation of a facility to recover such liquids.
1.19     « Natural Gas » means all gaseous hydrocarbons produced from a well, including Wet Gas and Dry Gas which may be associated or non-associated with liquid hydrocarbons and the residual gas which is obtained after extraction of the liquids from Natural Gas.
1.20     « Associated Natural Gas » means the Natural Gas existing in a reservoir in a solution with Crude Petroleum or in the form of "Gas Cap" in contact with Crude Petroleum, and which is produced or may be produced in association with the Crude Petroleum.
1.21     « Non-Associated Natural Gas » means Natural Gas excluding Associated Natural Gas.
1.22     « Dry Gas »  means Natural Gas containing essentially methane, ethane and inert gases.
1.23     « Hydrocarbons » means liquid and gaseous or solid hydrocarbons, in particular oil sands and oil shale.
1.24     « LIBOR » means the annual interbank rate applicable for the Dollar as published by the Financial Times, The Wall Street Journal or any other comparable publication of reference.
1.25     « Ministry » means the Ministry in Charge of Crude Hydrocarbons.
1.26     « Minister » means the Minister in Charge of Crude Hydrocarbons.
1.27     « Operator » means the company designated in Article 6.2 here below in charge of the conduct and the execution of Petroleum Operations or any company which would later be substituted for it according to applicable terms.
1.28     « Petroleum Operations » means all operations of exploration, exploitation, storage, transport and marketing of Hydrocarbons, including therein operations of evaluation/appraisal, development, production, separation, processing up until the Delivery Point, as well as the
6

 

remediation of the sites to their prior condition, and, more generally, all other operations directly or indirectly linked to the foregoing, carried out by the Contractor within the framework of this Contract, with the exclusion of refining and distribution of petroleum products.
1.29     « Ouguiya » means the currency of the Islamic Republic of Mauritania.
1.30     « Exploitation Perimeter » means all or part of the Exploratation Perimeter for which the State, within the context of this Contract, grants to the Contractor an Exploitation Authorization pursuant to the provisions of Article 9 here below .
1.31     « Exploration Perimeter » means the surface defined in Appendix 1, reduced, as the case may be, by relinquishments provided for in Article 3 and/or by Exploitation Perimeters, for which the State, in the context of this Contract, grants to the Contractor an Exploration Authorization pursuant to the provisions of Article 2.1 here below.
1.32     « Crude Petroleum » means all liquid Hydrocarbons in the natural state or obtained from Natural Gas by condensation or separation as well as asphalt.
1.33     « Delivery Point means:
 	§	 	For Crude Petroleum, the loading point F.O.B. of the Crude Petroleum as may be further defined more precisely in the possible lifting agreement(s) the Parties may enter into.	

 	§	 	For Natural Gas, the Delivery Point set by common agreement between the Parties pursuant to Article 15 of this Contract.	
1.34     « Remediation Plan » means the document detailing the program of work to be carried out by the Contractor at the expiration, the surrender or the canceling of an Exploitation Authorization, pursuant to Article 23.2 here below.
1.35     « Annual Work Program » means the descriptive document, item by item, of the Petroleum Operations to be carried out during the course of a Calendar Year within the framework of this Contract prepared pursuant to the provisions of Articles 4, 5 and 9 here below.
1.36     « Affiliated Company » means:
a)     Any company or any other entity which controls or is controlled, directly or indirectly, by a company or entity, party to this contract, or
b)     Any company or any other entity which controls or is controlled, directly or indirectly, by a company or entity which itself controls directly or indirectly any company or entity, party to this contract.
For purposes of this definition, the term « control » means the direct or indirect ownership by a
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company or any other entity of a percentage of capital stock or shares greater than fifty percent (50%) of the voting rights at the shareholders’ meeting of another company or entity.
1.37     « Third Party » means any natural person or legal entity other than the State, the Contractor and the Affiliated Companies of the Contractor.
1.38     « Quarter » means a period of three (3) consecutive months beginning on the first day of January, April, July or October of each Calendar Year.
ARTICLE 2 :  SCOPE OF APPLICATION OF THE CONTRACT
Pursuant to the Crude Hydrocarbons Code, the State hereby authorizes the Contractor to carry out on an exclusive basis in the Exploration Perimeter defined in Appendix 1 the appropriate and necessary Petroleum Operations within the framework of this Contract.
2.1       This Contract is entered into for the duration of the Exploration Authorization such as provided for in Article 3 of this Contract, including therein its renewal periods and possible extensions, and, in the case of a commercial discovery, for the duration of the Exploitation Authorizations which will have been granted, such as defined in Article 9.11 here below.
2.2       This Contract shall terminate if, at the expiration of all of the exploration phases provided for in Article 3, the Contractor has not notified the State of its decision to develop a commercial Hydrocarbons deposit and applied for an Exploitation Authorization relative to such deposit, pursuant to the provisions of Article 9.5 here below.
In the event of the grant of more than one Exploitation Authorization and unless there is an early termination, this Contract will expire upon the expiration of the last current valid Exploitation Authorization.
2.3       The expiration, surrender or termination of this Contract for whatever reason it may be, shall not free the Contractor from his obligations under this Contract, which came into being prior to the time of such expiration, surrender or termination, which obligations must be carried out by the Contractor.
2.4       The Contractor shall have the responsibility to carry out the Petroleum Operations provided for in this Contract. For their execution he undertakes to comply with good oilfield practice of the international petroleum industry and to comply with norms and standards decreed by Mauritanian regulations in matters of industrial safety, protection of the environment, and operational techniques.
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2.5       The Contractor shall supply all the financial and technical means necessary for the proper functioning of the Petroleum Operations and shall bear in full all the risks linked to the execution of said Operations, and without prejudice to the provisions of Article 21 of this Contract. The Petroleum Costs borne by the Contractor shall be recoverable by the Contractor pursuant to the provisions of Article 10 here below.
2.6       During the period of validity of the Contract, the production resulting from the Petroleum Operations shall be shared between the State and the Contractor pursuant to the provisions of Article 10 here below.
ARTICLE 3 :  EXPLORATION AUTHORIZATION
3.1       The Exploration Authorization in the Exploration Perimeter defined in Appendix 1 shall be granted to the Contractor for a first phase of four (4) Contract Years.
3.2       The Contractor shall have right to renewal of the Exploration Authorization two times, for a period of three (3) Contract Years each time, if he has fulfilled for the preceding exploration phase the work obligations stipulated in Article 4 here below and provided that he furnishes the bank guarantee for the renewal period pursuant to Article 4.6 here below.
3.3       In accordance with Article 21of the Crude Hydrocarbon Code, if at the expiration of any phase of the exploration period defined in Article 3.1 or 3.2 here above, works are actually still in progress, the Contractor shall have the right, if he submits an application duly providing supporting information, to a special extension of such phase for a period of time not to exceed twelve (12) months.
3.4       If the Contractor discovers one or more deposits of Hydrocarbons for which he cannot present the declaration of commerciality prior to the end of the third phase of the exploration period pursuant to Article 9.5 here below, by reason of the distance of the deposit in relation to possible delivery points on the Mauritanian territory and of the lack of infrastructure of transportation by pipeline, or the lack of a market for the production of the Natural Gas, he may apply for an extension of the Exploration Authorization for a maximum period of three (3) years for deposits of Petroleum or of Wet Gas and five (5) years for deposits of Dry Gas, the Exploration Perimeter being thus reduced to the presumed limits of the deposit(s) in question.
3.5       In the case where such an extension is granted, the Contractor must furnish to the Minister within sixty (60) days following the end of each Calendar Year of the period of extension a report showing whether or not the relevant deposit(s) is/are commercial, and, in the case of a deposit of Natural Gas, the results of the works and studies carried out pursuant to Article 15 here below.
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3.6       For each renewal or extension, other than the extension contemplated by Article 3.3, the Contractor must submit an application to the Minister not later than two (2) months prior to the expiration of the current exploration phase.
The renewals shall be granted by decree of the Minister while the extensions shall be granted by decree of the Council of Ministers; such decrees shall take effect starting from the date following the expiration of the preceding period.
3.7       The Contractor undertakes to relinquish to the State at least twenty-five percent (25%) of the initial surface area of the Exploration Perimeter at the time of each renewal of same, in such fashion as to not retain during the second phase of the exploration period more than seventy-five percent (75%) of the initial surface area of the Exploration Perimeter and during the third phase of the exploration period, not more than fifty percent (50%) of the initial surface area of the Exploration Perimeter.
3.8       For the application of Article 3.7 here above :
a)      The surfaces having previously been the subject of a voluntary relinquishment per Article 3.9 here below and the surfaces already covered by Exploitation Authorizations shall be deducted from the area subject to mandatory relinquishment.
b)      The Contractor shall have the right to determine the extent, the form and the location of the portion of the Exploration Perimeter which he intends to keep. However, the portion relinquished must consist of a perimeter of simple geometric form, delimited by North-South, East-West lines or by natural limits or frontiers.  The surface relinquishment shall be made according to the land registry grid from one of the borders of the initial or residual Exploration Perimeter and in a contiguous fashion.
c)      The application for renewal must be accompanied by a plan containing an indication of the Exploration Perimeter that was kept as well as a report specifying the works carried out since the Effective Date on the relinquished surfaces and the results obtained.
3.9       The Contractor may at any time, upon three (3) months’ notice, notify the Minister that he is surrendering all or a portion of the Exploration Perimeter.  In the event of a full surrender, the Exploration Authorization shall terminate automatically on the date of said notification.  In the case of a partial surrender, the provisions of Article 3.8 here above shall be applicable.
In all cases, no voluntary surrender during the course of an exploration phase shall reduce the exploration work commitments stipulated in Article 4 here below for said phase, nor does it terminate the corresponding bank guarantee.
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3.10     Except in the case of extension pursuant to Articles 3.3 and 3.4 here above, upon the expiration of the third phase of the exploration period, the Contractor must relinquish the remaining surface of the Exploration Perimeter, except for areas already comprised within Exploitation Perimeters.
Notwithstanding the preceding paragraph and pursuant to the provisions of Article 26.2 of the Crude Hydrocarbons Code, the Exploration Authorization shall remain in effect until Contractor submits a request for an Exploitation Authorization in accordance with the time frames stipulated in Article 9.
ARTICLE 4 :  EXPLORATION WORKS OBLIGATION
4.1       During the first phase of the exploration period of four (4) Contract Years defined in Article 3.1 here above, the Contractor undertakes to carry out the following work:
 	§	 	Acquire two thousand (2000) sq km 3D seismic;	

 	§	 	Reprocess the existing seimic data acquired by the prvious operator in Contract Area, subject to Contrator receiving such data from the Ministry.	
Said works must commence within the twelve (12) months following the Effective Date.
4.2       During the second phase of the exploration period of three (3) Contract Years defined in Article 3.2 here above, the Contractor undertakes to carry out the Drilling of one (1) Exploration well to a depth of two thousand five hundred (2500) meters below the mud line.
 	§	 	Said works must commence within the six (6) months following the start of the phase in question.	
4.3       During the third phase of the exploration period of three (3) Contract Years defined in Article 3.2 here above, the Contractor undertakes to carry out the Drilling of one (1) Exploration well to a depth of two thousand five hundred (2500) meters below mud line.
Said works must commence within the three (3) months following the start of the phase in question.
4.4       Each of the above-cited wells shall be carried out up to the minimum depth set forth here above, or to a lesser depth, upon authorization of the Minister, if the pursuit of the well, carried out according to good oilfield practices in the international petroleum industry, is impractical for
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one or another of the following reasons:
a)   The basement is encountered at a depth that is less than the minimum depth referred to above;
b)   The pursuit of the well presents a manifest danger by reason of the existence of an abnormal stratum pressure ;
c)   Rock formations are encountered, the hardness of which does not allow the practical advancement of the well carried out with the appropriate means of equipment;
d)   Petroliferous formations are encountered which in order to cross through requires for their protection the laying of casings, preventing the attainment of the above-cited minimum depth.
In each of the cases cited here above, the Contractor shall inform the Minister and shall be authorized to suspend the well and said well shall be deemed to have been drilled to the minimum depth referred to above.
4.5       If the Contractor, either during the course of the first phase of the exploration period, or during the course of the second phase of the exploration period, defined respectively in Articles 3.1 and 3.2 here above, carries out a number of exploration wells greater than the minimum commitments stipulated respectively in Articles 4.1 and 4.2 here above for said phase, the excess wells may be carried over to the following phase(s) of the exploration period and shall be deducted from the minimum work commitments stipulated for said phase(s).
For purposes of the application of Articles 4.1 to 4.5 here above, the wells carried out in the context of a program for evaluation of a discovery shall not be considered to be exploration wells, and, in the case of a discovery of Hydrocarbons, only one well per discovery shall be deemed to be an exploration well.
4.6       Within the thirty (30) days following the Effective Date, the Contractor must remit to the Minister a bank guarantee issued by an international bank of first order, pursuant to Appendix 3 of  four million Dollars ($4,000,000) covering his minimum work commitments for the first phase of the exploration period defined in Article 4.1 here above.  The guarantee will increase to seven million Dollars ($ 7,000,000) if the Contractor does not achieve the acquisition within six (6) months of the Effective Date.
In the case of renewal of the Exploration Authorization, the Contractor also must remit to the Minister, within the thirty (30) days following receipt of the decree from the Minister granting the renewal, a bank guarantee issued by an international bank of first order, pursuant to Appendix 3 of twenty-two million Dollars ($22,000,000) for the second Phase of the
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exploration period and of twenty-two million Dollars ($22,000,000) for the third Phase of the exploration period.
If on expiration of any phase of the exploration period or in the case of total or partial surrender or termination of the Contract, the exploration works have not reached the minimum commitments of this Article 4, the Minister shall have the right to call the guarantee for an amount equal to the amount of the guarantee after deduction of the estimated cost of the minimum work actually carried out.
Such cost shall be calculated on a lump-sum basis in utilizing the following unit costs:
a)       three thousand five hundred Dollars ($3500) per square kilometer;
b)       twenty-two million Dollars ($22,000,000) per exploration well.
Once the payment is made, the Contractor shall be deemed to have fulfilled his minimum exploration work obligations per Article 4 of this Contract; the Contractor may, except in the event of cancellation of the Exploration Authorization for a major failure in performance of this Contract, continue to benefit from the provisions of said Contract and, in the case of an acceptable application, obtain the renewal of the Exploration Authorization.
ARTICLE 5 :  PRESENTATION  AND APPROVAL OF ANNUAL WORK PROGRAMS
5.1       Not later than (2) months after the Effective Date, the Contractor shall prepare and submit to the Ministry for approval an Annual Work Program, detailed item by item, including therein the corresponding Annual Budget for all of the Exploration Perimeter, specifying the Petroleum Operations relating to the period running from the Effective Date to the following 31 December.
Thereafter, not later than (3) months prior to the start of each Calendar Year, the Contractor shall prepare and submit to the Ministry for approval an Annual Work Program, detailed item by item, including therein the corresponding Annual Budget for all of the Exploration Perimeter, then, if applicable, for the Exploitation Perimeter(s), in specifying the Petroleum Operations which he proposes to carry out over the course of the following Calendar Year.
Each Annual Work Program and corresponding Annual Budget shall be itemized between the different activities of exploration, and if applicable, of appraisal for each discovery, of development and of production for each commercial deposit.
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5.2       If the Ministry deems that revisions or modifications to the Annual Work Program and to the corresponding Annual Budget are necessary and appropriate, it must so notify the Contractor in writing with all supporting documentation deemed appropriate within a time period of sixty (60) days following their receipt.  In such case, the Ministry and the Contractor shall meet as soon as possible in order to study the revisions or modifications requested and establish by common agreement the Annual Work Program and the corresponding Annual Budget in their definitive form, according to good oilfield practice in the international petroleum industry .    The date of adoption of the Annual Work Program and of the corresponding Annual Budget shall be the above-cited mutually agreed date.
In the absence of notification by the Ministry to the Contractor of his wish for revision or modification within the time period of the above-referenced sixty (60) days, said Annual Work Program and corresponding Annual Budget shall be deemed accepted by the Ministry upon the date of expiration of said time period.
In all cases, each operation of the Annual Work Program, for which the Ministry has not requested revision or modification, must be carried out by the Contractor within the time periods set forth.
5.3       The Parties accept that the results obtained during the course of the works taking place, or that special circumstances may justify changes to an Annual Work Program and to the corresponding Budget.  In such case, after notification to the Ministry, the Contractor may make such changes provided that the fundamental objectives of said Annual Work Program are not modified.
ARTICLE 6 : OBLIGATIONS OF THE CONTRACTOR IN THE CONDUCT OF PETROLEUM OPERATIONS
6.1       Without prejudice to the provisions of Article 21 here below, the Contractor must furnish all necessary funds and purchase or rent all tools, equipment and construction supplies that are indispensable for the execution of Petroleum Operations.  The Contractor is responsible for the preparation and the execution of the Annual Work Programs which are to be carried out in the most appropriate manner in compliance with good oilfield practice in the international petroleum industry.
6.2       Upon the Effective Date of this Contract, Kosmos Energy Mauritania is designated as Operator and shall be responsible for the conduct and the execution of the Petroleum Operations.  The Operator, in the name of and on the behalf of the Contractor, shall communicate to the
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Minister all reports and information referred to in this Contract. Any change of Operator contemplated by the entities of the Contractor must receive the prior approval of the Minister, which approval shall not be withheld without reasonable justification provided therefor.
6.3      The Operator must maintain during the term of the Contract in Mauritania, a branch which shall in particular be staffed with a responsible person having authority for the conduct of the Petroleum Operations and to whom any notification with regard to this Contract can be sent.
6.4       The Contractor must during the course of the Petroleum Operations take all necessary measures for the protection of the environment.
He must in particular, for any Petroleum Operation subject to prior authorization according to the Environmental Code, submit to the Minister, depending on the case, the studies or notices of environmental impact required for this type of operation, carry out the measures and comply with restrictions set forth in the environmental management plan, furnish the declarations and submit himself to the oversight provided for in the Environmental Code
The Contractor must moreover take all reasonable measures according to good oilfield practice in the international petroleum industry in order to:
a)   Ensure that all of the facilities and equipment utilized for purposes of the Petroleum Operations be at all times in good repair and in conformity with the applicable norms, including therein those which result from international conventions ratified by the Islamic Republic of Mauritania and relative to the prevention of pollution;
b)   avoid losses and dumping:
-  of Hydrocarbons, including the flaring of Natural Gas, (with the exception of the cases provided for in Article 40 of the law instituting the Crude Hydrocarbons Code, under penalty of a fine which shall be later be determined by a decree taken by the Council of Ministers and which shall not under any circumstances exceed twenty (20) per cent of the then current market price of Natural Gas in Mauritania),
The above-cited fine shall not be considered a recoverable Petroleum Cost nor a deductible charge.
c)   DOES NOT APPLY.
d)   Store the Hydrocarbons produced in the facilities and receptacles constructed for this purpose ;
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e)   Without prejudice to the provisions of Article 23.2 here below, dismantle facilities which are no longer necessary to the Petroleum Operations and return the sites to their original condition;
f)   and, generally, prevent pollution of the soil and of the subsoil, of the water and of the atmosphere, as well as prevent harm to fauna and flora.
6.5       The Contractor must, during the course of the Petroleum Operations, take all necessary measures to ensure the safety and protect the health of persons according to good oilfield practices in the international petroleum industry and the Mauritanian regulations in force, and in particular to put into place:
a)   Appropriate means for prevention, rapid response and handling of risks, including the risks of blow-out;
b)   Measures for information, training and means adapted to the risks encountered, including therein individual protective equipment, fire-fighting materials as well as means of first-aid and prompt evacuation of victims.
6.6       All works and facilities set up by the Contractor under this Contract must, according to the nature and circumstances, be constructed, shown with markers and sign posts and equipped in such fashion as to allow at any time and in complete safety free passage within the Exploration Perimeter and the Exploitation Perimeter(s).
6.7       While carrying out his right of construction, to execute works, and to maintain all facilities necessary for the purposes of this Contract, the Contractor should not occupy lands situated less than five hundred (500) meters away from any religious buildings, whether cultural or not, burial grounds, walled enclosures, courts and gardens, dwelling places, groups of dwelling places, villages, built-up areas, wells, springs , reservoirs, roads, routes, railways, water conduits, pipelines, works of public utility, civil engineering works, without the prior consent of the Minister. The Contractor shall be required to repair any damages which his works may have caused to occur.
6.8       The Contractor commits to granting preference to Mauritanian enterprises and products, on equivalent conditions in terms of price, quantity, quality, terms for payment and timeframe of delivery, and to require his subcontractors to make a similar commitment
All contracts of supply, construction or service of a value greater than seven hundred fifty thousand (750,000) Dollars where works of exploration/appraisal are concerned and one million five hundred thousand ($1,500,000) Dollars where works of development/exploitation are concerned, must be the subject of a call for bids from Mauritanian and foreign bidders,
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unless there is a prior consent from the Minister.
Copies of such contracts entered into during the course of each Quarter shall be sent to the Minister within the thirty (30) days following the end of the relevant Quarter.
6.9       The Contractor undertakes to grant preference, on equivalent economic terms, in the purchase of goods necessary for the Petroleum Operations, taking into account rental terms and any other lease arrangements and to require from his subcontractors a similar commitment .
To this end, every Annual Budget referred to in Article 5 must specify all the draft rental contracts of an annual value greater than seven hundred fifty thousand (750,000) Dollars.
6.10     Without prejudice to the obligation and responsibility of the Contractor in respect of protecting the environment, the Parties agree to collaborate to support the management of environemental risks in a precuationary manner.  To this end, the Contractor agrees to contibute to the financing of the Environmental Committee by the payment of an amount of one hundred thousand Dollars ($100,000) per Calendar Year during the validity of the Exploration Authorization, and, starting from the granting of an Exploitation Authorization, an amount of three hundred fifty thousand Dollars ($350,000) per Calendar Year, and, starting from first commercial production from an Exploitation Authorization, an amount of seven hundred thousand Dollars ($700,000) per Calendar Year. The above-cited payments shall be considered to be recoverable Petroleum Costs with respect to the provisions of Article 10.2 here above and as deductible charges on the Industrial and Commercial Income Tax in conformity with Article 82 of the Crude Hydrocarbons Code.  Contractor shall have the right to be represented on the Environmental Committee for the duration of this Contract and shall appoint one (1) representative for this purpose.
ARTICLE 7 :  RIGHTS OF THE CONTRACTOR IN THE CONDUCT OF PETROLEUM OPERATIONS
7.1       The Contractor has the exclusive right to carry out Petroleum Operations inside of the Exploration Perimeter or any Exploitation Perimeter resulting therefrom, as long as the Petroleum Operations are in conformity with the terms and conditions of this Contract, of the Crude Hydrocarbons Code as well as with the provisions of the laws and regulations in force in
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Mauritania, and that they are executed according to good oilfield practice in the international petroleum industry.
7.2       For purposes of the execution of the Petroleum Operations, the Contractor shall benefit from the rights set forth in Article 54 of the Crude Hydrocarbons Code.
7.3       The costs, compensation payments, and in general all charges resulting from occupation of lands referred to in Articles 55 to 57 of the Crude Hydrocarbons Code shall be at the expense of the Contractor and shall be recoverable as Petroleum Costs pursuant to the provisions of Article 10.2 here below.
7.4       The expiration of an Exploration Authorization or of an Exploitation Authorization, or the obligatory or voluntary relinquishment, partial or total of an Exploration Perimeter or of an Exploitation Perimeter has no effect with regard to the rights resulting from Article 7.2 here above for the Contractor, on works and facilities executed in application of the provisions of this Article 7, provided that said works and facilities continue to be utilized in the framework of the Contractor’s activity on the portion kept or on other exploration or exploitation perimeters in Mauritania.
7.5       Subject to the provisions of Articles 6.8 and 6.9 here above, the Contractor has freedom of choice concerning suppliers and subcontractors and shall benefit from the customs regime set forth in Article 18 of this Contract.
7.6       Unless there are provisions to the contrary in the Contract, no restriction shall be set upon the entry, the stay, freedom of movement, employment and repatriation of persons and their families as well as their goods, for the employees of the Contractor and those of his subcontractors, subject to compliance with employment legislation and regulations as well as social laws in force in Mauritania.
The Ministry shall facilitate the delivery to the Contractor, as well as to his agents, to his subcontractors and to their families, all administrative authorizations which may possibly be required in relation with the Petroleum Operations carried out in the framework of this Contract, including entry and exit visas.
ARTICLE 8 :  MONITORING OF PETROLEUM OPERATIONS AND ACTIVITY REPORTS – CONFIDENTIALITY
8.1       The Petroleum Operations shall be subject to monitoring by the Ministry pursuant to the
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provisions of Title VIII of the Crude Hydrocarbons Code.  The duly mandated representatives of the Ministry shall in particular have the right to monitor the Petroleum Operations, to inspect facilities, equipment, materials, and to audit said procedures, norms, records and books pertaining to the Petroleum Operations.  Said such representatives shall make every effort not to disrupt the normal conduct of Contractor’s operations.
In order to allow the exercise of the rights referred to here above, the Contractor shall furnish to the representatives of the Ministry and to the other agents of the State in charge of the supervision of Petroleum Operations reasonable assistance in the matter of means of transport and of lodging.  The reasonable expenses for transport and lodging directly linked to monitoring and inspection shall be at the expense of the Contractor.  Such expenses shall be considered as recoverable Petroleum Costs according to the provisions of Article 10.2 of this Contract and as deductible charges for purposes of the calculation of Industrial and Commercial Income Tax.
8.2       The Contractor shall keep the Ministry regularly informed of the status of the Petroleum Operations. He must in particular supply the Ministry with the following programs and information:
a)   A work program for any geological or geophysical campaign, at least thirty (30) days before the beginning of the campaign in question and specifying in particular its location, its objectives, the techniques and equipment utilized, the name and address of the enterprise which will carry out the work, the starting date and the projected duration, the number of kilometers of seismic lines, the estimated costs and the safety measures put into place if the usage of explosives is contemplated.
b)   A work program for any well, at least thirty (30) days before the spudding of the well in question and specifying in particular its precise location, a detailed description of the works contemplated, including the well techniques and the associated operations, its depth, its geological objective, the start date and the projected duration, the estimated costs of the program, a summary of the geological and geophysical data which prompted the Contractor’s decision, the name and address of the drilling contractor as well as the designation of the well site, the name and address of all other subcontractors recruited for such operation, and the safety measures envisioned.
c)   An advance notice of thirty (30) days concerning any abandonment of a producing well and forty-eight (48) hours when it concerns a non-producing well.
d)   An advance notice of forty-eight (48) hours concerning any suspension of drilling or resumption of drilling after a suspension of greater than thirty (30) days.
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Any accident involving a stoppage of work or material damage or death occurring in the framework of the Petroleum Operations must be immediately notified to the Minister and not later than within twenty-four (24) hours.
8.3       The Ministry may require from Contractor the execution, at the expense of the latter, of all work necessary to ensure safety and hygiene within the framework of the Petroleum Operations, pursuant to Article 6.5 here above.
8.4       The Ministry shall have access to all original data resulting from Petroleum Operations undertaken by the Contractor within the Exploration Perimeter and Exploitation Perimeter(s) such as geological, geophysical, petrophysical, drilling, reports concerning commencement of exploitation and all other reports generally required for the Petroleum Operations.
8.5       The Contractor commits to furnishing to the Ministry the following periodic reports:
a)   Daily reports on drilling activities;
b)   Weekly reports on geophysical works;
c)   Starting from the date of granting of an Exploitation Authorization, within fifteen (15) days following the end of each Quarter, a detailed report on development activities;
d)   Starting from the start-up of production, within fifteen (15) days following the end of each month, an exploitation report specifying in particular each of the quantities of Hydrocarbons produced, utilized in Petroleum Operations, stored, lost or flared, and sold, during the course of the preceding month as well as an estimate of each of the quantities in question for the current month.  With regard to Hydrocarbons sold, the report shall specify for each sale the identity of the buyer, the quantity sold and the price obtained;
e)   Within the fifteen (15) days following the end of each Quarter, a report relative to Petroleum Operations carried out during the Quarter elapsed, containing in particular a description of the Petroleum Operations carried out and a detailed statement of the Petroleum Costs incurred, categorized in particular by Exploration Perimeter / Exploitation Perimeter and by type;
f)   Within the three (3) months following the end of each Calendar Year, a report relative to the Petroleum Operations carried out during the Calendar Year elapsed, as well as a detailed statement of Petroleum Costs incurred, categorized in particular by Exploration Perimeter / Exploitation Perimeter and by type and a statement of the personnel employed by the Contractor, indicating the number of employees, their nationality, their duties, the
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total amount of the salaries as well as a report on medical care and instruction given to them.
g)   Any other report generally required within the framework of Petroleum Operations.
8.6       Moreover, the following reports, data and documents shall be furnished to the Ministry during the month following their drafting or their being obtained:
a)   Two (2) copies of the geological reports made in the framework of exploration ;
b)   Two (2) copies of geophysical reports made in the framework of exploration.  The Ministry shall have access to the originals of all recordings made (magnetic tapes or other format) and may, upon request, obtain copies;
c)   Two (2) copies of reports of commencement and termination of drilling for each of the wells drilled;
d)   Two (2) copies of all measures, tests, and well loggings recorded during the course of drilling (drilling termination reports);
e)   Two (2) copies of each report of analyses (petrography, biostratigraphy, geochemistry or other) carried out on the core samples, the cuttings or fluids sampled in each one of the wells drilled, including therein raw data and supporting items with media for copying photos pertaining thereto;
f)   A representative portion of the core samples taken, well cuttings taken from each well as well as fluid samples collected during the production tests shall also be supplied within reasonable periods of time.
g)   Moreover, the Contractor may freely export core samples taken, drill cuttings taken and fluids produced;
h)   And in a general fashion, two (2) copies of all other reports generally required for Petroleum Operations.
Reports, studies and other results referred to in this Article 8.6, as well as those referred to in Article 8.5 here above, shall be supplied in a suitable medium in digital and/or hard copy.
8.7       The Parties undertake to consider as confidential and to not communicate to Third Parties or to publish, except with the prior consent of the Minister, data and information of a technical nature related to the Petroleum Operations and which would not already be in the public domain, for the entire duration of the Contract.
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In the case of relinquishment of a surface area or surrender of a perimeter , the Contractor undertakes to consider as confidential and to not communicate to Third Parties or to publish, except with the prior consent of the Minister, the data and information relating to the perimeter in question and which would not already be in the public domain.
After the surrender, termination or expiration of the Contract, the Contractor undertakes to consider as confidential and to not communicate to Third Parties or to publish, except with the prior consent of the Minister, the data and information relating to Petroleum Operations and which would not already be in the public domain.
8.8       Notwithstanding the provisions of Article 8.7, the State may communicate the data and information:
a)   To all suppliers of services and professional consultants providing services in the framework of the monitoring of Petroleum Operations, after obtaining a similar commitment of confidentiality;
b)   To any bank, institution or financial establishment with which an entity of the State solicits or obtains financing, after obtaining a similar commitment of confidentiality;
c)   In the framework of any contentious proceeding in a legal, administrative or arbitrational matter.
8.9       Notwithstanding the provisions of Article 8.7, the Contractor may communicate the data and information:
a)   To any Affiliated Company bound by a similar commitment of confidentiality;
b)   To any suppliers of services and professional consultants providing services in the framework of Petroleum Operations, after obtaining a similar commitment of confidentiality;
c)   To any company with a bona fide interest in the carrying out of a possible assignment, after obtaining from such company a commitment to keep confidential such information and to utilize it only for the purposes of such assignment;
d)   To any bank or financial establishment with which an entity of the Contractor solicits or obtains financing, after obtaining a similar commitment of confidentiality;
e)   When and to the extent that the regulations of a recognized stock exchange require the information;
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f)   Within the framework of any contentious proceeding in a legal, administrative or arbitrational matter.
8.10     The Contractor must report to the Minister the soonest possible any information relative to mineral substances encountered during the Petroleum Operations.
8.11     The Contractor must participate in the implementation of the Extractive Industries Transparency Initiative (EITI) pursuant to Article 98 of the Crude Hydrocarbons Code.
ARTICLE 9 :  APPRAISAL OF A DISCOVERY AND GRANTING OF AN EXPLOITATION AUTHORIZATION
9.1       If the Contractor discovers Hydrocarbons in the Exploration Perimeter, he must so notify the Minister in writing the soonest possible and carry out, pursuant to good oilfield practice in the international petroleum industry, the necessary tests.  Within the thirty (30) days following the provisional closure or abandonment of the discovery well, the Contractor must submit to the Minister a report giving all information pertaining to such discovery and formulating recommendations of the Contractor as to whether or not to pursue his appraisal.
9.2       If the Contractor wishes to undertake the appraisal works of the above-cited discovery, he must diligently submit to the Minister for approval the appraisal work program, the timetable for execution and the estimate of the corresponding budget, not later than six (6) months following the date of the notification of the discovery referred to in Article 9.1 here above.
The Contractor must then commence with maximum diligence the appraisal work pursuant to the program drawn up, it being understood that the provisions of Articles 5.2 and 5.3 here above shall apply to said program.
9.3       Within the three (3) months following the completion of the appraisal works, and not later than thirty (30) days prior to the expiration of the third phase of the exploration period defined in Article 3.2, as may be extended pursuant to the provisions of Articles 3.3 and 3.4 here above, the Contractor shall submit to the Minister a detailed report giving all the technical and economic information relative to the deposit so discovered and appraised, and establishing the commercial character or not of the said discovery.  Such report shall in particular include the following information:  the geological and petrophysical, characteristics, and the estimated delimitation of the deposit; the results of the production tests carried out, the nature, properties and volume of Hydrocarbons which it contains, a preliminary technical and economic study on the placement of the deposit into production.
9.4       Any quantity of Hydrocarbons produced from a discovery before the discovery has been declared commercial, if it is not utilized for the carrying-out of the Petroleum Operations, or
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lost, shall be subject to the provisions of Article 10 of this Contract.
9.5       A deposit considered by the Contractor to be commercially exploitable gives him the right to an Exploitation Authorization. In such case, the Contractor shall submit to the Minister, within the three (3) months following the submission of the report referred to in Article 9.3 here above, and not later than thirty (30) days prior to the expiration of the third phase of the exploration period defined in Article 3.2, possibly extended pursuant to the provisions of Articles 3.3 and 3.4 here above, an application for an Exploitation Authorization. Said application shall specify the lateral and stratigraphic delimitation of the Exploitation Perimeter, which shall cover only the presumed limits of the deposit discovered and appraised in the Exploration Perimeter then currently valid and shall be accompanied by technical justifications necessary for said delimitation. The above-cited application for an Exploitation Authorization shall be accompanied by a detailed development and production program, including in particular for the deposit in question :
a)   An estimate of the recoverable reserves, proven and probable and of the corresponding production profile, as well as a study of the methods of recovery of hydrocarbons and development of natural gas;
b)   A description of the works and facilities required to put the field into production, such as number of wells, facilities required for production, separation, processing, storage and transport of Hydrocarbons;
c)   A program and a schedule for carrying out the said works and facilities, including startup date for production ;
d)   An estimate of development investments and exploitation costs itemized for each year as well as an economic study confirming the commercial character of the deposit ;
e)   The methods for financing such investments by each one of the entities making up the Contractor ;
f)   An environmental impact study of the development project, carried out by the Contractor pursuant to the provisions of the Environmental Code.
g)   An outline of a Rehabilitation Plan to return the sites to their original condition at the end of exploitation.
The Minister may propose revisions or modifications to the development and production program referred to above, as well as to the Exploitation Perimeter applied for, in notifying the Contractor thereof with all justifying supporting data deemed appropriate, within the ninety (90)
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days following receipt of the said program.  The provisions of Article 5.2 here above shall apply to said program with regard to its adoption.
When the results acquired during the course of development justify changes to the development and production program, said program may be modified in utilizing the same procedure as that referred to here above for its initial adoption.
9.6       The Exploitation Authorization shall be granted by the Minister within forty-five (45) days following the date of adoption by the Parties of the development and production program.  The granting of an Exploitation Authorization entails  ipso facto  the cancellation of the Exploration Authorization inside of the Exploitation Perimeter; however, the Exploration Authorization continues to be valid outside that perimeter until its expiration date, without the minimum exploration work obligation referred to in Article 4 above for the subject phase of the exploration period being modified.
9.7       If the Contractor makes several commercial discoveries within the Exploration Perimeter, each of such will give rise, in accordance with Articles 9.5 and 9.6 here above, to a separate Exploitation Authorization corresponding to an Exploitation Perimeter.
9.8       If in the course of work subsequent to the grant of an Exploitation Authorization, it appears that the deposit has an extension greater than that initially provided for in Article 9.5 here above, the Minister shall grant to the Contractor, within the framework of the Exploitation Authorization already granted, the additional portion, provided that the extension is an integral part of the currently valid Exploration Perimeter and that the Contractor supplies the technical justifications for the extension applied for.
If it appears that the deposit has an extension less than that initially provided for, the Minister may require the Contractor to relinquish the exterior portion(s) of the boundaries of the deposit.
9.9       In the event that a deposit extends beyond the boundaries of the currently valid Exploration Perimeter, the Minister may require the Contractor to exploit such deposit together with the holder of the adjacent perimeter following the provisions of Article 53 of the Crude Hydrocarbons Code. Within the twelve (12) months following the written request of the Minister, the Contractor must submit to him, for approval, a draft development and production program of the relevant deposit drawn up in agreement with the holder of the adjacent perimeter.
In the case where the deposit extends over one or more other perimeters which are not under contract, the process of extension of the contractual perimeter may be undertaken, pursuant to the provisions of the Crude Hydrocarbons Code.
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9.10     The Contractor must start up the development operations including the necessary studies, not later than six (6) months following the date of granting of the Exploitation Authorization referred to in Article 9.6 here above and must pursue them with the maximum diligence. The Contractor undertakes to carry out the development and production operations according to good oilfield practice in the international petroleum industry, making it possible to ensure the optimum recovery of Hydrocarbons contained in the deposit. The Contractor undertakes to proceed as soon as possible with studies of assisted recovery in consultation with the Ministry and to utilize such processes if, in the estimation of Contractor, such processes will lead under the economic conditions to an improvement of the rate of recovery.
9.11     The duration of the exploitation period during which the Contractor is authorized to ensure the production of a deposit declared to be commercial is set at twenty-five (25) years if the exploitation is for deposits of Crude Petroleum and thirty (30) years if the exploitation is for deposits of Dry Gas, starting from the date of granting of the corresponding Exploitation Authorization.
Upon the expiration of the initial period of exploitation defined here above, the Exploitation Authorization may be renewed for an additional maximum period of ten (10) years upon an application by Contractor providing supporting information submitted to the Minister at least one (1) year prior to said expiration, provided that the Contractor has fulfilled all his contractual obligations during the initial exploitation period and that he proves that additional commercial production from the Exploitation Perimeter remains possible during the additional period applied for.
9.12     For any deposit having given rise to the granting of an Exploitation Authorization, the Contractor must, without prejudice to the provisions of Article 21 here below, carry out at his own expense all appropriate and necessary Petroleum Operations to place the deposit into exploitation, in conformity with the adopted development and production program.
However if the Contractor believes, on the basis of technical knowledge acquired on such deposit, and can make the accounting proof during the course of the development and production program or during the course of exploitation that producing from such deposit cannot be, or can no longer be, commercially profitable, even though the discovery well and the appraisal works have led to the granting of an Exploitation Authorization pursuant to this Contract, the Minister undertakes to not obligate the Contractor to pursue the works and to
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explore with the Contractor, to the extent possible, technical and economic improvements which would permit the Contractor to consider the profitable exploitation of said deposit.  In the case where the Contractor decides not to pursue the exploitation works and if the Minister asks him to, the Contractor shall surrender the relevant Exploitation Authorization and the rights which are attached thereto.
9.13     The Contractor may at any time, subject to so notifying the Minister in writing with an advance notice of at least six (6) months, surrender totally or in part an Exploitation Authorization, provided that he has satisfied all obligations provided for in this Contract .
9.14     The Contractor undertakes for the duration of the Exploitation Authorizations to produce annually quantities of Hydrocarbons from each deposit according to generally accepted norms in the international petroleum industry in taking principally into consideration the rules for the proper conservation of deposits and the optimal recovery of the reserves of Hydrocarbons under economic conditions for the duration of the relevant Exploitation Authorizations.
9.15     The ceasing of production of a deposit for a duration greater than six (6) consecutive months, decided upon by the Contractor without the consent of the Minister, may lead to the cancellation of this Contract within the terms set forth in Article 25 here below.
9.16     The Minister may place the Contractor on notice by registered letter with return receipt to remedy the following shortcomings within a time period of three (3) months, if the latter, without duly justified reasons:
a)   Has not submitted an appraisal work program for said discovery within the time period referred in Article 9.2 here above ;
b)   Has not carried out the appraisal works of said discovery in conformity with the appraisal program  referred to in Article 9.2 here above ;
c)   Or has not submitted an application for an Exploitation Authorization within the time period referred to in Article 9.5 here above.
If the Contractor has not remedied the above shortcomings within the mentioned time period, the Minister may then demand that he relinquish immediately and without compensation all his rights within the presumed boundaries of said discovery, including the Hydrocarbons which could be produced from it.
The State may then carry out all works of appraisal, development and production of such discovery upon condition however that it does not cause damage to the performance of the
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Petroleum Operations of the Contractor in the Exploration Perimeter or any Exploitation Perimeter governed by the Contract.
ARTICLE 10 :  RECOVERY OF PETROLEUM COSTS AND PRODUCTION SHARING
10.1     From the commencement of regular Hydrocarbons production carried out pursuant to an Exploitation Authorization or an early production authorization, that production shall be shared and sold in accordance with the provisions hereafter.
10.2     For the recovery of Petroleum Costs, the Contractor shall freely retain each Quarter, and for each Exploitation Authorization, a share of total production equal to fifty-five percent (55%) for Crude Petroleum and sixty-two percent (62%) for Dry Gas, calculated on total production which is not utilized for Petroleum Operations, nor wasted, or, if applicable, a lower percentage of production, or only a lower percentage which would be necessary and would suffice.
The value of the share of total production allocated for the petroleum cost recovery of the Contractor as defined in the preceding subparagraph, shall be calculated in accordance with the provisions of Articles 14 and 15 here below.
In the course of a Calendar Year, should the Petroleum Costs not yet recovered by the Contractor pursuant to the provisions of this Article 10.2 exceed the equivalent in value of fifty-five percent (55%) with respect to Crude Petroleum and sixty-two percent (62%) with respect to Dry Gas, of the total production calculated as indicated here above, the excess which cannot be recovered for the Calendar Year under consideration shall be carried forward to the following Calendar Year(s) until full recovery of Petroleum Costs or the termination of this Contract.  The recovery of Petroleum Costs for any Quarter shall be scheduled in the order stipulated in the Accounting Procedure.
10.3     The volume of Hydrocarbons, related to each Exploitation Authorization, which remains for each Quarter after the Contractor has taken from total production the share necessary to the recovery of Petroleum Costs under the provisions of Article 10.2 here above, shall be shared between the State and the Contractor in the following manner, in the ratio of the applicable figure for the ratio “R” defined as follows:
Value of « R »	    	Share of the State	    	Share of the
Contractor	 	
Less than 1	 	31 	%  	69 	%	
Greater than or equal to 1 and less than 1.5	 	33 	%  	67 	%	
Greater than or equal to 1.5 and less than 2	 	35 	%  	65 	%	
Greater than or equal to 2 and less than 2.5	 	37 	%  	63 	%	
Greater than or equal to 2.5 and less than 3	 	39 	%  	61 	%	
Greater than or equal to 3	 	42 	%  	58 	%	
 
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For the application of this Article, the ratio « R » means to the ratio of « Cumulative Net Revenue » of Contractor over « Cumulative Investments » in the relevant Exploitation Perimeter, where:
« Cumulative Net Revenue » means the sum, calculated from the Effective Date until the end of the preceding Quarter, of the value of Hydrocarbons obtained by Contractor pursuant to the provisions of Articles 10.2 and 10.3 here above ; less the Exploitation Petroleum Costs incurred by the Contractor, as such are defined and determined under the provisions of the Accounting Procedure. 
« Cumulative Investments » means the sum, from the Effective Date up until the end of the preceding Quarter, of the Exploration Petroleum Costs and the Development Petroleum Costs incurred by the Contractor as defined and determined under the provisions of the Accounting Procedure.
10.4     The State may receive its share of production defined in Article 10.3 here above, either in kind, or in cash.
10.5     If the State wishes to receive in kind all of part of its share of production defined in Article 10.3 here above, the Minister shall advise the Contractor in writing not less than ninety (90) days prior to the commencement of the relevant Quarter and specify the exact quantity it wishes to receive in kind during said Quarter and the modalities of delivery, which must be specified in the lifting contract.
For this purpose, it is agreed that the Contractor shall not commit to the sale of a part of the State production, for a term which exceeds one hundred and eighty (180) days, unless he shall have obtained the written consent of the Minister.
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10.6     If the State wishes to receive in cash all or part of its share of production specified in Article 10.3 here above, or if the Minister has failed to notify the Contractor of its decision to take a portion of the State’s production in kind in accordance with Article 10.5 here above, the Contractor is obligated to sell the State share of production which the State wishes to take in cash during the relevant Quarter, and to proceed with the liftings of such share in the course of such Quarter, and to pay the State within thirty (30) days following each lifting, an amount equal to the quantity corresponding to the portion of the State production share, multiplied by the sale price F.O.B., after deduction of the costs attributable to such sales.
The Minister shall be entitled to request the settling of the sales of the State share of production effected by the Contractor either in Dollars or in any other convertible currency in which the transaction took place.
ARTICLE 11 : TAX REGIME
11.1      Each of the entities which make up the Contractor shall be subject to the Industrial and Commercial Income Tax levied on the net profits earned in relation to the Petroleum Operations in accordance with Articles 66 to 74 of the Crude Hydrocarbons Code and the provisions of the Accounting Procedure found in Annex 2 of this Contract.
The rate of this tax is set at twenty-seven percent (27%) for the entire duration of the Contract such as defined in Article 2.2 here above.
For the purposes of setting the amount of the  Industrial and Commercial Income Tax, the value of Hydrocarbons sold by the Contractor under Articles 10.2 and 10.3 here above to be included in net taxable profit shall be established  in accordance with the provisions of Article 14 here below.
11.2     Without prejudice to the provisions of Article 21 here below, the Contractor shall pay to the State the following surface rentals:
a)   two Dollars ($2) per square kilometer and per year during the first phase of the exploration period ;
b)   three Dollars ($3) per square kilometer and per year during the second phase of the exploration period ;
c)   four Dollars ($4) per square kilometer and per year during the third phase of the exploration period and during any extension provided for in Articles 3.3 and 3.4 here above;
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d)   one hundred seventy Dollars ($170) per square kilometer and per year during the validity of the Exploitation Authorization.
The surface rentals referred to in paragraphs a), b) and c) here above shall be paid in advance and per year, not later than the first day of each Contract Year, for the entire Contract Year, according to the extent of the Exploration Perimeter held by the Contractor upon the due date of said rentals.
The surface rental relative to an Exploitation Authorization shall be paid in advance and per year, at the beginning of each Calendar Year following the granting of the Exploitation Authorization or for the Calendar Year of said grant, within thirty (30) days of the date of the grant, prorated over time for the remaining duration of the current Calendar Year, according to the extent of the Exploitation Perimeter upon such date.
In the case of relinquishment of the surface during the course of a Calendar Year or during the course of an event of Force Majeure, the Contractor shall have no right to any reimbursement of surface rentals already paid.
The amounts referred to in this Article 11.2 are not considered recoverable Petroleum Costs under the provisions of Article 10.2 here above, nor are they considered as deductible costs for setting the basis of the Industrial and Commercial Income Tax in accordance with Article 76 of the Crude Hydrocarbons Code.
11.3     The Contractor shall be subject to taxes and fees as well as to withholdings at source and other tax obligations applicable to contractors pursuant to Title VI of the Crude Hydrocarbons Code.
11.4     The subcontractors of the Contractor as well as the personnel of the Contractor and of his subcontractors shall be subject to the generally applicable tax provisions, subject to the provisions of Title VI of the Crude Hydrocarbons Code which are applicable to them.
11.5    The shareholders of the entities making up the Contractor and their Affiliated Companies shall benefit from the exemptions provided for in Article 86 of Title VI of the Crude Hydrocarbons Code.
11.6     Except for taxes, fees and dues provided in Title VI of the Crude Hydrocarbons Code, for special taxes related to the utilization of drinking water or of irrigation water provided for in Article 6 .4 here above, for the surface rentals provided for in Article 11.2 here above, for the bonuses provided for in Article 13 here below andfor the payment referred to in Article 12.2 here below, the Contractor shall not be subject to any tax, fees, royalties, payments and
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contributions of any nature whatsoever, be they national, regional or municipal, either in effect now or in the future, which may burden the Petroleum Operations, and of any revenue derived therefrom or more generally, the property, the activities or action of the Contractor, including its facility, its money transfers, and its operation in implementation of this contract, provided, however, that these exemptions are only applicable to Petroleum Operations.
Pursuant to Article 83-2º of the Crude Hydrocarbons Code, the rendering of services directly related to Petroleum Operations shall, in particular, be subject to VAT at the rate of zero, when the service rendered, the right transferred or the item rented are reused or exploited in Mauritania, pursuant to Article 177 B of the General Tax Code.
The foregoing exemptions in this Article do not cover services actually rendered to Contractor by public Mauritanian administrations and local governmental departments or units.  However, the tariffs levied in such cases on the Contractor, its subcontractors, transporters, customers and agents must be reasonable in relation to the services rendered and must not exceed the tariffs generally applicable for these same services by the same public Mauritanian administrations and local governmental departments or units .    The cost of these services shall be considered recoverable Petroleum Costs in accordance with Article 10.2 of this Contract.
ARTICLE 12 :  PERSONNEL
12.1     From the beginning of the Petroleum Operations, the Contractor undertakes to ensure the employment on a priority basis, with equal qualification, of Mauritanian personnel and to contribute to the training of such personnel, in order to allow their accession to all employment as qualified workers, supervisors, management, engineers and directors.
To this end, the Contractor shall establish in agreement with the Ministry at the end of each Calendar Year, a recruitment plan of Mauritanian personnel and a plan for training and skills improvement in order to attain a greater and greater participation of Mauritanian personnel in the Petroleum Operations.
12.2     The Contractor must also contribute to the training and skills improvement of the agents of the Ministry and to the other purposes referred to in Article 80 of the Crude Hydrocarbons Code, according to a plan established by the Ministry at the end of each Calendar Year.
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To this end, the Contractor shall pay to the State, for said training and job skills improvement plan, an amount of three hundred thousand Dollars ($300,000) per Calendar Year during the validity of the Exploration Authorization, and, starting from the granting of an Exploitation Authorization, an amount of six hundred thousand Dollars ($600,000) per Calendar Year. The above-cited payments shall be considered to be nonrecoverable Petroleum Costs with respect to the provisions of Article 10.2 here above but as deductible charges on the Industrial and Commercial Income Tax in conformity with Article 82 of the Crude Hydrocarbons Code.
ARTICLE 13 : BONUSES
13.1     The Contractor shall pay to the State a signature bonus in the amount of four million Dollars ($4,000,000) within the thirty (30) days following the Effective Date.
13.2     Moreover, the Contractor shall pay to the State the following production bonuses:
a)   six million Dollars ($6,000,000) when the regular commercial production of Hydrocarbons extracted from the Exploitation Perimeter(s) reaches for the first time an average rate equal to twenty-five thousand (25,000) Barrels of Crude Petroleum per day during a period of thirty (30) consecutive days;
b)   eight million Dollars ($8,000,000) when the regular commercial production of Hydrocarbons extracted from the Exploitation Perimeter(s) reaches for the first time an average rate equal to fifty thousand (50,000) Barrels of Crude Petroleum per day for a period of thirty (30) consecutive days;
c)   tweleve million Dollars ($12,000,000) when the regular commercial production of Hydrocarbons extracted from the Exploitation Perimeter(s) reaches for the first time an average rate equal to one hundred thousand (100,000) Barrels of Crude Petroleum per day for a period of thirty (30) consecutive days ;
d)   twenty million Dollars ($20,000,000) when the regular commercial production of Hydrocarbons extracted from the Exploitation Perimeter(s) reaches for the first time an average rate equal to one hundred fifty thousand (150,000) Barrels of Crude Petroleum per day for a period of thirty (30) consecutive days.
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Each of the sums referred to in paragraphs a), b), c) and d) here above shall be paid within the thirty (30) days following the above-cited period of reference.
13.3     The sums referred to in Articles 13.1 and 13.2 here above shall not be considered as recoverable Petroleum Costs with respect to the provisions of Article 10.2 here above, nor considered to be deductible charges for the determination of the Industrial and Commercial Income Tax  pursuant to Article 79 of the Crude Hydrocarbons Code.
ARTICLE 14 : PRICE AND MEASUREMENT OF HYDROCARBONS
14.1     The unitary market price of the Crude Petroleum used in consideration for purposes of Articles 10 and 11 here above shall be the “Market Price” F.O.B. the Delivery Point, expressed in Dollars per Barrel, as determined here below for each Quarter.
A Market Price shall be established for each type of Crude Petroleum or blend of Crude Petroleums.
14.2    The Market Price applicable to Crude Petroleum lifted in the course of a Quarter shall be calculated at the end of each Quarter under consideration, and shall be equal to the weighted average of prevailing prices obtained by the Contractor and the State in the course of their sale of Crude Petroleum to Third Parties in the course of the Quarter under consideration, adjusted as appropriate to reflect differentials in quality and density, and on the terms of F.O.B. delivery and payment terms provided the quantity sold in such manner to Third Parties in the course of the Quarter under consideration corresponds to no less than thirty percent (30%) of the total of the volumes of Crude Petroleum extracted from the Exploitation Perimeters existing under this Contract, taken as a whole, and sold in the course of the said Quarter.
14.3     If such Third Party sales do not take place during the Quarter under consideration, or if they constitute less than thirty percent of the total of the quantities of Crude Petroleum of the Exploitation Perimeter granted under the present Contract taken as a whole and sold in the course of the said Quarter, the Market Price shall be arrived at by comparison with the « Current International Market Price » for the Quarter under consideration of the qualities of Crude Petroleum produced in Mauritania and in neighboring producing countries, taking into account differentials of quality, density, transport and terms of payment.
« Current International Market Price »  shall be a reference price based on Dated Brent prices, as such are published in “Platt’s Crude Oil Marketwire” or similar internationally recognized
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publication, averaged for the month(s) during which sales were made and adjusted for differences in quality, API  gravity, terms of FOB delivery and payment terms.  If Dated Brent is replaced by another internationally recognized reference crude, the published quotes of the replacement crude shall be used instead.
14.4     In particular the following transactions are not taken into account in calculating the Market Price of the Crude Petroleum:
a)   Sales in which the buyer is an Affiliated Company of the seller as well as sales between entities making up the Contractor;
b)   Sales which include some consideration other than payment in freely-convertible currency or sales attributable in whole or in part to motivations other than the usual economic incentives attached to sales of Crude Petroleum on the international market (such as barter contracts, sales from government to government or to governmental units).
14.5     A committee presided over by the Minister or his delegate and including other representatives of the State and those of the Contractor shall meet at the request of its president, at the end of each Quarter, to establish, according to the stipulations of this Article 14, the Market Price of the Crude Petroleum produced, applicable to the Quarter elapsed. The decisions of the committee shall be by unanimous vote.
If no agreement can be reached by the committee on a decision within a time period of thirty (30) days after the end of the relevant Quarter, the Market Price of the Crude Petroleum produced shall be definitively determined by an expert of international reputation, appointed by agreement of the Parties, or, if such agreement is not reached, by the International Centre for Expertise of the International Chamber of Commerce.  The expert shall establish the price according to the stipulations of this Article 14 within a time period of twenty (20) days after his appointment.  The costs of expertise shall be shared equally between the Parties.
14.6     While awaiting the determination of the price, the Market Price provisionally applicable to a Quarter shall be the Market Price of the preceding Quarter.  Any necessary adjustment shall be made not later than thirty (30) days after the determination of the Market Price for the Quarter under consideration.
14.7     The Contractor shall measure all the Hydrocarbons produced after extraction of water and connected substances, in utilizing, with the consent of the Ministry, the instruments and procedures in conformity with the methods in force in the international petroleum industry.  The Ministry shall have the right to examine such measures and to check the instruments and
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procedures utilized.
If during the course of exploitation the Contractor wishes to modify such instruments and procedures, he must obtain the prior consent of the Ministry.
If, during the course of an inspection carried out by the Ministry, it is verified that the measuring instruments are inaccurate and exceed the acceptable tolerances, and that this condition of fact is confirmed by an independent expert, the inaccuracy in question shall be considered as having existed for half of the period since the preceding inspection, unless a different period is demonstrated.  The accounting of the Petroleum Costs and the shares of production and liftings of the Parties shall be the subject of appropriate adjustments within thirty (30) days following receipt of the expert’s report.
14.8     For Dry Gas, the provisions of this Article 14 shall apply mutatis mutandis, subject to the provisions of Article 15 here below.
ARTICLE 15 :  NATURAL GAS
Non-Associated Natural Gas
15.1     In the case where a discovery referred to in Article 9.1 here above concerns a deposit of Non-Associated Natural Gas which the Contractor has undertaken to appraise pursuant to Article 9.2 here above, the Minister and the Contractor shall jointly carry out, in parallel with the appraisal works of the discovery in question, a market study intended to evaluate the possible market outlets for such Natural Gas, both on the local and the export markets, as well as the means necessary for its marketing, and shall consider the possibility of a joint marketing of their shares of production.  The study shall in particular determine the quantities for which sale on the local market can be assured as a fuel or as a raw material, the facilities and arrangements necessary for the sale of such Natural Gas to the utilizing enterprises or to the entity of the State in charge of its distribution, as well as the discounted price which shall be determined pursuant to the principles set forth in Article 15.8 here below.
For purposes of evaluating the commercial value of the discovery of the Non-Associated Natural Gas, the Contractor shall have the right pursuant to Article 3.4 here above to an extension of his Exploration Authorization.
If following the appraisal of a discovery of Non-Associated Natural Gas, it is shown that the development requires specific economic terms in order to make it economically viable in the opinion of each of the two Parties, the Parties may agree, on an exceptional basis, on said terms.
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15.2     At the end of appraisal works, in the case where the Parties should decide to jointly exploit such Natural Gas in order to supply the local market, or in the case where the Contractor should decide to exploit it for export, the latter shall submit, prior to the end of the Exploration Authorization, an application for an Exploitation Authorization which the Minister shall grant within the terms set forth in Article 9.6 here above.
The Contractor shall then proceed with the development and the production of such Natural Gas pursuant to the development and production program submitted to the Minister and approved by the latter within the terms provided for in Article 9.5.  The provisions of this Contract applicable to Crude Petroleum shall apply  mutatis mutandis  to the Natural Gas, subject to the special provisions provided for in Articles 15.7 to 15.9 here below.
In the case where the production is intended in whole or in part for the local market, a supply contract shall be entered into, under the supervision of the Minister, between the Contractor and the enterprise of the State responsible for the distribution of the gas.  The Contract shall define the obligations of the parties in the matter of delivery and lifting of the commercial gas and may contain a clause obligating the purchaser to pay a portion of the price in the event of a default in the lifting of the contractual quantities.
15.3     If an appraisal program or application for an Exploitation Authorization has not been submitted within the time periods allowed for in Articles 9.2 and 9.5 here above, the surface comprising the extent of the deposit of Non-Associated Natural Gas shall be, upon the request of the Minister, relinquished to the State, which shall be able to undertake for its own account all works of placement into exploitation of the deposit in question.
Associated Natural Gas
15.4     In the event of a discovery of a commercially exploitable deposit of Crude Petroleum containing Associated Natural Gas, the Contractor shall indicate in the report provided for in Article 9.3 here above whether he considers that the production of such Associated Natural Gas is likely to exceed the quantities necessary for the purposes of Petroleum Operations relative to the production of Crude Petroleum, including therein the operations of reinjection, and whether it considers that such excess is likely to be produced in marketable quantities.  In the case where the Contractor will have advised the Minister of such an excess amount, the Parties shall jointly evaluate the possible markets for such excess amount, both on the local and the export markets, including therein the possibility of a joint marketing of their shares of production of such excess
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amount as well as the means necessary for its marketing.
In the case where the Parties should agree to exploit the excess amount of the Associated Natural Gas, or in the case where the Contractor should decide to exploit such amount for export, the Contractor shall indicate in the development and production program referred to in Article 9.5 here above the additional facilities necessary for the development and exploitation of such excess amount and his estimate of the costs pertaining thereto.
The Contractor must then proceed with the development and the exploitation of such excess amount pursuant to the development and production program submitted and approved by the Minister within the terms set forth in Article 9.5 here above, and the provisions of this Contract applicable to the Crude Petroleum shall apply  mutatis mutandis to the excess quantity of Natural Gas, subject to the special provisions set forth in Articles 15.7 to 15.9 here below.
A similar procedure to that described in the paragraph here above shall be followed if the marketing of the Associated Natural Gas is decided upon during the course of the exploitation of a deposit.
15.5     In the case where the Contractor should decide not to exploit the excess amount of Associated Natural Gas and if the State should at any time desire to utilize it, the Minister shall so advise the Contractor, in which case:
a)   The Contractor shall freely place at the disposal of the State all or a portion of the excess amount which the State desires to lift, at the exit point of the separation facilities;
b)   The State shall be responsible for the collection, the processing, compression and transport of such excess amount from the above-mentioned separation facilities, and shall bear all additional costs pertaining thereto;
c)   The construction of the facilities necessary for the operations referred to in paragraph b) here above, as well as the lifting of the excess amount by the State, shall be accomplished pursuant to good oilfield practices in the international petroleum industry and in such a manner so as not to impede production, lifting and transport of the Crude Petroleum by the Contractor.
15.6     Any excess amount of Associated Natural Gas which is not utilized within the framework of Articles 15.4 and 15.5 here above must be reinjected by the Contractor, unless Contractor technically demonstrates that such reinjection would result in a reduction of maximum oil recovery, in which case Contactor shall be authorized to flare said excess and shall be subject to
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the penalty provided for in Article 6.4.
Common Provisions
15.7     The Contractor shall have the right to dispose of his share of production of Natural Gas, pursuant to the provisions of this Contract. He shall also have the right to proceed with the separation of liquids of all Natural Gas produced, and to transport, store, as well as to sell on the local or export market his share of the liquid Hydrocarbons thus separated, which Hydrocarbons shall be considered as Crude Petroleum for purposes of their sharing between the Parties according to Article 10 here above.
15.8     For purposes of this Contract, the Market Price of the Natural Gas, expressed in Dollars per million of BTU, shall be equal:
a)   To the price obtained from buyers with regard to export sales of Natural Gas to Third Parties;
b)   With regard to sales on the local market of the Natural Gas as a fuel, to a price to be mutually agreed upon between the Minister or the national entity in charge of the distribution of gas on the local market, and the Contractor, on the basis in particular of the market rate of a fuel substitute for Natural Gas.
15.9     For purposes of the application of Articles 10.2, 10.3 and 13.2  here above, the quantities of Natural Gas available after deduction of quantities reinjected, flared and those utilized for purposes of the Petroleum Operations shall be expressed in number of Barrels of Crude Petroleum such that one hundred sixty-five (165) cubic meters of Natural Gas measured at a temperature of 15.6°C and at an atmospheric pressure of 1.01325 bars are deemed to be equal to one (1) Barrel of Crude Petroleum, except as otherwise agreed between the Parties.
ARTICLE 16 : TRANSPORT OF HYDROCARBONS BY PIPELINES
16.1     The Contractor shall have the right, for the validity term of the Contract and within the terms defined in Title V of the Crude Hydrocarbons Code, to process and transport within its own facilities inside of the territory of Mauritania and to cause to be processed and transported, while retaining ownership, the products resulting from its exploitation activities or its share of such products, to points of storage, processing, lifting, or gross consumption.
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16.2     In the case where agreements having as their purpose to permit or to facilitate transport by pipelines of Hydrocarbons through other states should come to be agreed upon between such states and the Mauritanian State, the latter shall grant to the Contractor without discrimination all the benefits which could result from the execution of such agreements..
16.3     Within the framework of its transport operations, the Contractor shall benefit from the rights and shall be subject to the obligations provided for in Title V of the Crude Hydrocarbons Code.
ARTICLE 17 : OBLIGATION FOR SUPPLYING THE DOMESTIC MARKET
17.1     The Contractor has the obligation of participating in meeting the needs of domestic consumption of Hydrocarbons, except for exports of petroleum products, pursuant to the provisions of Article 41 of the Crude Hydrocarbons Code.
17.2     The Minister shall notify the Contractor in writing, not later than the 1st of October of each Calendar Year, the quantities of Hydrocarbons which the State chooses to purchase pursuant to this Article, during the course of the following Calendar Year.  The deliveries shall be made, to the State or to the person designated by the Minister, by quantities and at regular time intervals during the course of said Year, according to terms set by agreement of the parties.
17.3     The price of the Hydrocarbons so sold by the Contractor to the State shall be the Market Price established according to the provisions of Articles 14 and 15.8 here above; it shall be payable to the Contractor in Dollars within sixty (60) days from the date of delivery.  A sales contract shall be entered into between the State and the Contractor which shall establish payment procedures and pertaining guarantees.
ARTICLE 18 : IMPORTATION AND EXPORTATION
18.1     The Contractor shall have the right to import into Mauritania, for its account or for that of its subcontractors, all merchandise, materials, machines, equipment, spare parts and consumable materials necessary for the proper execution of Petroleum Operations and specified in a customs list established by the Ministry, upon the proposal of the Contractor, pursuant to Article 92 of the Crude Hydrocarbons Code.
It is understood that the Contractor and his subcontractors undertake to proceed with the importing defined here above only to the extent that said materials and equipment are not
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available in Mauritania upon equivalent conditions in terms of price, quantity, quality, terms of payment and time period for delivery.
18.2     The imports and re-exports of the Contractor and of his subcontractors are subject to the customs regime set forth in Articles 90 to 96 of the Crude Hydrocarbons Code.
18.3     The Contractor, his clients and their transporters shall have, for the duration of the Contract, the right to freely export at the point of exportation chosen for such purpose, free of all customs duties and taxes and at any time whatsoeverand pursuant to the provisions of the Crude Hydrocarbons Code, the portion of Hydrocarbons to which the Contractor is entitled according to the provisions of the Contract, after deduction of all deliveries made to the State pursuant to Article 17. However, the Contractor undertakes, at the request of the State, not to sell the Hydrocarbons produced in Mauritania to countries declared hostile to the State.
ARTICLE 19 :  FOREIGN EXCHANGE
19.1     The Contractor shall benefit from the rights and is subject to the obligations provided for in Title VII of the Crude Hydrocarbons Code in matters of control of foreign exchange and of protection of investments.
ARTICLE 20 :  BOOK-KEEPING, MONETARY UNIT, ACCOUNTING
20.1     The records and books of account of the Contractor shall be kept according to the accounting rules generally utilized in the international petroleum industry, pursuant to the regulations in force and with the Accounting Procedure defined in Appendix 2 of this Contract.
20.2     The records and books of account shall be kept in the English language and denominated in Dollars. They shall be fully supported by detailed documentation proving the expenses and receipts of the Contractor with respect to this Contract.
Such records and books of account shall be utilized in particular to determine Petroleum Costs, and the net profits of the Contractor subject to the Industrial and Commercial Income Tax pursuant to Articles 66  et seq  of the Crude Hydrocarbons Code. They must contain the accounts of the Contractor highlighting the sales of Hydrocarbons under the terms of this Contract.
For informational purposes, the accounting of profits and balance sheets shall be kept in Ouguiyas.
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20.3    The originals of the records and accounting books referred to in Article 20.1 here above can be kept at the central headquarters of the Contractor, up until the Contractor is granted the first Exploitation Authorization, with at least one copy in Mauritania. Starting from the month during the course of which such Exploitation Authorization is granted to the Contractor, the originals of said records and accounting books as well as the supporting documents pertaining thereto shall be kept in Mauritania.
20.4    The Minister, after having informed the Contractor in writing, may cause to have the records and books of account relative to the Petroleum Operations examined and verified by auditors of his choice or by his own agents, according to the terms specified in the Accounting Procedure.  He shall have a period of three (3) years following the end of a given Calendar Year to carry out the examinations or verifications concerning said Calendar Year and present to the Contractor his objections for any contradictions or errors noted at the time of such examinations or verifications.  The Parties may agree to extend this time period by one additional year if special circumstances so justify it.
For Petroleum Costs incurred before the first year of production of Hydrocarbons, the time period of verification and of rectification is extended to the end of the second Calendar Year following the Calendar Year during which the first lifting of Hydrocarbons takes place.
The Contractor is required to furnish all necessary assistance to persons appointed by the Minister for this purpose and to facilitate the services they are rendering.  The reasonable expenses for examination and of verification shall be reimbursed to the State by the Contractor and shall be considered to be recoverable Petroleum Costs according to the provisions of Article 10.2 here above.
20.5     The sums due to the State or to the Contractor shall be payable in Dollars or in a convertible currency chosen by common agreement between the Parties.
In the event of a delay in payment, the sums due shall bear interest at the LIBOR rate +5% starting from the day that they should have been paid up until their payment, with monthly compounding of interest if the payment is more than thirty (30) days late.
ARTICLE 21 :  PARTICIPATION OF THE STATE
21.1     The State shall acquire on the Effective Date, through the National Enterprise (Société Mauritanienne des Hydrocarbures et de Patrimoine Minier - SMHPM) referred to in Article 6 of the Crude Hydrocarbons Code, a carried interest of ten percent (10%) in the rights and obligations of the Contractor in the Exploration Perimeter.  The entities of the Contractor, other than the National Enterprise, shall finance the share of the latter in all Petroleum Costs corresponding to the exploration Petroleum Operations including
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therein the evaluation/appraisal of discoveries made in the Exploration Perimeter, during the entire duration of the Exploration Authorization which is the subject of Article 3 here above.
Additionally, to assist the National Enterprise with capacity building the Contractor, other than the National Enterprise, will advance to the National Enterprise, for each Calendar Year during the exploration period until first production is achieved from an Exploration Perimeter, an annual amount of two hundred thousand Dollars ($200,000) reimbursable by the National Enterprise in the event there is exploitation from the the Exploration Perimeter.  The Contractor will not be subject to any tax or charge of any nature on account of this reimbursemnet or any gaains resulting therefrom.  The method of reimbursement of these amounts will be specified in the JOA.
The National Enterprise, as an entity of the Contractor, shall benefit on account of and pro rata to its participation from the same rights and benefits and is subject to the same obligations as the other members of the Contractor, subject to the provisions of this Article 21.
21.2     The State shall have the option to acquire, through the National Enterprise, a participation in the Petroleum Operations in any Exploitation Perimeter resulting from the Exploration Perimeter within the limits indicated in Article 21.3 here below.
In such case, the National Enterprise shall be the beneficiary, on account of and pro rata to its participation, of the same rights and subject to the same obligations as those of the Contractor defined in this Contract, subject to the provisions of this Article 21.
In order to avoid any ambiguity, the participation of the State in the Exploration Perimeter shall continue to be carried by the entities of the Contractor pursuant to the provisions of Article 21.1 here above.
21.3     In the case of the exercise by the State of the option of participation in an Exploitation Perimeter mentioned in Article 21.2 here above, such participation may not be less than ten percent (10% ) and may not exceed eighteen percent ( 18%).
21.4     Not later than six (6) months starting from the date of the grant of an Exploitation Authorization, the Minister must notify the Contractor in writing of the decision of the State to exercise its option of participation in specifying the percentage chosen within the limit set forth in Article 21.3 here above.
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Said participation shall take effect starting from the date of receipt of notification of the exercise of the option of the State.
In order to avoid any ambiguity, the State shall have no participation in Petroleum Operations in any Exploitation Perimeter from the Exploration Perimeter if he does not exercise the option mentioned in Article 21.2 here above.
21.5     Starting from the effective date of its participation, which is the subject of Articles 21.2 to 21.4 here above, the State shall finance the Petroleum Costs in the relevant Exploitation Perimeter pro rata to its participation.
The State shall reimburse to the entities of the Contractor, other than the National Enterprise, pursuant to Article 21.6 here below, pro rata to its participation, the Petroleum Costs not yet recovered relative to said Exploitation Perimeter and incurred since the Effective Date (with the exclusion of exploitation Petroleum Costs (OPEX) and financing costs), up until the date of receipt of notification referred to in Article 21.4 here above.
The Contractor shall not be subject to any tax of any type whatsoever, by reason of such reimbursements or possible added value pertaining thereto.
21.6     The State shall assign and shall continue to assign to the Contractor thirty percent (30%) of the share of production to which it is entitled from its participation and as recovery of Petroleum Costs pursuant to Article 10.2 here above and the Accounting Procedure constituting Appendix 2, until the cumulative value of such transfers or reimbursements, appraised according to the provisions of Articles 14 and 15 here above, is equal to one hundred fifteen percent (115%) of the Petroleum Costs prior to the Effective Date of the participation and referred to in the second paragraph of Article 21.5 here above.
21.7     In order to remove any ambiguity, the reimbursement of the exploration Petroleum Costs stipulated in Articles 21.5 and 21 .6 here above, does not in any way include the sums paid by the Contractor with respect to Article 13 of this Contract.
21.8     The reimbursements which will be made by the State with respect to the provisions of Articles 21.5 and 21.6 here above, shall be paid in kind by the State which shall transfer to the entities of the Contractor, other than the National Enterprise, each Quarter at the Delivery Point the percentage of its quarterly share of production of Hydrocarbons
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stipulated in said Articles.
However, the State reserves the option to make said reimbursements in Dollars for which the payment in full must take place within a time period of ninety (90) days starting from the effective date of the participation referred to in Article 21.4 here above.
In the event that the payment of all said reimbursements within the time periods provided here above does not take place, the reimbursement in kind such as referred to in Articles 21.5 and 21.6 here above shall apply.
21.9     The practical methods of participation of the State stipulated in Article 21.1 here above as well as the rules and obligations of the entities of the Contractor, including therein the National Enterprise, shall be determined in an association contract (JOA), substantially conforming to the AIPN model JOA, which shall be entered into between these entities and shall enter into force not later than ninety (90) days starting from the Effective Date.  Said association contract (JOA) shall be amended as necessary and in particular to take into account, if applicable, the exercise by the State of its participation, which is the subject of Article 21.2 here above.
21.10   The National Enterprise, on the one hand, and the other entities making up the Contractor on the other hand, shall not be jointly and severally liable for the obligations resulting from this Contract vis-a-vis the State. The National Enterprise shall be individually responsible vis-à-vis the State for its obligations such as provided in this Contract.  Any default of the National Enterprise to execute any of its obligations shall not be considered as a default of the other entities making up the Contractor and shall in no event be invoked by the State in order to cancel this Contract. The association of the National Enterprise to the Contractor, shall not under any circumstance cause void nor affect the rights of the other entities constituting the Contractor to have recourse to the arbitration clause provided in Article 28 here below.
ARTICLE 22 :  ASSIGNMENT
22.1     The rights and obligations resulting from this Contract may not be assigned to a Third Party, wholly or in part, by any of the entities making up the Contractor, without the prior approval of the Minister.
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If within the three (3) months following notification to the Minister of a proposed assignment accompanied by the necessary information to prove the technical and financial means of the assignee as well as the terms and conditions of assignment, the Minister has not given notice of his opposition with reasonable justification, such assignment shall be deemed to have been approved by the Minister.
Starting from the date of approval, the assignee shall acquire the status of a member of the Contractor and must satisfy the obligations imposed upon the Contractor by this Contract.
Each of the entities making up the Contractor may freely and at any time assign all or a portion of its interests under the Contract to an Affiliated Company or to another entity of the Contractor provided that the Minister is notified beforehand.
22.2     Likewise, the Contractor, or any entity of the Contractor, shall be required to submit for prior approval of the Minister:
a)   Any plan which would be likely to lead, in particular through a new allocation of capital stock, to a change of the direct control of the Contractor or of an entity comprising the Contractor. In particular the following shall be considered as elements of control of the Contractor, or of an entity comprising the Contractor:  a change in the allocation of capital stock, the nationality of the majority shareholders, as well as the statutory provisions relative to the registered office and the rights and obligations attached to the company shares with respect to the majority required at the shareholder meetings.  However, the transfers of company shares to Affiliated Companies may be freely made subject to prior declaration to the Minister for information and application of the provisions of Article 24.4 here below, if applicable.  As for transfer of company shares to Third Parties, transfers shall not be subject to the approval of the Minister unless they result in the transfer of greater than thirty percent (30%) of the capital of the enterprise.
b)   Any plan to pledge as security property and facilities earmarked for Petroleum Operations.
The plans referred to in paragraphs a) and b) shall be notified to the Minister.  If within a time period of three (3) months, the Minister has not notified the Contractor or one of the entities in question of his opposition with reasonable justification to said plans, the plans shall be deemed approved.
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22.3     When the Contractor is made up of several entities, it shall furnish to the Minister, within the month following its signature, a copy of the association agreement (JOA) binding the entities and of all modifications which could be made to said agreement, in specifying the name of the enterprise appointed as Operator for the Petroleum Operations. Any change of Operator shall be submitted to the approval of the Minister, pursuant to the provisions of Article 6.2 here above.
22.4     The transfers made in violation of the provisions of this Article 22 shall be null and void.
ARTICLE 23 : OWNERSHIP, USAGE AND ABANDONMENT OF PROPERTY
23.1    The Contractor shall be the owner of property, moveable and immoveable, which he will have acquired for purposes of the Petroleum Operations, and shall retain the full usage thereof, as well as the right to export them or to transfer them to Third Parties during the entire term of the Contract, provided that the State may acquire for free, at the request of the Minister, all or a portion of the property belonging to the Contractor which will have been utilized for the Petroleum Operations and for which the acquisition costs will have been fully recovered pursuant to Article 10 here above in the following cases:
a)   Upon expiration, surrender or termination of this Contract ;
b)   In the event of surrender or of expiration of an Exploitation Authorization, with regard to the works and facilities situated in the Exploitation Perimeter and the equipment earmarked exclusively for Petroleum Operations in the Exploitation Perimeter in question, unless the Contractor wishes to utilize such property for the Petroleum Operations in other Exploitation Perimeters resulting from the Exploration Perimeter.
23.2     Upon the expiration, surrender or termination of any Exploitation Authorization, the Contractor must proceed with all operations necessary to rehabilitate its original condition in conformity with a Remediation Plan drawn up and financed within the following terms:
a)   No less than ninety (90) days after the commencement of commercial production pursaunt to an  approved development program for a deposit, the Contractor shall prepare and submit to the Minister for approval a Remediation Plan of the site, in conformity with good oilfield practices of the international petroleum industry, which he proposes to carry out at the end of production operations, as well as the corresponding budget.  Each Calendar Year the Contractor shall incorporate into the Remediation Plan the necessary revisions to take into account the changes of technical and financial parameters. The revised
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Remediation Plan shall become the new Remediation Plan which shall be taken into account for the calculation of the payments on the sequestered account ;
b)   The Remediation Plan shall include a detailed description of the works of removal and/or of securing of infrastructure such as the platforms, the storage facilities, the wells, pipes, gathering lines, etc., necessary for the protection of the environment and of persons;
c)   The Minister may, in consultation with the Minister in charge of the Environment, propose revisions or modifications to the Remediation Plan, notifying the Contractor thereof in writing with all appropriate justifying supporting information, within the ninety (90) days following receipt of said Plan. The provisions of Article 5.2 here above shall apply to said Plan with regard to its adoption.  When the results acquired during the course of exploitation justify changes to the Remediation Plan, said Plan and the corresponding budget may be modified in conformity with the adoption procedure described here before;
d)   For purposes of financing the operations set forth in the Remediation Plan, the Contractor shall open, as of the adoption of this Plan, a sequestered account with a top tier international banking establishment acceptable to the Minister, which he will fund starting from the Quarter following the adoption of the Remediation Plan via annual payments of amounts and according to a schedule, based on an amortization of the unit of production basis or otherwise determined in agreement with the Minister ;
e)   The funds paid into the sequestered account shall be treated as recoverable Petroleum Costs according to the terms set forth in Article 10.2 here above, and shall be considered to be deductible charges for the determination of the tax on industrial and commercial profits.  Such funds, as well as the interest received on the sequestered account, shall be earmarked exclusively for the payment of expenses linked to the operations of the Remediation Plan ;
f)   The Contractor shall notify the Minister, with an advance notice of one hundred eighty (180) days, of his intention to start up the operations set forth in the Remediation Plan, unless the Minister notifies Contractor within thirty (30) days following the above-cited opinion that:
(i) the exploitation of the deposit of the Exploitation Perimeter in question shall be pursued by the State or by a Third Party, or
(ii) the State wishes to retain the facilities for justifiable reasons.
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In the two cases cited in i) and ii) here above, the sequestered account shall be transferred to  the successor responsible party and Contractor is relieved of all liability with regard to the Remediation Plan and the sequestered account pertaining to the deposit in question;
g)   In the case where the expenses necessary for the execution of the Rehabilitation Plan are greater than the amount available in the sequestered account, the excess amount shall be entirely at the expense of the Contractor;
h)   The Contractor shall pay to the State upon completion of Rehabilitation Plan any residual amount of the sequestered account not utilized for the carrying out of the Rehabilitation Plan and which will have been recovered under this Article 10.2 here above.
ARTICLE 24 : LIABILITY AND INSURANCE
24.1     The Contractor shall indemnify and hold harmless any person, including the State, for any damage or loss that the Contractor, his employees or his subcontractors and their employees may cause to the person, property or rights of other persons, by reason of or during Petroleum Operations.
In the event the liability of the State is implicated by reason of or during the course of Petroleum Operations, the Minister must so advise the Contractor, who shall conduct the defense in this regard and shall indemnfiy the State for any sum which the latter is required to pay or any expense pertaining thereto which he has borne or which is incurred subseqent of a claim.
24.2     The Contractor shall obtain and maintain in force, and shall cause his subcontractors to obtain and to maintain in force, all insurance coverages relative to Petroleum Operations of the type and amounts in use in the international petroleum industry, in particular (a) general third party liability coverage, (b) coverage for environmental risks pertaining to the Petroleum Operations, (c) coverage for employee work-related accidents, (d) any other insurance coverage required by the regulations in force.
The insurance coverages in question shall be obtained from top tier insurance companies pursuant to the applicable regulations.
The Contractor shall provide the Minister with certifications proving the obtaining of insurance coverage and the maintenance in force of the above-cited insurance coverages.
24.3     When the Contractor is made up of several entities, the obligations and responsibilities of the latter under this Contract shall be, without prejudice to the provisions of Article 21 here above,
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joint and several with the exception of their obligations pertaining to the Industrial and Commercial Income Tax.
24.4     If one of the entities of the Contractor assigns all or a portion of his rights and obligations in connection with this Contract to an Affiliated Company, whenever the latter displays a lower level of financial and technical qualification, the parent company shall submit for the approval of the Minister a commitment guaranteeing the proper execution of the obligations arising from this Contract.
ARTICLE 25 :  TERMINATION OF THE CONTRACT
25.1     This Contract may be terminated, without compensation, in any of the following cases:
a)   Serious and/or continued violation by the Contractor of the provisions of this Contract, of the Crude Hydrocarbons Code, or of the regulations in force applicable to the Contractor;
b)   Failure to remit a bank guarantee pursuant to Article 4.6 here above; 
c)   Delay of more than three (3) months of a payment due to the State;
d)   Cessation of development works of a deposit for six (6) consecutive months without the consent of the Minister;
e)   After the startup of production on a deposit, cessation of his exploitation for a period of greater than six (6) months, decided upon by the Contractor without the consent of the Minister;
f)   Non-execution by the Contractor within the time period prescribed by an arbitral award rendered pursuant to the provisions of Article 28 here below;
g)   Bankruptcy, receivership or liquidation of the property of the Contractor.
25.2     Except for the case set forth in subparagraph g) here above, the Minister may only pronounce the forfeiture provided for in Article 25.1 here above after having placed the Contractor on notice, by registered letter with return receipt, to remedy the violation in question within the allowed time period specified in the notice from the time of receipt of such.
25.3     If there is a failure by the Contractor to remedy the violation which was the subject of the termination notice within the time period allowed, the termination of this Contract may be pronounced.
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Any dispute as to the justification of the termination of the Contract pronounced by the Minister is open to recourse to arbitration pursuant to the provisions of Article 28 here below. In such a case, the Contract shall remain in force until an arbitral award confirms the justifiability of such termination, in which case the Contract will definitively terminate.
The termination of this Contract shall automatically entail the withdrawal of the Exploration Authorization and of the currently valid Exploitation Authorizations.
ARTICLE 26 : APPLICABLE LAW AND STABILIZATION OF TERMS
26.1     This Contract is governed by the laws and regulations of the Islamic Republic of Mauritania, supplemented by general principles of the laws of international commerce.
26.2     The Contractor shall be subject at all times to the laws and regulations in force in the Islamic Republic of Mauritania.
26.3     No legislative or regulatory provision occurring after the Effective Date of the Contract may be applied to the Contractor which would have as a direct or an indirect effect to diminish the rights of the Contractor or to increase his obligations under this Contract and the legislation and regulations in force upon the Effective Date of this Contract, without the prior agreement of the Parties.
However, it is agreed that the Contractor cannot, with reference to the preceding paragraph, oppose the application of the legislative and regulatory provisions which are generally applicable, adopted after the Effective Date of the Contract, in the matter of safety of persons and of protection of the environment or employment law
ARTICLE 27 :  FORCE MAJEURE
27.1     Any obligation resulting from this Contract which would be totally or partially impossible for a Party to carry out, other than payments for which it is responsible to pay, shall not be considered to be a violation of this Contract if said non-execution results from a case of Force Majeure, provided however that there is a direct link of cause and effect between impediment and the case of Force Majeure invoked.
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27.2     For purposes of this Contract the following should be understood to be a case of Force Majeure :  any event which is unforeseeable, irresistible or outside of the will of the Party invoking it, such as earthquake, accidents, strike, guerilla actions, acts of terrorism, blockade, riot, insurrection, civil unrest, sabotage, acts of war, the Contractor being subject to any law, regulation, or any other cause outside of his control and which has as a result of delaying or rendering momentarily impossible the execution of all or a portion of his obligations.  The intention of the Parties is that the term Force Majeure be given the interpretation the most in conformity with the principles and customs of international law and with the practices of the international petroleum industry.
27.3     When a Party considers itself prevented from carrying out any of its obligations by reason of a case of Force Majeure, it must immediately so notify the other Party in writing specifying the elements of the type to establish the case of Force Majeure and to take, in agreement with the other Party, all appropriate and necessary provisions in order to allow a return to the normal execution of obligations affected by the Force Majeure after the case of Force Majeure ceases.
The obligations, other than those affected by the Force Majeure, must continue to be fulfilled pursuant to the provisions of this Contract.
27.4     If, following a case of Force Majeure, the execution of any of the obligations of this Contract was delayed, the duration of the delay resulting therefrom, increased by the delay which may be necessary for the repair of all damage caused by the case of Force Majeure, shall be added to the time period stipulated in this Contract for the execution of said obligation as well as to the duration of the currently valid Exploration Authorization and of any Exploitation Authorizations.
ARTICLE 28 : ARBITRATION AND EXPERTISE
28.1     In the event of a dispute between the State and the Contractor concerning the interpretation or the application of the provisions of this Contract, the Parties shall make good faith effort to resolve such dispute amicably.
With regard to the Market Price, the provisions of Article 14.5 here above shall apply.
The Parties may also agree to submit any other dispute of a technical nature to an expert appointed by common agreement or by the International Centre for Expertise of the International Chamber of Commerce (“ICC”).
If, within a time period of ninety (90) days starting from the date of notification of a dispute, the Parties are not able to reach an amicable solution or following the proposal of an expert, said dispute shall be submitted at the request of the most diligent Party to the ICC for arbitration
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following the rules set by the Rules of Arbitration of the ICC.
28.2     The location of the arbitration shall be Paris (France). The languages utilized during the proceedings shall be the French and English languages and the applicable law shall be the Mauritanian law, as well as the rules and customs of applicable international law in the matter.
The arbitrational court shall be made up of three (3) arbitrators.  No arbitrator shall be a national of the countries of which the Parties are nationals.
The award of the court is rendered on a definitive and irrevocable basis.  It is binding upon the Parties and is immediately executory.
The expenses of arbitration shall be borne in equal part by the Parties, subject to the decision of the court concerning their allocation.
The Parties formally and without reservation waive any right to attack such award, to impede its recognition and its execution by any means whatsoever.
28.3     The Parties shall conform to any protective measures ordered by the arbitrational court.  Without prejudice to the power of the arbitrational court to recommend protective measures, each Party may solicit provisional or protective measures in application of the pre-arbitration emergency procedure rules of the ICC.
28.4     The introduction of an arbitrational procedure shall entail the suspension of the contractual provisions with respect to the subject of the dispute, but shall leave in place all other rights and obligations of the Parties with respect to this Contract.
28.5     Without prejudice to the provisions of Article 21 here above, the costs and expert fees referred to in Article 28.1 here above shall be borne by the Contractor up until the grant of the first Exploitation Authorization and thereafter half by each of the Parties. Such costs shall be considered as recoverable Petroleum Costs with regard to Article 10 of this Contract.
ARTICLE 29 : TERMS FOR APPLICATION OF THE CONTRACT
29.1     The Parties agree to cooperate in all ways possible in order to achieve the objectives of this Contract.
The State shall facilitate the Contractor in the exercise of his activities in granting to him all permits, authorizations, licenses and access rights necessary for the carrying out of the Petroleum Operations, and in placing at his disposal all appropriate services to said Operations of the Contractor , of his employees and agents on national territory.
Any application for the above-cited permits, authorizations, licenses and rights shall be
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submitted to the Minister who shall transmit it, if applicable to the relevant Ministries and entities, and shall ensure its follow-up.  Such applications may not be refused without a legitimate reason and shall be diligently handled in a manner so as to not unduly delay the Petroleum Operations.
29.2     All notices or other communications related to this Contract must be sent in writing and shall be considered to have been validly made from the time they are, hand delivered against receipt, to the qualified representative of the concerned Party at the place of its principal establishment in Mauritania, or delivered in a stamped envelope, by registered mail with return receipt, or sent by telecopy confirmed by letter, and after confirmation of receipt by the recipient, at the address chosen by them and deemed authentic indicated here below :
For the Ministry :
Department of Crude Hydrocarbons
BP : 4921
Nouakchott- Mauritania
TEL/FAX : +222 524 43 07
For the Contractor :
Kosmos Energy Mauritania
c/o Wilmington Trust
4th Floor, Century Yard
Cricket Square, Hutchins Dr.
Elgin Avenue, George Town
Grand Cayman KY1-1209
Cayman Islands
Telephone       :  +1-345-814-6703
FAX                :  +1-345-527-2105
Attention         :   Andrew Johnson
Email: mauritanianotifications@kosmosenergy.com
With Copy to:
Kosmos Energy Mauritania
c/o Kosmos Energy, LLC.
Attention: General Counsel
8176 Park Lane, Suite 500
Dallas, TX 75231
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Fax:       +1 214-445-9705
Email: KosmosGeneralCounsel@kosmosenergy.com
The notices shall be considered as having been made upon the date of confirmation of the receipt.
29.3     The State and the Contractor may at any time change their authorized representatives or choice of domicile mentioned in Article 29.2 here above, subject to having so notified with an advance notice of at least ten (10) days.
29.4     This Contract may not be modified except by common agreement of the Parties and by the execution of an approved amendment entering into force within the terms provided in Article 30 here below.
29.5     Any waiver by the State of the execution of an obligation of the Contractor must be done in writing and signed by the Minister, and no possible waiver can be considered as a precedent if the State declines to act upon any of its rights which are recognized by this Contract.
29.6     Titles appearing in this Contract are inserted for purposes of convenience and of reference and in no way shall define, nor limit, nor describe the scope or the purpose of the provisions of the Contract.
29.7     Appendices 1, 2 and 3 attached hereto are an integral part of this Contract.  However, in the event of conflict, the provisions of this Contract shall prevail over those of the Appendices.
ARTICLE 30 : ENTRY INTO FORCE
Once signed by the Parties, this Contract shall be approved by decree made in the Council of Ministers and shall enter into force upon the date of publication of the said decree in the Official Journal, said date being designated under the name Effective Date and rendering said Contract binding upon the Parties.
In witness whereof, the Parties have signed this Contract in two (2) original copies.
Nouakchott, on           11 OCT 2016            
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FOR	    	FOR	
 	 	 	
THE ISLAMIC REPUBLIC	 	THE CONTRACTOR	
 	 	 	
OF MAURITANIA	 	 	
 	 	 	
THE MINISTER OF PETROLEUM,	 	PRESIDENT DIRECTEUR GENERAL	
 	 	 	
ENERGY AND MINES	 	KOSMOS ENERGY MAURITANIA	
 	 	 	
/s/ Mohamed Abdel Vetah	 	/s/ Andrew G. Inglis	
Mohamed ABDEL VETAH	 	Andrew G. INGLIS	
 
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APPENDIX 1 : EXPLORATION PERIMETER
Attached and being an integral part of the Contract between the Islamic Republic of Mauritania and the Contractor.
On the Effective Date, the initial Exploration Perimeter includes a surface area deemed to be equal to four thousand three hundred (4,300) km²,
Such Exploration Perimeter is represented on the attached map with the indicated coordinates.
MAP OF THE EXPLORATION PERIMETER
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APPENDIX 2 : ACCOUNTING PROCEDURE
Attached to and an integral part of the Contract between the Islamic Republic of Mauritania and Contractor.
ARTICLE 1:  GENERAL PROVISIONS
1.1       Purpose
The purpose of this Accounting Procedure is to set the rules and methods of accounting for the verification of Petroleum Costs to provide for their recovery and for the purpose of sharing production in accordance with Article 10 of the Contract, as well as the rules to determine net profits of the Contractor for purposes of calculating the tax on industrial and commercial profits.
1.2       Statements
The accounts, books and registers of the Contractor shall be maintained consistent with the rules of the applicable accounting plan in Mauritania and the practices and methods in use in the international petroleum industry.
Pursuant to the provisions of Article 20.2 of the Contract, the accounts, books and registers of the Contractor shall be kept in the English language using the Dollar as the unit of account.
Anytime, whenever it is necessary to convert into Dollars expenses and revenue paid or received in any other currency, these currencies shall be valued on the basis of the rate of exchange quoted on the foreign-exchange market of Paris, in accordance with terms determined by mutual agreement.
1.3       Interpretation
The definitions of words which appear in this Appendix 2 are the same as those of the corresponding words as they appear in the Contract.
The word « Contractor », has the meaning given to it by the Contract, and may sometimes refer to the Operator when the Contractor is made up of several entities and when Petroleum Operations are conducted by the Operator on behalf of all these entities, or sometimes the reference is to each of these entities whenever the obligation of each individual entity is being addressed.
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ARTICLE 2:  ACCOUNTING FOR PETROLEUM COSTS
2.1       General rules and principles.  Classes and groupings
2.1.1    The Contractor shall at all times keep books of account specially reserved and organized for the booking of Petroleum Costs ; they shall detail the expenses actually incurred by it and giving rise to recovery consistent with the provisions of the Contract and of this Appendix, the recovered Petroleum Costs, progressively as the production intended for such purpose becomes available, as well as the amounts which must be properly deducted or which have the effect of reducing  the Petroleum Costs.
2.1.2    The accounting of Petroleum Costs must highlight at all times and for each Exploration Perimeter and for each Exploitation Perimeter derived therefrom :
 	§	 	The full amount of the Petroleum Costs paid by Contractor from Effective Date;	

 	§	 	The full amount of the Petroleum Costs recovered;	

 	§	 	The amounts which diminish or otherwise are a deduction from Petroleum Costs and the type of operations related to these amounts;	

 	§	 	The balance of Petroleum Costs not yet recovered.	
2.1.3    The accounting for Petroleum Costs shall comprise as debit entries all expenses actually incurred and directly related to Petroleum Operations in accordance with the Contract and the provisions of this Appendix, and considered chargeable to Petroleum Costs.
These expenses which have been actually incurred must:
 	§	 	Be actually incurred by Contractor ;	

 	§	 	Be necessary to the proper carrying out of Petroleum Operations ;	

 	§	 	Be properly incurred and supported by items and documents which allow an effective audit by the Ministry.	
2.1.4    The accounting for Petroleum Costs shall include as credit entries the amount of recovered Petroleum Costs as and when this recovery takes place, and as and when the amounts are collected, the revenue and miscellaneous products which are to be deducted from or operate to diminish the Petroleum Costs.
2.1.5    The original text of contracts, invoices and other documents which support the Petroleum Costs must be available for examination by the Ministry and produced whenever it requests it.
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2.1.6       Petroleum Costs are recovered in accordance with the following:
a)       The priority order arranged by the type of costs:
 	§	 	Exploitation Petroleum Costs ;	

 	§	 	Development Petroleum Costs ;	

 	§	 	Exploration Petroleum Costs;	
As these categories of Petroleum Costs are defined in Articles 3.2, 3.3 and 3.4 of this Appendix.
b)       Priority based on geographic considerations:
 	§	 	Petroleum Costs incurred in an Exploitation Perimeter shall be the first to be recovered from the production extracted from that perimeter consistent with the order of priorities stipulated in paragraph a) here above ;	

 	§	 	Petroleum Costs incurred outside of an Exploitation Perimeter shall be recovered in second priority from the production extracted from that perimeter consistent with the priority order specified in paragraph a) here above.	
Petroleum Costs incurred in the Exploitation Perimeters, other than that in question shall be recovered before the Petroleum Costs incurred in the Exploration Perimeter and in accordance with the order of priority stipulated in subparagraph a) here above.
Each entity which makes up the Contractor is entitled to its cost recovery upon commencement of production.
2.1.7     Accounting for Petroleum Costs must be true and accurate ; it must be organized and the books must be kept and submitted in such manner that they can be easily grouped together and make the relevant Petroleum Costs clearly apparent, in particular as they relate to the following expenses:
 	§	 	exploration	

 	§	 	appraisal	

 	§	 	development	

 	§	 	production of Crude Petroleum,	

 	§	 	production of Natural Gas,	
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 	§	 	transportation of Hydrocarbons and storage thereof,	

 	§	 	ancillary activities, auxiliary or subordinate, and separate from them,	

 	§	 	as well as the amounts paid in the sequestered account in accordance with Article 23.2 of the Contract.	
2.1.8    For each of the activities here above listed, the accounting of Petroleum Costs must clearly show the following expenses:
a)   Related to tangible assets, in particular those which refer to the purchase, creation, construction or carrying out of:
 	§	 	land parcels,	

 	§	 	buildings (workshops, offices, storage areas, dwellings, laboratories, etc....),	

 	§	 	facilities for loading and storage,	

 	§	 	access roads and general infrastructure works,	

 	§	 	facilities to transport Hydrocarbons (pipelines, tankers, etc.),	

 	§	 	general equipment,	

 	§	 	specific equipment and facilities,	

 	§	 	vehicles for use of transport and civil engineering machinery,	

 	§	 	materiel and tools (the normal useful life of which exceeds one year),	

 	§	 	successful drilling,	

 	§	 	other tangible assets.	
b)   Related to intangible assets, particularly those which relate to:
 	§	 	Surface investigation of geological or geophysical nature and related to laboratory work (studies, reprocessing, etc.),	

 	§	 	Nonproductive exploration wells which are not utilized in furtherance of the development plan,	

 	§	 	Other intangible assets.	
c)   Related to raw materials consumables;
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d)   Operational for functioning expenses :
Involved here are expenses of whatever nature, excepting the overhead referred to below, and which are not accounted for in subparagraphs a) to c) above of this Article 2.1.8, and which are directly connected to the study, progress and the implementation of Petroleum Operations ;
e)   Non operating expenses or overhead :
Involved here are expenses borne by the Contractor related to Petroleum Operations and connected to management or to administration of the said operations.
2.1.9    Moreover, the accounting of Petroleum Costs must show, for each category of expenses listed or defined in subparagraphs a) to d) of Article 2-1-8 above, all payments made to the following:
 	§	 	The Operator, for goods and services which it has itself furnished;	

 	§	 	For the entities which make up the Contractor, the goods and services which they have supplied themselves;	

 	§	 	Affiliated Companies;	

 	§	 	Third Parties.	
2.2       Analysis of expenses and methodology for attribution
2.2.1    The principles for attribution and the usual analytical methods of the Contractor in the matter of itemizing and of reintegrating must be applied in a homogeneous manner, which is fair and does not discriminate against its activities taken as a whole. They must be submitted to the Ministry on its request.
The Contractor must inform Ministry of any change made by it in its principles and methodology.
2.2.2    Tangible assets constructed, manufactured, created or brought about by the Contractor in the furtherance of Petroleum Operations and dedicated to these operations as well as their normal maintenance shall be accounted for at the acquisition cost of construction, manufacturing, creation, or realization.
2.2.3    Equipment, materials and consumables required for Petroleum Operations and not including those referred to above shall be:
a)   Either acquired for immediate use, subject to the time spent in transport, and if necessary, the temporary storage by Contractor (provided they shall not have been
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commingled with his own inventory). This equipment, materials and consumables acquired by the Contractor shall be valued, for their charging Petroleum Costs, at their landed price in Mauritania.
“The Landed price in Mauritania”  includes the following items, which shall be accounted for in accordance with the analytic methodology of Contractor:
 	§	 	Purchase price less discounts and rebates,	

 	§	 	Transport costs, insurance, transit costs, handling and customs (and other possible taxes and fees) from the storage site of the vendor to that of the Contractor or to the place they are utilized, as may be applicable,	
b)   Or supplied by the Contractor from its own inventory
 	§	 	New equipment and materials other than consumables, supplied by the Contractor from its own inventory, shall be valued for accounting purposes at the  weighted purchase price calculated pursuant to the provisions of subparagraph a) of this Article 2.2.3, hereafter  « net cost ».	

 	§	 	Materials and equipment which are depreciable and already used supplied by the Contractor from his own inventory or which originate from other activities he may have had, including those of Affiliated Companies, shall be valued for purposes of booking Petroleum Costs, in accordance with the following schedule:	

 	·	 	New Material (Condition « A »): New Material, never used : 100% (one hundred percent) of the net cost.	

 	·	 	Material in good condition (Condition « B »): Material in good condition and still utilizable for its original purpose without repair: 75% (seventy-five percent) of the net cost of the new material as defined here above.	

 	·	 	Other used material  (Condition  « C »): Material which is still utilizable for its original purpose, but only after repair and upgrading: 50% (fifty percent) of the  net cost of the new material as defined here above.	

 	·	 	Material in poor condition (Condition « D »): Material not utilizable for its original purpose but still usable for another purpose: 25% (twenty-five percent) of net cost of the new material as defined here above.	
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 	·	 	Junk and scrap (Condition « E »): Materials unusable and not repairable: applicable price for junk.	
2.2.3.1 The Operator does not guarantee the quality of the new material referred to above beyond the warranty furnished by the manufacturer or seller of the subject material.  In the event of defective new material, Contractor will do its best to seek reimbursement or compensation from the manufacturer or the reseller; however, the corresponding credit shall only be booked after receipt of reimbursement for indemnification;
2.2.3.2 In the event used material referred to above is defective, the Contractor shall credit the account of the Petroleum Costs with the amount which it will have actually received as compensation.
2.2.3.3 Utilization of materials, equipment and facilities which are Contractor’s own property
Materials, equipment and facilities which are Contractor’s own property and which are temporarily put into use to carry out Petroleum Operations, shall be charged to Petroleum Costs at a rental amount covering the following:
a)   Maintenance and repairs,
b)   A share of depreciation pro rata to the time period utilized for Petroleum Operations, calculated by applying to the original costs (initial cost before revaluation), a rate which shall not exceed the one provided by Article 4.2 here below.
c)   The expenses of transport and operations and all other expenses have not been otherwise charged.
The invoiced price shall exclude any excess cost, arising in particular from breakdown or abnormal or inappropriate use of the same equipment and facilities in furtherance of the Contractor’s activities which are not Petroleum Operations.
In all events, costs charged as Petroleum Costs for use of this equipment and facilities shall not exceed those in common usage in Mauritania by Third Parties, nor shall they result in a cascading charge of expenses and profit margins.
The Contractor shall maintain detailed statement of materials, equipment and facilities which are owned by it and used in Petroleum Operations, it shall indicate the description and serial number of each unit, the maintenance expenses, the relevant repairs, and the dates on which each item has been dedicated to and then withdrawn from Petroleum Operations.  This statement must delivered to the Ministry not later than March 1 st  of every year.
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2.3       Operational expenses
2.3.1    Expenses of this type shall be charged to Petroleum Costs at the Contractor’s actual cost for the charges for services involved, such as this price appears in the Contractor’s accounts consistent with the applicable provisions of this Appendix.  These expenses include in particular:
2.3.2    The taxes, fees and imposts due and payable in Mauritania under applicable regulations and the provisions of the Contract and directly related to Petroleum Operations.
Surface rentals, the BIC tax and the bonuses provided for respectively in Articles 11 and 13 of the Contract, as well as any other charge the recovery of which is disallowed by the provisions of this Contract or of this Appendix, shall not be charged to Petroleum Costs.
2.3.3    Personnel expenses and environment of the personnel
2.3.3.1 Principles
To the extent that they correspond to actual work and services and that they are not excessive with regard to the importance of the responsibilities exercised, to the work carried out, and to the customary practices, such expenses cover all payments made to employ and and provide benefits to personnel working in Mauritania and hired for the conduct and execution of the Petroleum Operations or for their supervision.  Such personnel includes persons recruited locally by the by the Contractor and those placed at the Contractor’s disposal by the Affiliated Companies, the other Parties or Third Parties.
Such expenses are also deductible when they are connected to fixed premises of the Contractor abroad, when the activity of such premises is carried out exclusively for the benefit of the Petroleum Operations of the Contractor in Mauritania .
2.3.3.2 Expense Items
The expenses of personnel and personnel benefits shall include, on the one hand, all sums paid or reimbursed on account of such personnel referred to here above, under legal and regulatory texts, collective agreements, employment contracts and the internal policies of the Contractor and, on the other hand, expenses paid for the benefit of such personnel:
a)   Salaries and pay for active employment or holidays, overtime, bonuses and other compensation;
b)   Employer contributions pertaining thereto resulting from legal and regulatory texts, collective agreements and terms of employment;
c)   Expenses paid for the benefit of the personnel; these represent, in particular:
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 	§	 	Expenses for medical and hospital assistance, social security and all other social expenses particular to the Contractor ;	

 	§	 	Expenses for transportation of employees, their families and their personal effects, when the assumption of such expenses is provided for in the employment contract;	

 	§	 	Expenses for lodging of personnel, including therein provision of services related thereto, when the assumption of such expenses by the employer is provided for in the employment contract (water, gas, electricity, telephone) ;	

 	§	 	Compensation paid upon the time of moving in and of departure of the salaried personnel;	

 	§	 	Expenses paid to administrative personnel rendering the following services:  management and recruitment of local personnel, management of expatriate personnel, personnel training, maintenance and operation of offices and lodging, when such expenses are not included in overhead or under other expense categories;	

 	§	 	Expenses for office rental or their expense for occupancy, the expense of collective administrative services (secretarial services, furniture, office supplies, telephone, etc.).	
2.3.3.3 Terms for booking charges
Personnel costs correspond:
 	§	 	Either to direct expenses charged to the corresponding Petroleum Costs account,	

 	§	 	Or to indirect or common expenses charged to the Petroleum Costs account based upon data fromanalytical accounting and determined pro rata to the time dedicated to the Petroleum Operations.	
2.3.4    Expenses paid by reason of the provision of services supplied by Third Parties, the entities comprising the Contractor and the Affiliated Companies shall include in particular:
2.3.4.1 Services rendered by Third Parties and by the Parties are booked at the Contractor’s actual book costs, which means the price invoiced by the vendors, including all taxes, fees, and ancillary costs, if applicable; the actual costs shall be reduced by any rebates, discounts, kickbacks, or promotions the Contractor may have secured either directly or indirectly.
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2.3.4.2 The technical assistance rendered to the Contractor by its Affiliated Companies:  consisting of  services and actions for the benefit of the Petroleum Operations and emanate from the departments and services of these Affiliated Companies who are engaged in the following activities:
 	§	 	Geology,	

 	§	 	Geophysics,	

 	§	 	Engineering,	

 	§	 	Drilling and production,	

 	§	 	Deposits and reservoir studies,	

 	§	 	Economic studies,	

 	§	 	Technical contracts,	

 	§	 	Laboratories,	

 	§	 	Purchases and transport in transit (except for charges comprised of those referred to in 2.2.3 here above),	

 	§	 	Designs,	

 	§	 	Some administrative and legal services related to studies or to well-defined or occasional projects and which are not part of ordinary and regular business, nor of the legal proceedings referred to in 2.3.8 below.	
Technical assistance is generally the subject of service contracts entered into between the Contractor and its Affiliated Companies.
The costs of technical assistance rendered by the Affiliated Companies are booked at actual cost for the Affiliated Company which renders the service.  This actual cost includes, in particular, personnel expenses, the cost of raw materials, materials and consumables utilized, the cost of maintenance and repair, the cost of insurance, taxes, a portion of the amortization of general investments calculated on the original acquisition cost or of the construction of related tangible items and of any other expenses which are related to these services and have not been otherwise booked elsewhere.
However, the price excludes any surcharges arising from, in particular, fixed assets or a non-regular or cyclical use of materials, facilities and equipment at an Affiliated Company.
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In all cases, expenses related to these services must not exceed those which are normally incurred for similar services by technical service companies and independent laboratories.  They must not result in cascading charges from profit margins.
Moreover, all of these services, including analytical studies, must be supported by reports to be submitted at the request of the Ministry.  They must be the subject of written orders issued by the Contractor, and also of itemized invoices.
2.3.4.3 Whenever the Contractor utilizes in Petroleum Operations, materiel, equipment or facilities which are the sole property of an entity which makes up the Contractor, the Contractor must charge the Petroleum Costs pro rata the usage time, and the corresponding entry must be determined in accordance with the customary methods and the principles defined in 2.3.4.2 above.  This entry includes, in particular:
 	§	 	A portion of the annual depreciation calculated on the original “landed Mauritanian price” defined in 2.2.3 here above;	

 	§	 	A portion of the start-up cost, of insurance coverage, of ordinary maintenance, of financing, and of periodic checkups.	

 	§	 	Warehousing costs	

 	§	 	Warehousing costs and handling costs (expenses incurred for personnel and for management of the services) are charged to Petroleum Costs pro rata the value of the items taken out of inventory.	

 	§	 	Transportation expense:  expenses of transport of personnel, of materiel or of equipment intended and dedicated to Petroleum Operations shall be booked as Petroleum Costs if they are not already included in the preceding paragraphs and if they have not been accounted in actual costs.	
2.3.5    Damages and waste which impact jointly-owned properties
All expenses necessary to repair and restore to working condition equipment which has suffered damages or losses arising from fires, floods, storms, theft, accidents or any other cause, shall be booked in accordance with the principles defined in this Appendix.
Amounts recovered from insurance companies for these damages and losses shall be booked as a credit to Petroleum Costs.
2.3.6    Maintenance expenses
Maintenance expenses (routine maintenance and exceptional maintenance) of the materiel,
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equipment and facilities dedicated to Petroleum Operations shall be booked to Petroleum Costs at actual cost.
2.3.7    Insurance premiums and expenses related to the settlement of casualty losses shall be charged to Petroleum Costs:
a)   Premiums and expenses related to mandatory insurance and to those arising under policies to cover the Hydrocarbons produced, the persons and the properties dedicated to Petroleum Operations or the third-party liability insurance of the Contractor within the purview of the said operations;
b)   Expenses incurred by the Contractor as the result of a casualty which arose from Petroleum Operations, and those incurred in the settlement of all losses, claims, damages and other related costs which are not covered by the insurance policies;
c)   Expenses disbursed in settlement of losses, claims, damages or legal proceedings which are not compensated by insurance and which do not relate to risk which the Contractor was required to insure against.  The amounts recovered from insurance policies and guarantees are accounted for as provided for in Article 2.6.2 g) here below;
2.3.8    Legal costs
Petroleum Costs can be charged with expenses related to adversary legal proceedings, investigation, and settlement of disputes and claims (requests for reimbursement or compensation), which arise from Petroleum Operations or which become necessary in order to protect or recover properties, including, in particular, the fees of lawyers and experts, legal costs, investigation costs, cost of gathering evidence, as well as amounts disbursed in settlement of the disputes or the final settlement of any proceedings or claim.
Whenever these services are rendered by personnel of the Contractor, a compensatory payment shall be included in the Petroleum Costs which corresponds to time expended and costs actually incurred.  The price charged in such manner shall not exceed that which would have been paid to Third Parties for identical or analogous services.
2.3.9    Interest, fees, and financial charges
The following are chargeable to Petroleum Costs : interest penalties for late payment incurred by the Contractor and related to borrowings from Third Parties as well as advances and loans from Affiliated Companies, to the extent that these borrowings and advances are used to finance the Petroleum Costs and related exclusively to petroleum development operations of a commercial deposit (excluded here are Petroleum Operations related to exploration and appraisal), and provided they do not exceed seventy percent (70%) of the total amount of these
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petroleum development costs.  These borrowings and advances must be submitted for the approval of the Ministry.
In the case where such financing is secured by Affiliated Companies, the acceptable interest rates must not exceed the rate normally charged on the international financial markets for similar loans.
2.3.10  Foreign-exchange losses
Foreign-exchange losses related to borrowings and debts incurred by the Contractor under this Contract are chargeable to Petroleum Costs.
2.3.11  Disbursements related to expenses, verifications and audits of the Ministry, pursuant to the provisions of the Contract, are chargeable to Petroleum Costs.
2.3.12  Payments related to other expenses, including payments to Third Parties for the transport of Hydrocarbons to the Delivery Point shall be included in the Petroleum Costs.  Involved here are all payments made or losses incurred related to or caused by the proper execution of the Petroleum Operations, provided the charge to Petroleum Costs is not disallowed under provisions of this Contract or of this Appendix, and provided they are not similar to expenses which the Ministry has disallowed and provided these expenses have received the approval of the Ministry.  Moreover, except for contrary provisions in the law, the Contractor is at liberty, if it wishes, to make contributions of an economic, social, cultural or sport-related nature, with the mandatory exclusion of financing political activities.  These contributions shall be debited to the Petroleum Costs account.
2.4       Overhead
These expenses pertain to those Petroleum Costs which have not been otherwise accounted for.  They pertain to:
2.4.1    Expenses incurred outside of Mauritania
The Contractor shall add a reasonable sum on account of foreign overhead necessary to carry out the Petroleum Operations and borne by the Contractor and its Affiliated Companies, in such amount as they reflect the cost of the services rendered to the Petroleum Operations.
The amounts must be supported by accounting entries and copies of reports related to the services and works carried out; if an arbitrary sharing is utilized, there must be proof by means of supportive explanations and presentation of the rules utilized to arrive at such.
The amounts charged are considered provisional amounts arrived at on the basis of the Contractor’s experience, and they shall be adjusted annually in relation to the Contractor’s real costs, but they must not exceed the following caps:
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 	·	 	Before grant of the first Exploitation Authorization : three percent (3%) of the Petroleum Costs excluding overhead;	

 	·	 	On the grant of the first Exploitation Authorization : one and one-half percent (1.5%) of Petroleum Costs not including financial costs and overhead.	
These percentages are applied to expenses, not including overhead, which are chargeable to Petroleum Costs for the Calendar Year under consideration.
2.4.2    Expenses disbursed inside of Mauritania
These expenses cover payment related to the following activities and services:
 	§	 	General management and general secretarial services;	

 	§	 	Information and communication ;	

 	§	 	General administration (law department, insurance, taxes, computer services) ;	

 	§	 	Accounting and budget ;	

 	§	 	Internal audit.	
They must include services which have actually been required to advance the Petroleum Operations and which correspond to actual services rendered in Mauritania  by the Contractor or the Affiliated Companies.  They must not result in cascading of of costs margins.
The amount must be actual amounts, whenever direct expenses are involved, and they must be amounts arrived at by sharing whenever indirect expenses are involved.  In the latter case, the rules for sharing must be clearly defined and the amounts must be supported by analytical accounting.
2.5       Expenses not chargeable to Petroleum Costs
Payments paid in settlement of expenses, charges or costs not directly chargeable to Petroleum Operations, and those for which the deduction or charging for is disallowed by the provisions of the Contract or of this Appendix, or those which are not necessary for the conduct of Petroleum Operations, shall not be taken into account and shall not give rise to recovery.
Involved here are these types of payments:
a)   Costs of a capital increase;
b)   Expenses related to activities downstream of the Delivery Point, particularly marketing costs;
c)   The expenses which relate to the period prior to the Effective Date;
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d)   Auditing expenses disbursed by the Contractor further to special relationships between the entities which make up the Contractor;
e)   Expenses borne for meetings, studies and work carried out in furtherance of the association which ties together the entities which make up the Contractor and the purpose of which is not the proper conduct of the Petroleum Operations;
f)   Interest, late payment fees, and financial charges other than those the chargeability of which is authorized pursuant to Article 2.3.9 of this Appendix.
g)   Foreign-exchange losses incurred other than those which are chargeable under the provisions of this Contract.
h)   Foreign-exchange losses which constitute a loss of earnings tied to risks related to the Contractor’s own capital and self-financing by it.
2.6       Items to be booked as a credit to Petroleum Costs
The following must be credited to the Petroleum Costs account, in particular:
2.6.1    The proceeds from the quantities of Hydrocarbons which the Contractor takes in furtherance of the provisions of Article 10.2 of the Contract, multiplied by the related Market Price as defined in Article 14 of the Contract.
2.6.2    All other receipts, revenues, proceeds, connected profits, whether ancillary or accessory, directly or indirectly tied to Petroleum Operations, including in particular those derived from:
(A) The sale of associated substances;
(B) The transport and storage of products owned by Third Parties in the facilities dedicated to the Petroleum Operations;
(C) Reimbursements originating from insurance companies;
(D) Settlements arising out transactions or liquidations;
(E) Transfers or rentals already declared under Petroleum Costs
(F) Discounts, rebates, allowances and promotions received which have not been charged as a deduction from the actual costs of the properties to which they relate.
(G) Any other income or receipts similar to those listed above that are usually deducted from Petroleum Costs.
2.7       Materiel, equipment and facilities sold by the Contractor
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2.7.1    The materials, equipment, facilities, and consumables which are not used or are not usable shall be withdrawn from Petroleum Operations ; they must be either downgraded or considered as « junk and waste », or bought back by the Contractor for his own needs, or sold to Third Parties or to Affiliated Companies.
2.7.2    In the event of adisposal to the entities which make up the Contractor or to their Affiliated Companies, the prices shall be arrived at pursuant to the provisions of 2-2-3.b of this Appendix, or, should they exceed those which would be applicable under the provisions of that article, their price must be agreed by the Parties. Whenever the use of an item of property related to Petroleum Operations has been temporary and it does not fall under the price reduction referred to in the above article, the said item shall be valued so that the Petroleum Costs are debited of a net amount which is equivalent to the value of the service rendered.
2.7.3    The sales to Third Parties of materials, equipment, facilities and consumables shall be effected by Contractor at the best possible price.  All reimbursements or compensation granted to a buyer for a defective piece of equipment shall be debited to the Petroleum Costs account to the extent and at the time such are actually paid by the Contractor.
2.7.4    Whenever an asset is used for the benefit of a Third Party or the Contractor for activities which are not within the scope of this Contract, the amounts due in exchange therefor must be calculated at a rate which is not less than actual costs, unless the Ministry agrees otherwise.
ARTICLE 3:  DETERMINATION OF THE RATIO « R »
3.1       For the purpose of arriving at the value of the “R” ratio in application of Article 10.3 of the Contract, the Petroleum Costs which impact the calculation of Net Cumulative Revenues and of Cumulative Investments shall be categorized and recorded separately according to the following categories.
3.2       Exploration Petroleum Costs
They are the Petroleum Costs incurred in the exploration Petroleum Operations inside an Exploration Perimeter, included in an Annual Work Program approved pursuant to the provisions of the Contract, and they shall include, without limitation:
3.2.1    Geochemical, geophysical, paleontological, geological, topographical studies and the seismic campaigning as well as studies and interpretations related thereto.
3.2.2    Coring, exploration wells, appraisal wells and wells drilled to supply water.
3.2.3    Labor costs, materiel, supplies and services used to service exploration wells or appraisal wells of a discovery and which are not completed as producers.
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3.2.4    Equipment utilized exclusively to enhance and justify the objectives listed in Articles 3.2.1, 3.2.2 and 3.2.3 here above, including access roads and acquired geological and geophysical information.
3.2.5    That portion of the Petroleum Costs incurred in construction of facilities and equipment, the overhead chargeable to exploration Petroleum Costs as such is derived from a fair allocation of the Petroleum Costs taken as a whole (including overhead) between exploration Petroleum Costs and the Petroleum Costs taken as a whole, with exception of overhead.
3.2.6    All the other Petroleum Costs incurred for the purpose of exploration between the Effective Date and the startup of the commercial production of Hydrocarbons that are not included in Article 3.3 here below.
3.3       Petroleum Costs of Development
They are the Petroleum Costs incurred in development Petroleum Operations related to an Exploitation Authorization, and they include, without limitation:
3.3.1    Development and production wells, including water-injection wells and gas-injection wells drilled for the purpose of enhancing recovery of Hydrocarbons as well as those intended to sequester and conserve natural gas.
3.3.2    The wells which have been completed by setting casing or equipment after a well has been drilled with intent to complete it as a producer well or a water-injection well or a gas-injection well drilled for the purpose of increasing the recovery rate of Hydrocarbons as well as those wells the purpose of which is sequestration and conservation of natural gas.
3.3.3    The costs of equipment related to production, transport and storage to the Delivery Point, such as pipelines, flow-lines, processing and production units, equipment on the well-head, underwater equipment, systems to increase recovery of Hydrocarbons, offshore platforms, production floating unit and/or production and storage floating units (FPO and FPSO), storage facilities, export terminals, port installations and auxiliary equipment, as well as access roads in relation to production activities.
3.3.4    Engineering studies and design studies related to the equipment referred to in Article 3.3.3.
3.3.5    The cost of construction, the overhead chargeable to Development Costs, as these are calculated according to the ratio of Development Costs over total Petroleum Costs, excluding overhead.
3.3.6    Financial charges pertaining to the financing of Development Costs are excluded.
3.4       Exploitation Petroleum Costs
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These are the Petroleum Costs incurred in an Exploitation Perimeter consequent to the startup of commercial Hydrocarbons production and which are neither exploration costs nor development costs nor overhead.
Exploitation costs include more particularly the reserves built up for the purpose of meeting losses or charges, including the reserve to fund the Rehabilitation Plan, which reserve has been paid in full to the sequestered account opened for the purpose of financing rehabilitation of the site works in accordance with Article 23.2 of the Contract.
The portion of overhead which has not been allocated to either exploration or development costs shall be included in exploitation costs.
3.5       It is understood that depreciation of assets as calculated for the determination of taxable profits pursuant to the provisions of Article 4 here below are not Petroleum Costs and consequently, they do not enter into the determination of the Ratio “R”.
ARTICLE 4:  CHARGES WHICH ARE DEDUCTIBLE FOR DETERMINATION OF THE
INDUSTRIAL AND COMMERCIAL INCOME TAX
4.1       Deductible charges
In accordance with Article 70 of the Crude Hydrocarbons Code, the charges which are deductible for the determination of the Industrial and Commercial Income Tax are made up of the following items, within the limits prescribed by this Accounting Procedure, and excluding those charges which are non-deductible as specified in Title 6 of the Crude Hydrocarbons Code and of costs non-chargeable to Petroleum as specified in Article 2.5 here above of this Appendix:
 	§	 	The exploitation Petroleum Costs, as defined in the provisions of this Accounting Procedure ;	

 	§	 	The overhead in accordance with the provisions of Article 2-4 here above of this Appendix;	

 	§	 	Depreciation of assets which make up the development Petroleum Costs in according with the provisions of Article 4.2 below;	

 	§	 	Interest, interest for late payments, and financial charges, in accordance with the Article 2.3.9 here above ;	
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 	§	 	Loss or wastage of materials and property arising out of destruction or casualty, uncollectible debts, and compensation paid to Third Parties on account of legal liability (unless these damages were caused by the Gross Negligence of the Contractor) ;	

 	§	 	Reserves which are reasonable and justified created for the purpose of meeting losses or clearly defined charges which the prevailing circumstances make probable;	

 	§	 	The non-recovered portion of deficits related to previous years within a limit of five (5) years following the fiscal year that shows a deficit.	
4.2       Depreciation of fixed assets
Fixed assets of the Contractor that are required for Petroleum Operations are depreciated according to a straight-line dereciation method.
The minimum span of the depreciation period shall be:
 	§	 	ten (10) Calendar Years for assets related to the transport of Hydrocarbons production by pipeline;	

 	§	 	five (5) Calendar Years for the other fixed assets.	
The period of depreciation shall begin with the Calendar Year during which the said fixed assets have been acquired, or from the Calendar Year during which the fixed assets were placed into normal service if such latter year is after, pro rata temporis, the first Calendar Year in question.
4.3       Exploration Petroleum Costs
The petroleum Exploration Costs incurred by the Contractor for the Exploration Perimeter, including particularly the expenses of geological and geophysical exploration studies and the expenses of exploration drilling and appraisal of a discovery (excluding productive wells, which shall be considered assets which fall under the provisions of Article 4.2 here above of this Appendix), are considered charges deductible in full from the year they are entered on the books or they may be depreciated at the rate chosen by the Contractor.
ARTICLE 5:  INVENTORIES
5.1       Frequency
The Contractor shall keep a permanent inventory in both quantity and value of all property used in Petroleum Operations and he shall, with reasonable frequency, and not less than once a year, proceed to take a physical inventory as required by the Parties.
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5.2       Notification
Written notification of the intention to take a physical inventory must be sent by the Contractor not less than ninety days (90) days prior to the commencement of the taking of such inventory, so that the Ministry and the entities which make up the Contractor may if they wish be represented at their own expense during the taking of said inventory.
5.3       Information
Should the Ministry or an entity which makes up the Contractor not be represented when an inventory is taken, such Party will remain bound by the result of the inventory taken by the Contractor, who must furnish to said Party a copy of the said inventory.
ARTICLE 6:  STATEMENTS OF OPERATIONS AND WORK, STATUS REPORTS
6.1       Principles
Other than the statements and supply of information provided for elsewhere, the Contractor must submit to the Ministry under terms, conditions and timelines indicated below, the details of its operations and works carried out as they have been booked in its accounts, documents, reports and statements which it must keep in relation to the Petroleum Operations.
6.2       Statement of variations in fixed assets accounting and in inventory of materiel and consumables.
This statement must be received by the Ministry not later than the fifteenth day (15th) day of the first month of each calendar Quarter. In particular, it shall state, for the preceding quarter what was acquired and created by way of fixed assets, of materiel and of consumables required for Petroleum Operations, for each deposit, and by major categories, as well as disposal of these items (assignments, wastage and losses, destruction, discarding and junk).
6.3       Statement of the quantities of Crude Petroleum and of Natural Gas which have been transported during each month
Such statement must reach the Ministry not later than the fifteenth (15th) day of each month.  For each deposit, it shall indicate the quantities of Crude Petroleum and of Natural Gas which have been transported in the course of the preceding month, between the field and the point of export or delivery, as well as the identification of the pipeline utilized and the cost of transport paid, whenever transport was carried out by Third Parties.  The statement must also show how the products transported in such manner are shared between the Parties.
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6.4       Statement of the recovery of Petroleum Costs
This statement must reach the Ministry not later than the fifteenth (15th) day of each month.  It shall show, for the preceding month, the breakdown of the Petroleum Costs account and must reflect, in particular, the following:
 	§	 	The Petroleum Costs which remain to be recovered as of the end of the preceding month;	

 	§	 	The Petroleum Costs related to activities during the month in question;	

 	§	 	The Petroleum Costs recovered in the course of the month indicating in particular quantities and value of production involved for this purpose;	

 	§	 	The amounts which are booked to reduce or diminish Petroleum Costs in the course of the month in question;	

 	§	 	The unrecovered Petroleum Costs as of the end of that month.	
6.5       Statement of the determination of the ratio « R »
This statement must reach the Ministry not later than the fifteenth (15th) day of the first month of each Quarter.  It shall highlight each of the factors which enter into the determination of the “R” ratio as defined in Article 3 of this Accounting Procedure, as well as the resulting value of the ratio, which ratio is applicable during the subject Quarter.
6.6       Inventories of Crude Petroleum and of Natural Gas
This statement must reach the Ministry not later than the fifteenth (15th) day of each month.  It shall specify for the preceding month and for each storage location:
 	§	 	Inventory at the commencement of the month;	

 	§	 	Addition to inventory in the course of the month;	

 	§	 	Withdrawals from inventories during the course of the month;	

 	§	 	Theoretical level of the inventory at the end of the month;	

 	§	 	Inventory at the end of the month taken by measurement;	

 	§	 	An explanation for discrepancies, if any.	
6.7       Tax returns
The Contractor shall supply the Ministry with a copy of all returns which the entities which make up the Contractor are required to file with the Tax Administrations responsible for determining tax
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basis; and in particular, those which pertain to the BIC tax on together with all annexes, documents, and supporting information attached thereto.
6.8       Statement of payments of taxes and fees
Not later than the fifteenth (15th) day of the first month of each Quarter, the Contractor shall prepare and submit to the Ministry a statement showing taxes, fees, and dues of any kind paid by it in the course of the preceding calendar Quarter; it shall detail precisely the nature of the tax, fee and dues involved (surface rentals, customs duties, etc.), the kind of payment involved (on account, balances, corrections, etc.), the date and the amount of each payment, the designation of the tax collector responsible for the collection, and other further useful information.
6.9       Special provisions
The statements, lists, and information referred to in Articles 6.2 to 6.8 shall be produced and submitted in accordance with printed forms issued by the Ministry, after consultation with the Contractor.
The Ministry may, as needed, request that the Contractor furnish it with all other statements, reports and information that the Ministry deems useful.
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APPENDIX 3:  MODEL BANK GUARANTEE
Attached and being an integral part of the Contract between the Islamic Republic of Mauritania and the Contractor (On letterhead of the Bank)
To the Honorable Minister in Charge of Crude Hydrocarbons,
Nouakchott
Mauritania
Amount : -----
In letters : ----------------------------------------
We have been informed that, upon the date of -----, the Mauritanian State entered into an exploration-production contract with the Contractor constituted by the following entities:
Kosmos Energy Mauritania
----------------------------------------
Grand Cayman
----------------------------------------
Kosmos Energy Mauritania --------, address -------- is the Principal and has been so designated here below.
Pursuant to Article 4.6  of this Contract, a bank guarantee of proper discharge of the minimum work obligations, for work committed to the first phase of the Exploration Period of the contract,  must be  remitted to the State.
That said, we (name of bank -------------, address ---------------) referred to hereafter as «the Bank», upon instructions from the Principal, commit ourselves through this Guarantee, in an irrevocable fashion, to pay to the Mauritanian State, independently of the validity and legal merits under the Contract in question and without raising any exception, nor objection arising from the said Contract, upon your first demand, any amount up to the maximum amount cited above in this letter of of guarantee, upon receipt  by ourselves of a demand for payment duly signed and a written confirmation on your part certifying that the Contractor has not fulfilled the minimum work obligations above-mentioned and specifying the nature as well of the estimated cost of the work not executed.
For reasons of identification, your written demand for payment will only be considered valid if it reaches us through the intermediary of our corresponding bank located in Mauritania (name-------, address ----------), accompanied by a declaration of the latter certifying that it proceeded with the verification of your signature.
Your call is also acceptable to the extent that it is fully transmitted to us by the bank in question by means of a telex/SWIFT confirming that it has sent us the original by registered mail or by another courier service and that the signature appearing there was verified by the latter.
The amount of the Guarantee shall be reduced by the amount of the expenditures made by ________, upon receipt by the Bank of a copy of a work completion statement signed by the Mauritanian State and attesting to said expenditures and to the resulting new Guarantee amount, in accordance with the model in Annex A.
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Our guarantee is valid up until the --------------------------------- (provide for 6 months after the end of the phase in question of the Exploration Period) and shall terminate automatically and entirely if your demand for payment or the telex/SWIFT does not reach us at the address here above by such date at the latest, whether it is a business day or not.
All the bank fees in connection with this guarantee are at the expense of the Principal.
This guarantee is subject to the « Uniform Rules for Demand Guarantees of the ICC » of the International Chamber of Commerce (ICC Publication in force No. 758).
 	·	 	Signature of the authorized representative and seal of the Bank	
Annex A
Model notification of expenditure and reduction of guarantee to be used
Notification of expenditure and reduction of guarantee
To the Minister in Charge of Crude Hydrocarbons
Mauritanian State
Nouakchott
Mauritania
Purpose:  Notification of expenditure and reduction of guarantee amount ref. XXXX
Honorable Minister,
We refer to the Exploration and Production Contract signed on ____, as well as the bank guarantee of proper discharge in the initial amount of USD ___given by _____on _____ under reference no. _____.
On ____ the amounts expended were USD____.  Accordingly the amount of said guarantee is reduced to ____ (numbers plus letters).
Polite closure statement
Date:
Signature of Contracting Entity
Confirmation of Principal (KOSMOS ENERGY)
"Stamp of the Minister in charge of Hydrocarbons, authorized signature
Preceded by the statement “Agreed for the reduction of the guarantee in question in the amount of XXXX”
NAME + FUNCTION + STAMP of the Minister"
 
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Exhibit 10.42
 
Private and Confidential
15 DECEMBER 2016

 

 
KOSMOS ENERGY MAURITANIA
AND
BP EXPLORATION (WEST AFRICA) LIMITED

 

FARMOUT AGREEMENT RELATING TO
BLOCKS C6, C8, C12 and C13, OFFSHORE MAURITANIA

 

 

TABLE OF CONTENTS

ARTICLE 1 DEFINITIONS	1 	
 	 	
ARTICLE 2 ASSIGNMENT OF INTEREST	8 	
 	 	
ARTICLE 3 CONDITIONS PRECEDENT	9 	
 	 	
ARTICLE 4 CONSIDERATION	13 	
 	 	
ARTICLE 5 OBLIGATIONS AND LIABILITIES	17 	
 	 	
ARTICLE 6 INTERIM PERIOD OBLIGATIONS	19 	
 	 	
ARTICLE 7 WARRANTIES	21 	
 	 	
ARTICLE 8 TAX	24 	
 	 	
ARTICLE 9 CONFIDENTIALITY	26 	
 	 	
ARTICLE 10 NOTICES	27 	
 	 	
ARTICLE 11 LAW AND DISPUTE RESOLUTION	28 	
 	 	
ARTICLE 12 FORCE MAJEURE	29 	
 	 	
ARTICLE 13 DEFAULT	30 	
 	 	
ARTICLE 14 GENERAL PROVISIONS	30 	
 
EXHIBITS
 
A.	Eligible Discovery	I.	Farmee Warranties	
B.	NOT USED	J.1	Firm Work Programme (Exploration & Appraisal)	
C.	Contract Area	   2.	Firm Work Programme (Development)	
D.	Form of JOA Novation Agreement	K.	Operator Transition Provisions	
E.	Assignment	L.	Questions and Answers	
F.	NOT USED	M.	ABC Obligations	
G.	NOT USED	N.	Farmor Retained Liabilities	
H.	Farmor Warranties	 	 	

 

 

FARMOUT AGREEMENT
 
THIS AGREEMENT is entered into on the 15th  day of December 2016 by and between Kosmos Energy Mauritania , a company existing under the laws of the Cayman Islands (hereinafter referred to as “ Farmor ”) and  BP Exploration (West Africa) Limited , a company existing under the laws of England and Wales (hereinafter referred to as “ Farmee ”).  The companies named above, and their respective successors and assignees (if any), may sometimes individually be referred to as “ Party ” and collectively as the “ Parties ”.
 
WITNESSETH:
 
WHEREAS, the Contracts for Blocks C8, C12 and C13 were signed on 5 April 2012 by and between Farmor, SMHPM and the Islamic Republic of Mauritania for the exploration, development and production of hydrocarbons in the Blocks C8, C12 and C13 portions of the Contract Area;
 
WHEREAS, the Contract for Block 6 was signed on 11 October 2016 by and between Farmor, SMHPM and the Islamic Republic of Mauritania for the exploration, development and production of hydrocarbons in the Block C6 portion of the Contract Area;
 
WHEREAS, as of the date of this Agreement, Farmor holds ninety percent (90%) of the rights and obligations in the Contract and the Contract Area for Blocks C6, C8, C12 and C13;
 
WHEREAS, as of the date of this Agreement, Farmor holds a ninety percent (90%) participating interest and a one hundred percent (100%) paying interest in the rights and obligations in the JOA for Blocks C8, C12 and C13, and when issued Farmor will hold a ninety percent (90%) participating interest and one hundred percent (100%) paying interest in the rights and obligations in the JOA for Block C6; and
 
WHEREAS, Farmor is willing to assign and transfer a certain undivided interest in its rights and obligations under the Contract and JOA for Blocks C8, C12 and C13, the Contract for Block C6, and when issued the JOA for Block C6 to Farmee in accordance with the terms set forth herein and Farmee agrees to accept such interest.
 
NOW, THEREFORE, in consideration of the premises and the mutual covenants and obligations set out below and to be performed, Farmor and Farmee agree as follows:
 
ARTICLE 1
DEFINITIONS 
 
1.1        As used in this Agreement, the following capitalized words and terms shall have the meaning ascribed to them below.  Any capitalized term used in this Agreement and not specifically
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defined in this Agreement shall have the same meaning as in the Contract or JOA, as the context requires.
 
Affiliate means a legal entity which Controls, or is Controlled by, or which is Controlled by an entity which Controls, a Party, and “ Affiliates ” shall be construed accordingly.
 
Agreement means this Farmout Agreement together with the Exhibits, and any extension, renewal or amendment hereof agreed to in writing by the Parties.
 
Answer means a written response made by Farmor to Farmee in respect of any question or clarification sought by Farmee in respect of or in relation to the Interests, the Interest Documents or the Contract Area, as set out in Exhibit L.
 
Anti-Corruption Laws and Obligations means:
 
(a)      The OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions, 1997;
 
(b)      the Foreign Corrupt Practices Act of 1977 of the United States of America, as amended by the Foreign Corrupt Practices Act Amendments of 1988 and 1998, and as may be further amended and supplemented from time to time;
 
(c)      the Bribery Act 2010 of the United Kingdom and any regulations or guidance issued pursuant to such legislation, as may be amended and supplemented from time to time; and
 
(d)      any act, rule or regulation of the United States of America, the United Kingdom, the Islamic Republic of Mauritania or any other relevant jurisdiction related to prevention of bribery, corruption, or money laundering,
 
provided that, in the event that a Party acting with respect to this Agreement is outside the jurisdiction or scope of any of the aforementioned laws, such laws shall be interpreted as though such Party were within the jurisdiction and scope of such law.
 
Approval means the issuance of the approval of the Government required in order to effect the legal assignment and transfer of the Interests from Farmor to Farmee.
 
Assignment means the document, substantially in the form attached as Exhibit E, by which the Interest in the Contract is assigned and transferred to Farmee by Farmor as provided hereunder, together with any revisions or amendments thereto approved by Farmee (such approval not to be unreasonably withheld).
 
Associated Person means a person acting on behalf of the first Person or the first Person’s Affiliates, whether as personnel of any tier, as an officer, director or under a power of attorney or other similar authorization and specifically including consultants, representatives, agents, employees or other similar persons who have the right or power to act on behalf of the first Person or its Affiliate.
 
BP Senegal means BP Indonesia Oil Terminal Investment Limited, a company existing under the laws of England and Wales, being a party to the Senegal Agreement.
 
Brent means the arithmetic average of the high and low spot daily assessments of Brent (Dated)
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quotations as published in Platt’s Crude Oil Marketwire for the relevant period of time.
 
Business Day means a day other than Saturday or Sunday on which banks are generally open for business in London and Dallas; and “ Business Days ” shall be construed accordingly.
 
Completion Date means the date on which the Conditions Precedent have all been satisfied or waived.
 
Commercial Production means any production from the Contract Area pursuant to a Development Plan (as defined under the JOA) as approved in accordance with the JOA.
 
Conditions Precedent means the conditions precedent contained in or referred to in Article 3.1.
 
Consideration has the meaning given in Article 4.1.
 
Contract means together the Petroleum Agreement and any extension, renewal or amendment thereto, and all exploration authorizations granted pursuant to the Petroleum Agreement or any successor title that governs all or part of the Contract Area, as all such instruments and titles are governed by the Hydrocarbon Code.
 
Contract Area means the area or blocks more particularly described in Exhibit C.
 
Control means the ownership directly or indirectly of fifty percent (50%) or more of the voting rights in a legal entity. “ Controls” , “ Controlled by ” and other derivatives shall be construed accordingly.
 
Co-Venturer means any third party to a joint operating agreement that relates to the Contract Area from time to time, and “ Co-Venturers ” shall be construed accordingly.
 
Data means all accounts, books, data and reports in the possession, custody or control of Farmor and its Affiliates relating to the Interests including correspondence, petroleum engineering, reservoir engineering, drilling, geoscientific, seismic and all other kinds of technical data and reports, samples, well logs and analyzes in whatever form the same are maintained, including third party information, including seismic, which Farmor or its Affiliates has the right to disclose, acquired pursuant to the Interest Documents, subject to the exclusion of work product of, or attorney-client communications with, legal counsel for Farmor or any Affiliate of Farmor.
 
Development Carry shall have the meaning given to it in Article 4.5.
 
Disclosure Documents means the Disclosure Letter and the documents stored in electronic form on a hard drive provided to each Party by Intralinks Inc., that represent the entire contents of Farmor’s data room at 16.55 (GMT) (London time)/ 10.55 am Dallas time (CST) on 12 th  December 2016.
 
Disclosure Letter means the letter described as such, dated as of the date of this Agreement and addressed to Farmee by Farmor, which sets out certain disclosures against the Farmor’s Warranties.
 
Dollars or US$ means the currency of the United States of America.
 
Effective Date means 1 July 2016.
 
Eligible Discovery means a discovery of Hydrocarbons (as defined under the Contract) in the
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Contract Area, other than the Tortue Discovery Area (from the surface to the equivalent of the oldest stratigraphy currently penetrated in the development area by the Guembeul #1A Well) and the Marsouin Discovery Area (from the surface to the equivalent of the oldest stratigraphy currently penetrated in the development area in the Marsouin #1 Well) as shown and described on Exhibit A, Parts 1 and 2.
 
Encumbrances means all liens, charges (fixed or floating), mortgages, pledges, encumbrances or security or net profit interests or royalty or overriding interests, carried interests, production payments, claims, options, pre-emption rights or equities or any agreement to create any of the foregoing other than (in each case) those arising under the provisions of the Interest Documents “Encumbrance” and “Encumber” shall be construed accordingly;
 
Exploitation Perimeter shall have the meaning given to it in the Contract.
 
Exploration & Appraisal Carry shall have the meaning given to it in Article 4.4.
 
Farmee Participating Interest Share means the Farmee's Participating Interest share accepted by Farmee on and from the Completion Date and as set out in Article 2.4.
 
Farmee Warranties means the representations and warranties set out in Exhibit I.
 
Farmee’s Account means the account information notified by Farmee to Farmor from time to time.
 
Farmor Retained Liabilities means all costs, charges, expenses, duties, losses, liabilities and obligations which accrue or relate to any period before, on or after the date of this Agreement and arise in relation to the matters set out in Exhibit N.
 
Farmor Warranties means the representations and warranties set out in Exhibit H.
 
Farmor’s Account means the account information notified by Farmor to Farmee from time to time with at least five (5) Business Days' Notice.
 
Farmor Payment Failure means: (i) any failure by the Farmor to pay any amount owed by Farmor to Farmee in respect of this Agreement (other than under Article 4.7B hereof); or (ii) any failure by Kosmos Senegal to pay any amount owed by Kosmos Senegal in respect of the Senegal Agreement.
 
Firm Work Programme (Development) means the Tortue development studies required to support a late 2017 investment decision on the Tortue area as set out in Exhibit J 2.
 
Firm Work Programme (Exploration and Appraisal) means the work programme as set out in Exhibit J 1.
 
Good Industry Practice means the exercise of that degree of skill, diligence, prudence and foresight which would reasonably and ordinarily be expected to be applied by a skilled and experienced person engaged in the same type of undertaking.
 
Government means the government of the Islamic Republic of Mauritania and any political subdivision, agency or instrumentality thereof, including SMHPM.
 
Government Official means, whether appointed, elected or otherwise, any:
 
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(a) minister, civil servant, director, officer, principal, agent or employee or other official of: (i) any government (whether central, federal, state, provincial or local) ministry, body, department, agency, instrumentality or part of any of them; (ii) any public international organization; (iii) any department, agency or body of any government-owned or controlled company, agency, enterprise, joint venture, or partnership; and (iv) any company, agency, enterprise, joint venture, or partnership in which a government owns an interest of more than thirty percent, and/or of any public international organization (such as the World Bank or United Nations);
 
(b) person acting in any official, legislative, administrative or judicial capacity for or on behalf of any government department, agency, body, instrumentality or public international organization, including without limitation any judges or other court officials, military personnel and customs, police, national security or other law enforcement personnel;
 
(c) officer or employee of a political party or any person acting in an official capacity on behalf of a political party; and/or
 
(d) candidate for political office.
 
Guarantee means (a) the bank guarantee to be provided by non-Operator to Operator pursuant to Article 3.4(a) and (b) the guarantee to be provided by Farmee to Farmor pursuant to Article 3.4(b).
 
Hydrocarbon Code means Code of Crude Hydrocarbons (Law No. 2010-33 dated 20 July 2010) as modified and completed.
 
Initial Payment shall have the meaning given to it in Article 4.2.
 
Interests means an undivided legal and beneficial interest of sixty-two percent (62%) in the rights and obligations under the Contract and an undivided interest of sixty-two percent (62%) participating interest and a sixty-eight decimal eighty-nine percent (68.89%) Paying Interest in the rights and obligations under the JOA, in each case to be acquired by Farmee from Farmor pursuant to this Agreement.
 
Interest Documents means the Contract and JOA.
 
Interim Period Costs means all costs properly incurred by Operator directly in relation to the Farmee’s Paying Interest share under the JOA for Joint Operations (as defined under the JOA) undertaken by Operator pursuant to the terms of the JOA during the Interim Period if applicable, and determined pursuant to Article 4.3 but which shall not include the Farmor Retained Liabilities.
 
Interim Period means the period commencing from 1 July, 2016 until, but not including the Completion Date .
 
JOA or Joint Operating Agreement means (a) the three (3) Amended and Restated Joint Operating Agreements each dated 1 December 2014 entered into by Farmor and SMHPM for operations in the Blocks C8, C12 and C13 portions of the Contract Area; and (b) the Joint
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Operating Agreement to be entered into on terms substantially similar to the JOAs set out in (a) above, by Farmor,  SMHPM and, if such JOA has yet to be executed prior to the Completion Date, by Farmee for operations in the Block C6 portion of the Contract Area, copies of which are included in the Disclosure Materials. 
 
JOA Novation means the novation and amendment agreement in respect of the JOA to be entered into by the Parties and SMHPM pursuant to the terms of this Agreement, which forms Exhibit D, together with any revisions or amendments thereto approved by Farmee (such approval not to be unreasonably withheld).
 
JV Co has the meaning given in the Senegal Agreement.
 
Kosmos Senegal means Kosmos Energy Senegal, a company incorporated in the Cayman Islands with its registered office at 4th Floor, Century Yard, Cricket Square, Hutchins Drive, Elgin Avenue, George Town, Grand Cayman KY1-1209.
 
Laws/Regulations means those laws, statutes, rules and regulations governing activities under the Contract .
 
LNG means processed Natural Gas (as defined under the Contract) consisting primarily of methane (CH 4 ) in a liquid state at or below its boiling point and at a pressure of approximately one (1) atmosphere.
 
Operator means the operator under the Contract and the JOA.
 
Operator Transfer Date means 1 April 2017 (or such later date as is mutually agreed between the Parties and SMHPM).
 
Participating Interest means as to any party to the Contract or the JOA, the undivided interest of such party expressed as a percentage of the total interest of all parties in the rights and obligations derived from the Contract or the JOA as the context so requires.
 
Paying Interest means as to any party to the JOA, other than SMHPM, the undivided interest of such party in the payment obligations under the JOA in respect of the Participating Interest share of SMHPM in a Contract, until SMHPM elects to participate in an Exploitation Perimeter as set forth in Article 2.4 from which time the Parties’ Paying Interests in such Exploitation Perimeter will be aligned with such Party’s Participating Interests.
 
Person means an individual, corporation, company, government entity, state enterprise, or any other legal entity.
 
Petroleum Agreement means (a) the three (3) Exploration and Production Contracts each dated 5 April 2012 entered into by Farmor, SMHPM and the Islamic Republic of Mauritania for the exploration and exploitation of hydrocarbons in the Blocks C8, C12 and C13 portions of the Contract Area; and (b) the Exploration and Production Contract dated 11 October 2016 entered into by Farmor, SMHPM and the Islamic Republic of Mauritania for the exploration and exploitation of hydrocarbons in the Block C6 portion of the Contract Area, copies of which are included in the Disclosure Materials.
 
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Preferential Right means a right held by any third party under the terms of the Contract, JOA or under applicable law rule or regulation to pre-empt the transaction contemplated by this Agreement or affect its terms in any way.
 
Quarter has the meaning ascribed to that term under the Contract.
 
Senegal Agreement means the Sale and Purchase Agreement concerning the shares of JVCo between Kosmos Senegal and BP Senegal of even date with this Agreement.
 
Senegal Area means the area covered by the Hydrocarbon Exploration and Production Sharing Contract granted by the Republic of Senegal dated January 17, 2012 covering the Saint Louis Offshore Profond Block and the Hydrocarbon Exploration and Production Sharing Contract granted by the Republic of Senegal dated January 17, 2012 covering the Cayar Offshore Profond Block.
 
SMHPM or La Société Mauritanienne Des Hydrocarbures et de Patrimoine Minier   means   the national oil company of the Islamic Republic of Mauritania, incorporated by Decree No. 2005-106 dated 7 November 2005 as amended by Decree No. 2009-168 dated 3 May 2009 and Decree No. 2014-01 dated 6 January 2014 under the laws of the Islamic Republic of Mauritania and having its registered office at Ilot K, Rue 42-133, No. 349, BP 4344, Nouakchott, Islamic Republic of Mauritania.
 
Success Fee means a fee per Barrel (as defined under the Contract) of total production of all liquid Hydrocarbons (as defined under the Contract) in the natural state or obtained from Natural Gas by condensation or separation with an API gravity equal to or greater than 22.3°, but excluding LNG, from each Eligible Discovery calculated on the basis of the average price of Brent during the relevant Quarter of production multiplied by one decimal sixty-seven cents (US$ 0.0167), which yields a Success Fee of one Dollar (US$ 1.00) per Barrel of production at a Brent price of sixty Dollars (US$ 60); provided that the Success Fee per Barrel shall not exceed two Dollars (US$ 2.00) per Barrel regardless of the average price of Brent.
 
Surviving Provisions means Articles 1 (Definitions and Interpretation), 2.5C (Transfer of Title and Risk ), 3.2E ( Acts to be Performed ), 7.3A ( Breach of Warranty ), 7.6 ( Fraud and Wilful Concealment ),   8 ( Tax ), 9 ( Confidentiality ), 10 ( Notices ),   11 ( Law and Dispute Resolution ), 14 ( General Provisions )   and Exhibit M ( ABC Obligations ).
 
Tax means any tax, royalty, levy, charge, impost, duty, fee, deduction, compulsory loan or withholding which is assessed, levied, imposed or collected by the Government tax authorities or any tax authorities of any other jurisdiction and includes any interest, fine, penalty, charge, fee or other amount imposed in respect of the above, and “ Taxes ” shall be construed accordingly.
 
Wholly-Owned Affiliate means, in relation to any entity, any other entity that is wholly owned and controlled by such entity or that is wholly owned and controlled by a third person which has common control over the first two entities.
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ARTICLE 2
ASSIGNMENT OF INTEREST
 
2.1        Grant
 
Subject to the satisfaction of the Conditions Precedent and in exchange for the Consideration, with effect from the Completion Date Farmor shall assign and transfer to Farmee, and Farmee agrees to accept, the Interests, free from Encumbrances, excluding any Encumbrances contained within the Contract. 
 
2.2        Joint Operating Agreement
 
A. Following the Completion Date the Parties shall use reasonable endeavours to agree and execute the JOA Novation with SMHPM. From the date specified in the JOA Novation, the JOA Novation shall be legally effective in accordance with its terms.
 
AA. In the event that the JOA for operations in the Block C6 portion of the Contract Area has not been executed by the Completion Date, Farmor and Farmee shall execute such JOA with SMHPM on terms substantially similar to  the JOAs  for operations in the Blocks C8, C12 and C13 portions of the Contract Area or on such other terms as the Parties agree (acting reasonably).
 
B. From the date of this Agreement, Farmee shall be deemed to be a party to the JOA in respect of the provision by the Operator of any information sent or released in any way to the parties to the JOA, and Farmor shall use all reasonable endeavours to procure the agreement of any Co-Venturer to the right of Farmee to receive such information pursuant to the terms of this Article 2.2B.
 
C. From the date of this Agreement, the Parties agree, in respect of the JOA and the Contract, to comply with the obligations set out in paragraphs 1 to 7 of Exhibit M for the duration of the JOA, the Contract and any agreements entered into that are anticipated by the JOA and or the Contract.  
 
2.3        Binding Effect
 
Without prejudice to Article 3.3 and subject to Article 3.1, Farmor and Farmee shall be bound by this Agreement as of the date hereof and shall fully perform all of their respective obligations under this Agreement. 
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2.4        Ownership
 
From the Completion Date, the Participating Interests of all parties to the Contract and JOA shall be:
 
Person	Contract
Participating
Interest (%)	JOA Participating
Interest / (Paying
Interest*) (%)	
Farmor	28	28 / 31.11	
Farmee	62	62 / 68.89	
SMHPM	10	10 / 0	
TOTAL	100	100	

*Until SMHPM elects to participate in an Exploitation Perimeter
 
2.5        Transfer of Title and Risk
 
A. On the Completion Date, title and risk in the Interests shall pass from Farmor to Farmee.
 
B. Farmee shall have no liability for any costs and no payments under this Agreement shall become due in respect of the Interests prior to the occurrence of the Completion Date, notwithstanding that Farmee agrees following the occurrence of the Completion Date to pay amounts to Farmor in respect of certain costs relating to the Interests that are incurred by Farmor prior to the Completion Date as part of the Consideration.
 
C. Save for the payment of the Consideration pursuant to the terms of this Agreement, Farmor shall be liable for and shall indemnify and hold Farmee harmless from all costs, charges, expenses, duties, losses, liabilities and obligations which Farmee pays, incurs or is liable for at any time which accrue or relate to any period prior to the Completion Date (including the Farmor Retained Liabilities) relating to the Interests.
 
D. To the extent not delivered or otherwise held by Farmee prior to the Completion Date all Data in the possession or control of Farmor (or copies of such Data) shall be made available for collection by Farmee at its own expense (it being agreed that such expense will be limited to Farmee’s logistical costs of collection and that Farmee will not be required to make any payment other than the Consideration for rights to ownership or use of the Data) within normal business hours as soon as reasonably practicable after the Completion Date.
 
ARTICLE 3
CONDITIONS PRECEDENT
 
3.1        Conditions Precedent
 
The obligations of the Parties set out in Article 2.1 and Article 4 shall be conditional upon the satisfaction or waiver (as applicable) of the following, collectively called the “ Conditions Precedent ”:
 
(i)   issuance of a letter of Approval by the Mauritanian Minister of Petroleum, Energy and Mines 
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approving the transfer of the Interests from Farmor to Farmee to the Contract (or such approval being deemed effective pursuant to the Contract) and written approval of such Minister designating Farmee as Operator of the Contract Area with effect from the Operator Transfer Date;
 
(ii)  receipt by the Parties of a waiver or other evidence in writing of the expiration or non-exercise of any Preferential Right and written approval of the proposed Assignment and transfer of Operatorship to Farmee by SMHPM;
 
(iii) the execution and (if applicable) delivery of the Assignment in respect of each of the Interests by the Farmor and the Farmee
 
(iv) receipt of written confirmation from SMHPM approving the transfer of the Interests in the JOA from Farmor to Farmee;
 
(v)  receipt of written evidence by the Parties of the satisfaction of any additional regulatory requirements in Mauritania which are imposed on either Party, including any requirements relating to anti-trust issues; and
 
(vi) no notice of termination having been given in accordance with Article 3.3C.
 
3.2        Acts to be Performed
 
A. Subject to Article 3.2D, each party shall use commercially reasonable efforts to execute all documents, and do and procure to be done all such acts and things as are reasonably within its power to ensure the Conditions Precedent are satisfied as soon as is reasonably practicable after execution of this Agreement.
 
B. The Parties shall keep each other informed of progress towards the satisfaction of the Conditions Precedent and shall notify the other as soon as is reasonably practicable after it becomes aware that a Condition Precedent has been satisfied or, as the case may be, validly waived.
 
C. Waiver of any of the Conditions Precedent (whether in whole or in part) shall require the mutual consent of Farmor and Farmee in writing.
 
D. The Parties agree that:
 
(i)   no formal request shall be sought from the Mauritanian Minister of Petroleum, Energy and Mines to approve the transfer of the Interests from Farmor to Farmee and designating Farmor as Operator of the Contract Area from Operator Transfer Date until such time as all Conditions Precedent set out in Article 3.1 have been satisfied or waived in accordance with Article 3.2C (other than the Condition Precedent set out in Article 3.1(i).
 
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E. In the event that the transfer of the Interests becomes effective prior to the Completion Date, from the date on which the transfer of the Interests becomes effective until the Completion Date:
 
(i)   to the extent permitted under Laws/Regulation and the relevant Contract and JOA, Farmee shall hold the Interests for the benefit of the Farmor;
 
(ii)  the Farmee shall consult with Farmor in the exercise of any rights in relation to the Interests; and
 
(iii) the Farmor shall be liable for and shall indemnify and hold Farmee harmless from all costs, charges, expenses, duties, losses, liabilities and obligations which Farmee pays, incurs or is liable in relation to the Interests (including any amounts for which Farmee would otherwise be liable under the relevant Assignment or JOA Novation) during such period,
 
provided that if it becomes impossible to satisfy the remaining Conditions Precedent the Farmee will reassign the Interests to Farmor and the Parties will execute all documents necessary for such reassignment in substantially the same form as those pertaining to the original assignment and will cooperate in obtaining any required approvals for such reassignment.
 
3.3        Termination
 
A. Notwithstanding any period of Force Majeure under Article 12, if each of the Conditions Precedent are not satisfied (or waived pursuant to Article 3.2C) within two hundred seventy (270) days of the date of this Agreement, then either Party shall have the right to terminate this Agreement on notice pursuant to Article 3.3C.
 
B. Notwithstanding any other provision of this Agreement, if, prior to the Completion Date, Farmor or any other Person is or becomes the subject of any investigation, inquiry or enforcement proceeding by a governmental, administrative or regulatory body regarding an offence or alleged offence relating to the Interests under any of the Anti-Corruption Laws and Obligations that is likely to result in a material, detrimental impact to the Interests, the Interest Documents or this Agreement, Farmee shall have the right to terminate this Agreement on notice pursuant to Article 3.3C.
 
BB. Notwithstanding any other provision of this Agreement, the Farmee shall have the right to terminate this Agreement on notice pursuant to Article 3.3C, if:
 
(i)   any of the Farmor Warranties was at the date of this Agreement, or has since become, untrue in any material respect and is likely to prevent or inhibit the ability of the Farmee to take title of the Interests; or
 
(ii)  the Farmor is in breach of any material undertaking in this Agreement and the breach is incapable of being cured before the Completion Date, or has continued without cure for a period of 30 days after the notice of breach from the Farmee or remains uncured two (2) days prior to the Completion Date.
 
C. A Party may terminate this Agreement pursuant to Articles 3.3A, 3.3B, 3.3BB, 3.3D or 3.3E by giving ten (10) days notice to the other Party and upon the expiry of such notice (unless
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withdrawn) this Agreement will terminate and neither Farmor nor Farmee shall have any liability under this Agreement to the other save for its obligations under the Surviving Provisions which shall survive any such termination and save for any liability for breach of this Agreement prior to the date of any such termination.  In the event that termination occurs after the date of the letter of approval by the Mauritanian Minister of Petroleum, Energy and Mines approving the transfer of the Interests from Farmor to Farmee and/or designating Farmor as Operator of the Contract Area, Farmee will reassign the Interests to Farmor. Accordingly, as soon as practical following the notice pursuant to this Article 3.3C, the Parties will execute all documents necessary for such reassignment in substantially the same form as those pertaining to the original assignment and will cooperate in obtaining any required Government approval for such reassignment.
 
D. If the Government imposes conditions for approval of the assignment and transfer of the Interests or transition of Operatorship as contemplated hereunder materially in excess of those which are usually imposed in similar circumstances or if such approval contains unusual and onerous conditions which any affected Party is not willing to accept, then the affected Party shall have the right to terminate this Agreement on notice pursuant to Article 3.3C.
 
E. Notwithstanding any period of Force Majeure under Article 12 if either Party receives notice from the Government of a rejection of the Assignment, then either Party shall have the right to terminate this Agreement on notice pursuant to Article 3.3C.
 
3.4        Guarantees
 
A.  If permitted under the Contract (or otherwise agreed with the Mauritanian Minister of Petroleum, Energy and Mines, the Parties having used reasonable endeavours to procure such agreement) each Party shall provide the Mauritanian Minister of Petroleum, Energy and Mines with a guarantee for its Paying Interest share of the amount required under the Contract. If not so permitted or agreed, Farmee, as the new Operator, shall replace the guarantee that Farmor previously provided to the Mauritanian Minister of Petroleum, Energy and Mines as Operator, and Farmor shall provide Farmee with a back-to-back guarantee for Farmor’s Paying Interest share under the JOA of the amount required under the Contract. The obligations of the Parties under this Article 3.4A shall take effect from the Operator Transfer Date.  From the Completion Date until the Operation Transfer Date, Farmee shall provide Farmor, if requested by Farmor, with a back-to-back parent company guarantee for Farmee’s Paying Interest share under the JOA of the amount required under the Contract.
 
B.  Farmee shall provide Farmor with a parent company Guarantee from a creditworthy Affiliate for Farmee’s payment of the Consideration under this Agreement in a form mutually agreed by the Parties   on or before the Completion Date, but in no event earlier than five (5)
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Business Days after the signing of this Agreement. Farmor acknowledges that for the purposes of this Article 3.4B, BP Exploration Operating Company Limited is a creditworthy Affiliate.
 
ARTICLE 4
CONSIDERATION
 
4.1        Consideration
 
As consideration for the assignment and transfer of the Interests Farmee agrees to pay each of the:
 
(i)     Initial Payment;
 
(ii)    Interim Period Costs;
 
(iii)   Exploration & Appraisal Carry;
 
(iv)   Development Carry; and
 
(v)    Success Fee,
 
(together the “Consideration”) subject to such payments becoming due and payable pursuant to the terms of this Agreement.
 
4.2        Initial Payment
 
Within the five (5) days following the Completion Date, the sum of one hundred twenty million Dollars (US$ 120,000,000) (“ Initial Payment ”)   shall be paid by Farmee to Farmor by electronic transfer in immediately available funds into Farmor’s Account.
 
4.3        Interim Period Costs
 
A. Farmor shall keep Farmee advised of the costs expended during the Interim Period.  Specifically, Farmor shall provide Farmee with a written statement of the amount of the Dollar balance resulting from the initial calculation of the Interim Period Costs (the “ Monthly   Interim Costs Completion Statement ”) no later than thirty (30) days following the end of each calendar month during the Interim Period. Farmor and Farmee agree that if the information required for such timely preparation of a Monthly Interim Costs Completion Statement is not available, Farmor’s good faith estimate of such information shall be substituted.
 
B. For the avoidance of doubt, Farmee shall not be required to pay the Farmor Retained Liabilities and the Farmor Retained Liabilities shall not be included in the Monthly Interim Costs Completion Statement.
 
C. Within sixty (60) days after the Completion Date, or within such other period as may be agreed in writing by the Parties, Farmor shall provide Farmee with a written statement giving the final amount of the Interim Period Costs (the “ Final Completion Statement ”).  Upon Farmee request, Farmor shall provide Farmee with copies of reports, billing statements and
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correspondence and any other relevant documentation in the Farmor’s possession in support of the Final Completion Statement within ten (10) Business Days of such request, which shall be made no later than ten (10) Business Days from the date the Final Completion Statement is supplied to Farmee.  Farmee shall have the right, for a period of ninety (90) days following the date of delivery of the Final Completion Statement, to audit the Interim Period Costs on prior notice and during reasonable business hours in the Farmor’s offices; and Farmor shall provide such confirmation of the said Interim Period Costs as may be requested by Farmee in order to confirm the amount of Interim Period Costs. Farmor and Farmee shall endeavor in good faith to resolve any item of adjustment to the Interim Period Costs in the Final Completion Statement within  one hundred twenty (120) days following the date of delivery of the Final Completion Statement.  The agreed amount of the Interim Period Costs shall be subject to no adjustment or amendment. In the event that the Farmor and Farmee are unable to agree upon any item of adjustment within the above period, such amount shall be determined in accordance with the procedures for settling disputed invoices under the JOA.
 
D. Farmor shall provide Farmee with copies of all operator reports, billing statements and correspondence and any other relevant documentation in support of the Monthly Interim Costs Completion Statement and the Final Completion Statement at the same time such Statements are supplied.
 
E. The Interim Period Costs shall be paid by Farmee to Farmor within five (5) Business Days of the delivery of the Final Completion Statement (pursuant to this Article 4.3) by electronic transfer in immediately available funds into Farmor’s Account, subject to Farmee’s audit rights under this Article 4.3 and without prejudice to Farmee’s subsequent rights of audit and dispute.
 
4.4        Exploration and Appraisal Carry
 
A. Subject to Article 4.4C, Farmee shall pay the JOA Paying Interest share (as set out in Article 2.4) of costs otherwise due and payable by Farmor after the Effective Date under the terms of the JOA pursuant to an approved work programme and budget thereunder in connection with all activities other than those activities covered under Article 4.5 (the “ Exploration and Appraisal Carry ”) until the earlier of:  (i) the date on which such costs paid by Farmee plus such costs paid by BP Senegal pursuant to exploration and appraisal carry under the Senegal Agreement exceed an amount equal in the aggregate to the sum of two hundred twenty one million Dollars ($US 221,000,000) carried by Farmee in the Contract Area and by BP Senegal in the Senegal Area under the Senegal Agreement, and (ii) 31 December 2022.
 
B. If the total amount of the Exploration and Appraisal Carry paid pursuant to Article 4.4A by Farmee in the aggregate in the Contract Area and the exploration and appraisal carry paid by BP Senegal under the Senegal Agreement) in the Senegal Area as of 31 December 2022 is less than two hundred twenty one million Dollars ($US 221,000,000) then the difference shall be paid no later than 1 February 2023 at Farmor’s election either by Farmee to Farmor by
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electronic transfer in immediately available funds into Farmor’s Account or alternatively a portion of the difference paid under the Senegal Agreement with the balance being paid to Farmor pursuant to this Article 4.4B.
 
C. If satisfaction of the Conditions (as such term is defined in the Senegal Agreement) does not occur by the Longstop Date (as such term is defined in the Senegal Agreement) , then Farmee shall pay the Exploration and Appraisal Carry until the earlier of:  (i) the date on which such costs paid by Farmee exceed an amount equal in the aggregate to the sum of one hundred sixty-three million eight hundred thousand Dollars ($US 163,800,000) carried by Farmee in the Contract Area and (ii) 31 December 2022.
 
D. If the total amount of the Exploration and Appraisal Carry paid pursuant to Article 4.4C by Farmee in the aggregate in the Contract Area as of 31 December 2022 is less than one hundred sixty-three million eight hundred thousand Dollars ($US 163,800,000), then the difference shall be paid no later than 1 February 2023 at Farmor’s election by Farmee to Farmor by electronic transfer in immediately available funds into Farmor’s Account.
 
E.  In the event that the maximum amount payable by BP Senegal pursuant to clause 8.3(A)(i) of the Senegal Agreement is reduced in accordance with clause 8.7(A) of the Senegal Agreement, then the maximum amount payable by Farmee pursuant to Article 4.4A and 4.4B shall be reduced by an equivalent amount, provided that, if such adjustment under the Senegal Agreement is reversed pursuant to clause 8.7(D) of the Senegal Agreement, then such adjustment under this Article 4.4E shall also be reversed and an appropriate adjusting payment made. 
 
4.5        Development Carry
 
A.   Subject to Article 4.5B, Farmee shall pay the JOA Paying Interest share (as set out in Article 2.4) of costs, that are properly incurred and due and payable by Farmor after the Effective Date under the terms of the JOA pursuant to an approved work programme and budget thereunder in connection with achieving Commercial Production of Hydrocarbons (as defined under the Contract) from the Tortue Discovery Area as shown in Exhibit A, Part 1, including the Firm Work Programme (Development) in Exhibit J 2, or any alternative development in the Contract Area (the “ Development Carry ”) until the earlier of:  (i) the date on which such costs paid by the Farmee plus such costs paid by BP Senegal pursuant to the Senegal Agreement exceed the sum of five hundred thirty-three million four hundred thousand Dollars (US $ 533,400,000) or (ii) the date first Commercial Production from a development within an Exploitation Perimeter is achieved from the Contract Area and/or Senegal Area.
 
B.   If satisfaction of the Conditions (as such term is defined under the Senegal Agreement) does not occur by the Longstop Date (as such term is defined under the Senegal
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Agreement), then Farmee shall pay the Development Carry until the earlier of:  (i) the date on which such costs paid by the Farmee exceed the sum of three hundred fifty million Dollars (US $ 350,000,000) or (ii) the date first Commercial Production from a development within an Exploitation Perimeter is achieved from the Contract Area.
 
C.   For the avoidance of any doubt, there shall be no double-counting of amounts payable under Article 4.4 and Article 4.5 with the intention that Farmee shall not be required to pay more than once in respect of the same costs.
 
D.   In the event that the maximum amount payable by BP Senegal pursuant to clause 8.4(A)(i) of the Senegal Agreement is reduced in accordance with clause 8.7(A) of the Senegal Agreement, then the maximum amount payable by Farmee pursuant to Article 4.5A shall be reduced by an equivalent amount, provided that, if such adjustment under the Senegal Agreement is reversed pursuant to clause 8.7(D) of the Senegal Agreement, then such adjustment under this Article 4.5D shall also be reversed and an appropriate adjusting payment made.
 
4.6        Success Fee
 
A.      The Success Fee in respect of each Eligible Discovery shall be paid by Farmee, or Farmee’s Affiliate, to Farmor, or Farmor’s Affiliate, by electronic transfer in immediately available funds into Farmor’s Account no later than thirty (30) days following the end of each Quarter after the date Commercial Production exceeds twenty thousand Barrels per day (20mbd) from such Eligible Discovery and in respect of each Barrel (as defined under the Contract) of gross production of liquid Hydrocarbons (as defined under the Contract) in the natural state or obtained from Natural Gas by condensation or separation with an API gravity equal to or greater than 22.3°, but excluding LNG, produced from such Eligible Discovery in the immediately preceding Quarter.
 
B.      The obligation to pay a Success Fee in respect of production from each Eligible Discovery shall expire fifteen (15) years after the date of first production from such Eligible Discovery.
 
C.      The obligation to pay a Success Fee in respect of production from all Eligible Discoveries shall expire on the date the aggregate gross cumulative production from all Eligible Discoveries and from all Eligible Discoveries (as such term is defined in the Senegal Agreement) exceeds one billion Barrels (1bnbbl).
 
D.      If an index is required to be used in the calculation of Brent, and such index ceases to be published, either Farmor or Farmee may request the adoption of such substitute index as most closely resembles the original index prior to it ceasing to be published or changing. If the Parties are unable to agree within sixty (60) days of such request, the matter shall be referred for determination under Article 11.2.
 
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E.      To the extent that a Success Fee is payable by BP Senegal under the Senegal Agreement and this Agreement in respect of the same discovery, there shall be no double-counting of amounts payable under the Senegal Agreement with amounts payable under this Agreement.
 
4.7        Other Costs and Cost Recovery
 
A. Payment of any amount payable by Farmee on Farmor’s behalf under Article 4.4A or 4.5A shall be made by Farmee after the Completion Date and following notification by Operator to Farmee that such amount is due and payable under the terms of the JOA.
 
B.  Except to the extent Farmee becomes liable to pay any costs on behalf of Farmor under Article 4.4 or 4.5, on and from the Effective Date each Party shall assume and be liable for its Participating Interest share of costs incurred under the Contract or JOA pursuant to their terms, with Farmee’s share of such costs to be payable from the Completion Date.   Any costs for which the Farmee would otherwise be liable under the terms of the JOA between the Effective Date and the Completion Date shall be paid by Farmor on behalf of Farmee and shall be paid to Farmor after the Completion Date pursuant to Article 4.3.
 
C. Each Party shall be entitled to recover its Participating Interest share of costs incurred under the Contract upon commencement of production from the relevant portion of the Contract Area regardless of whether the costs were incurred before or after the Effective Date. For the avoidance of doubt, such Participating Interest share shall be the Participating Interest held at the time such costs become recoverable under the Contract after the commencement of production and to the extent that the either Party (the " Receiving Party ")   receives the Participating Interest share of costs that should otherwise have been paid to the other Party (the " Entitled Party "), the Receiving Party shall pay such sums to the Entitled Party within five (5) Business Days of receipt thereof.
 
ARTICLE 5
OBLIGATIONS AND LIABILITIES
 
5.1        Acceptance of Prior Terms
 
Subject to the Farmor Warranties and applicable laws, Farmee hereby ratifies, confirms and accepts the terms of the Contract and the JOA.
 
5.2        Firm Work Programme (Exploration and Appraisal) and Firm Work Programme (Development)
 
Notwithstanding articles 5.9, 6.1(D) and 6.1(E) of the JOA, the Parties agree to participate in the Firm Work Programme (Exploration and Appraisal) and Firm Work Programme (Development), unless otherwise mutually agreed.  The Parties will support an amendment to
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the Work Program and Budget approved under the JOA to accomplish the Firm Work Programme (Exploration and Appraisal) and Firm Work Programme (Development).
 
5.4        Obligations in Respect of Tortue Development
 
Farmee supports the Tortue development concept for phase 1 proposed and supported by Farmor and an indicative work program aimed to reach a final investment decision (" FID ")   by the end of 2017.  Notwithstanding the foregoing, in Farmee’s view the following key decisions for the first phase development of Tortue require study or screening for the potential full field development (" FFD ")   solution: (i) location of breakwater and pre-treatment facility; (ii) scope of phase 1 pre-treatment facility; (iii) breakwater configuration capable of expansion; and (iv) LNG cooling solution capable of expansion.  These key decisions will be informed by the following key activities: (i) metocean survey/ report results; (ii) G&G site survey results at breakwater and Tortue sites; (iii) agreement with a third party contractor for liquefaction services; (iv) FFD concept screening to allow expansion of LNG facilities; (v) FFD concept process safety, environmental studies and operations philosophy; and (vi) FFD flow assurance and water breakthrough risk mitigation studies.  Farmee proposes (and Farmor agrees) that these key decisions and their supporting studies and surveys are completed by the end of first quarter 2017 so they are able to feed into a prompt FID decision. For the avoidance of doubt, each Party shall have complete discretion (to be exercised as it sees fit) in how it exercises its vote or decision under Interest Documents in respect of the FID decision.
 
5.5        Operatorship
 
A.  Subject to the Contract and Laws/Regulations, the Parties shall support and vote and campaign in favor of the following to be effective on the Operator Transfer Date:
 
(i)      Farmee to assume the role of Operator in respect of all evaluation/appraisal (including preparation of the appraisal plan), development, exploitation and production activities under the Contract upon the Completion Date;
 
(ii)     Farmee to perform the role of operator in respect of all Exploitation Perimeters (as defined under the Contract) in the Contract Area, including any unit which includes any Exploitation Perimeter in the Contract Area; and
 
(iii)    Farmor to perform the role of technical operator in respect of all exploration activities, including exploration drilling, under the Contract as set out in the JOA Novation.
 
B.  The provisions in Article 5.5A shall be reflected in the JOA Novation attached as Exhibit D.
 
C.  The agreed arrangements for the safe, smooth and efficient transition of the role of operator
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under the Contract and JOA are contained in Exhibit K.
 
5.6        Option to Sell LNG
 
A.  From the Completion Date, Farmee, as Operator, offers to work with Farmor and the other parties to the Interest Documents in a possible Tortue development, to develop a LNG marketing strategy and to use its experience and relationships in the market to jointly sell the LNG produced from the Tortue development.  Farmee is an experienced LNG industry player and already undertakes this role as the operator of other LNG projects also governed by a production sharing contract. 
 
B. Additionally, Farmee’s LNG trading business will offer to purchase some or all of the LNG produced from the Tortue development on a free on board “FoB” basis through a long term LNG purchase agreement.  Farmee’s LNG trading business believe the natural market for this LNG is in Europe and would plan to offer to purchase on the basis of delivery to the European market. Farmee’s LNG trading business has industry leading trading capability and track record, and will attempt to divert purchased LNG cargos to other more attractive markets outside of Europe where possible, the benefits of any upside value achieved (net of shipping and regasification costs) will be shared equally between buyer and seller.
 
C.  The foregoing is subject to applicable law joint selling limitations.
 
5.7        The provisions of this Article 5 shall only become effective upon the Completion Date.
 
ARTICLE 6
INTERIM PERIOD OBLIGATIONS
 
6.1        Farmor Obligations
 
During the Interim Period, Farmor shall:
 
(i)      having notified Farmee in advance of the subject matter thereof, consult with Farmee in relation to any material decision (including any voting matter under the Interest Documents) in connection with the Interests (including decisions relating to the location and timing of any exploration wells), and take due consideration of Farmee’s representations in respect thereof;
 
(ii)     consult with Farmee in relation to the negotiation of a term sheet and any definitive agreements with a third party liquefaction contractor, and take due consideration of Farmee’s representations in respect thereof.  Additionally Farmor will take all steps within its control to afford Farmee the opportunity to attend and participate in such negotiations;
 
(iii)    not incur, commit to incur or approve or amend any work programme, budget, expenditure or capital commitment  relating to the Interests involving expenditure or agree to do any of the foregoing, in any case other than:
 
(a)   any expenditure permitted and approved under the JOA and disclosed to Farmee at the date of this Agreement;
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(b)   any expenditure required to carry out the Firm Work Programme (Exploration and Appraisal);
 
(c)   any expenditure required to carry out the Firm Work Programme (Development);
 
(d)   any such expenditure in respect of which Farmee has given its prior approval (not to be unreasonably withheld or delayed)
 
(e)   any expenditure necessitated by any emergency (in which case Farmor shall consult with Farmee to the extent practicable in the circumstances);
 
(iii) conduct operations regarding the Interests in the ordinary and usual course, past practice and with the intention that the same be protected and maintained in accordance with Good Industry Practice and all applicable laws;
 
(iv) not (by act or omission) breach any of the provisions of the Contract or JOA or new agreements concluded in the Interim Period in accordance with this Article (and notify Farmee in a timely manner of any facts or circumstances of which it is aware or becomes aware which indicate that there has been a breach of any of the Contract or JOA by any other party or that such a breach by Farmor has occurred);
 
(v) take all steps within its control (and Farmor shall procure that its Affiliates take all steps within their control) to maintain and renew all governmental licences, permits, authorizations, consents and permissions necessary to own and operate the Interests;
 
(vi) not amend, terminate or replace any of the Contract, JOA or new agreements concluded in the Interim Period in accordance with this Article or waive or surrender any right or grant any consent thereunder, or agree to do any of the foregoing, without the written consent of Farmee (such consent shall not be unreasonably withheld or delayed);
 
(vii) not, without Farmee’s written consent (not to be unreasonably withheld or delayed), create any Encumbrance in relation to, sell, lease or otherwise dispose of all or any part of, the Interests, or purport to or agree to do any of the same;
 
(viii) in respect of the Interests, not enter into or become a party to any new licences, operating agreements (other than the JOA for operations in the Block C6 portion of the Contract Area on terms substantially similar to the JOAs for operations in the Block C8, C12 and C13 portions of the Contract Area), farm-in or farm-out agreements, unitization agreements, liquefaction agreements, charterparties, development agreement or any other agreement or undertaking or any of them (by whatever name called) or trade, relinquish, surrender, sell, assign, transfer or amend the Interests (or agree to do any of the foregoing in the future) without the prior written approval of Farmee (such approval not to be unreasonably withheld or delayed); and
 
(vii)  keep Farmee informed in a timely manner of all material matters in relation to the Interests,
 
(viii) to the maximum extent permitted by law and confidentiality obligations under agreements, provide Farmee with copies of all communications with the Government,
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Mauritanian Minister of Petroleum, Energy and Mines and SMHPM in relation to the Interest Documents,
 
and Farmor undertakes to notify Farmee in writing promptly if it or any of its Affiliates becomes aware of any circumstance arising after the date of this Agreement which is or is reasonably likely to result in a breach of any of the covenants in this Article 6.1.
 
ARTICLE 7
WARRANTIES
 
7.1        Farmor’s Representations and Warranties
 
Subject to the provisions of this Article 7, and save as disclosed under the terms of the Farmor Disclosure Letter, Farmor warrants and undertakes to Farmee as at the date of this Agreement that the Farmor Warranties and the warranty at paragraph 1 of Exhibit M are true and accurate in all respects, and the Farmor Warranties and the warranty at paragraph 1 of Exhibit M shall be deemed to be repeated at the Completion Date.
 
7.2        Farmee’s Representations and Warranties
 
Farmee warrants and undertakes to Farmor as at the date of this Agreement that the Farmee Warranties and the warranty at paragraph 1 of Exhibit M are true and accurate in all respects, and the Farmee Warranties and the warranty at paragraph 1 of Exhibit M shall be deemed to be repeated at the Completion Date.
 
7.3        Breach of Warranty
 
A. Each of the Parties agrees to indemnify and hold the other Party harmless against any costs, charges, expenses, duties, losses, liabilities and obligations which such other Party pays, suffers or is liable for at any time which arise out of or in connection with the breach by the indemnifying Party of, in the case of the Farmor, any of the Farmor Warranties, or, in the case of the Farmee, any of the Farmee Warranties.
 
B. Farmor shall have no liability in respect of any claim made by Farmee for a breach of the Farmor Warranties, and Farmee shall have no liability in respect of any claim made by Farmor for a breach of Farmee Warranties, unless such claim:
 
(i)   equals or exceeds one million Dollars (US$1,000,000); or
 
(ii)  when aggregated with all other valid claims the Party concerned may have against the other Party that are each of a value under one million Dollars (US$1,000,000), would mean such aggregate equals or exceeds one million Dollars (US$1,000,000),
 
and in either case the Party concerned shall be entitled to recover the whole amount of the
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relevant claim(s) not only the amount the relevant claim(s) (alone or aggregated) exceed one million Dollars (US$1,000,000).
 
C.  The Farmor shall not be liable in respect of a claim for breach of a Farmor Warranty set out in paragraphs 15.1 or 15.2 of Exhibit H or the warranty at paragraph 1 of Exhibit M to the extent that, as at the date of this Agreement, the Farmee was actually aware: (i) of the facts or circumstances giving rise to the claim for breach of such Farmor Warranty or the warranty set out at paragraph 1 of Exhibit M; and (ii) that such facts or circumstances would give rise to a claim for breach of such Farmor Warranty or the warranty at paragraph 1 of Exhibit M.
 
7.4        Undertakings in relation to breaches
 
A. Farmor undertakes that:
 
(i)      it shall not at any time before the Completion Date do (or permit or suffer to subsist or be done) any act or thing which would constitute a breach of any of the Farmor Warranties or the warranty at paragraph 1 of Exhibit M or which would make any of the Farmor Warranties untrue or misleading at any time; and
 
(ii)      upon becoming aware before the Completion Date of the actual or impending occurrence or non-occurrence of any matter, event or circumstance (including any omission to act) which:
 
(a)    would or might reasonably be expected to cause or constitute a breach of any Farmor Warranty or the warranty at paragraph 1 of Exhibit M;
 
(b)    would or might reasonably be expected to make any of the Farmor Warranties or the warranty at paragraph 1 of Exhibit M untrue or misleading;
 
(c)    would have caused or constituted a breach of any Farmor Warranty or the warranty at paragraph 1 of Exhibit M had it been known to Farmor before the date of this Agreement; or
 
(d)    would or might reasonably be expected to adversely affect (or has so affected) the Interests,
 
it will immediately give Farmee notice of such matter, event or circumstance with sufficient details to enable Farmee accurately to assess its impact.
 
B. Farmee undertakes that:
 
(i)      it shall not at any time before the Completion Date do (or permit or suffer to subsist or be done) any act or thing which would constitute a breach of any of the Farmee Warranties or the warranty at paragraph 1 of Exhibit M or which would make any of the Farmee Warranties or the warranty at paragraph 1 of Exhibit M untrue or misleading at any time; and
 
(ii)     upon becoming aware before the Completion Date of the actual or impending occurrence or non-occurrence of any matter, event or circumstance (including any omission to act) which:
 
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(a)    would or might reasonably be expected to cause or constitute a breach of any Farmee Warranty or the warranty at paragraph 1 of Exhibit M;
 
(b)    would or might reasonably be expected to make any of the Farmee Warranties or the warranty at paragraph 1 of Exhibit M untrue or misleading;
 
(c)    would have caused or constituted a breach of any Farmee Warranty or the warranty at paragraph 1 of Exhibit M had it been known to Farmee before the date of this Agreement; or
 
(d)    would or might reasonably be expected to adversely affect (or has so affected) the Interests,
 
it will immediately give Farmor notice of such matter, event or circumstance with sufficient details to enable Farmor accurately to assess its impact. 
 
7.5        Disclaimer of Other Representations and Warranties
 
A. Except for the Farmor Warranties and the warranty in paragraph 1 of Exhibit M, Farmor makes no, and disclaims any, warranty or representation of any kind, either express, implied, statutory, or otherwise, including, the accuracy or completeness of any data, reports, records, projections, information, or materials now, heretofore, or hereafter furnished or made available to Farmee in connection with this Agreement.
 
B. Except for the Farmee Warranties and the warranty in paragraph 1 of Exhibit M, Farmee makes no, and disclaims any, warranty or representation of any kind, either express, implied, statutory, or otherwise, including, without limitation, the accuracy or completeness of any data, reports, records, projections, information, or materials now, heretofore, or hereafter furnished or made available to Farmor in connection with this Agreement.
 
7.6        Fraud and Wilful Concealment
 
Notwithstanding anything to the contrary herein, nothing in this Agreement shall limit any Party’s liability for fraud or willful concealment.
 
7.7        Set-off
 
Farmee is hereby authorized and entitled at any time and from time to time, to the fullest extent permitted by law, to withhold and set-off from any payment otherwise due to be made to Farmor pursuant to Articles 4.3 to 4.6 of this Agreement or from any payment due to be made by BP Senegal pursuant to clauses 6 to 8 of the Senegal Agreement an amount equal to the amount owing pursuant to any and all Farmor Payment Failures.
 
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ARTICLE 8
TAX
 
8.1        Tax Obligations
 
Each Party shall be responsible for reporting and discharging its own Tax measured by the profit, gain or income of the Party and the satisfaction of such Party’s share of all contract obligations under the Contract and under this Agreement.  Each Party shall protect, defend and indemnify each other Party from any and all loss, cost or liability arising from the indemnifying Party’s failure to report and discharge such taxes or satisfy such obligations.  The Parties intend that all income under the Interest Documents will be allocated by the Government tax authorities to the Parties based on the share of income actually received by each Party.  The Parties intend that all Tax benefits (including deductions, depreciation, credits and capitalization) with respect to joint operating expenditures (whether incurred by carry or otherwise) made by the Parties hereunder or under the Interest Documents will be allocated by the Government tax authorities to the Parties based on their respective JOA Participating Interest share of each such Tax item.  If such allocation is not accomplished due to the application of the Laws/Regulations or other Government action, the Parties shall attempt to adopt mutually agreeable arrangements that will allow the Parties to achieve the financial results intended.  Operator shall provide each Party, in a timely manner and at such Party’s sole expense, with such information with respect to Joint Operations as such Party may reasonably request for preparation of its tax returns or responding to any audit or other tax proceeding.
 
8.2        Secondary tax liabilities
 
Each Party shall indemnify the other Party in respect of Tax demanded from the other Party which is the primary liability of the first mentioned Party.
 
8.3        United States Tax Election
 
A. If, for United States federal income tax purposes, this Agreement and the operations under this Agreement are regarded as a partnership and if the Parties have not agreed to form a tax partnership, each Party elects to be excluded from the application of all of the provisions of Subchapter “K”, Chapter 1, Subtitle “A” of the United States Internal Revenue Code of 1986, as amended (the “Code”), to the extent permitted and authorized by Section 761(a) of the Code and the regulations promulgated under the Code.  Operator, if it is a U.S. Party, is authorized and directed to execute and file for each Party such evidence of this election as may be required by the Internal Revenue Service, including all of the returns, statements, and data required by United States Treasury Regulations Sections 1.761-2 and 1.6031(a)-1(b)(5) and shall provide a copy thereof to each U.S. Party.  However, if Operator is not a U.S. Party, the Party who holds
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the greatest Participating Interest among the U.S. Parties shall fulfill the obligations of Operator under this Article.  Should there be any requirement that any Party give further evidence of this election, each Party shall execute such documents and furnish such other evidence as may be required by the Internal Revenue Service or as may be necessary to evidence this election.
 
B. No US Party shall give any notice or take any other action inconsistent with the foregoing election.  If any income tax laws of any state or other political subdivision of the United States or any future income tax laws of the United States or any such political subdivision contain provisions similar to those in Subchapter “K”, Chapter 1, Subtitle “A” of the Code, under which an election similar to that provided by Section 761(a) of the Code is permitted, each Party shall make such election as may be permitted or required by such laws.  In making the foregoing election or elections, each U.S. Party states that the income derived by it from operations under this Agreement can be adequately determined without the computation of partnership taxable income.
 
C.  Unless approved by every Non-U.S. Party, no activity shall be conducted under this Agreement that would cause any Non-U.S. Party to be deemed to be engaged in a trade or business within the United States under United States income tax laws and regulations.
 
8.4        Capital Gains Tax
 
Farmor shall pay, and shall indemnify and hold Farmee harmless against any liability for any capital gains tax (or equivalent tax) which may be, or become, payable in connection with the sale, assignment or transfer of the Interests and in respect of any costs (including reasonable legal costs), expenses, loss or damage occasioned by its failure to pay, or any delay in paying, such tax.
 
8.5        Transfer Taxes
 
Farmee shall be responsible for payment in a timely fashion of any and all transfer taxes, such as stamp duties and taxes (or equivalent duties and taxes) (including interest, penalties and/or fines thereof) (the “ Transfer Taxes ”) payable on or in respect of the assignment and transfer of the Interests including the execution and enforcement of this Agreement and shall indemnify and hold Farmor harmless in respect of any costs (including reasonable legal costs), expenses, loss or damage occasioned by its failure to pay, or any delay in paying, such Transfer Taxes.
 
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ARTICLE 9
CONFIDENTIALITY
 
9.1        Except as otherwise provided in the Contract and the JOA, each Party agrees that the existence of and all terms of this Agreement and all information disclosed under this Agreement by either Party (except information in the public domain or lawfully in possession of a Party prior to the date of this Agreement) shall be considered confidential information and shall not be disclosed to any other person or entity without the prior written consent of the other Party. This obligation of confidentiality shall remain in force during the term of the Contract and for a period of three (3) years thereafter. Notwithstanding the foregoing, confidential information may be disclosed without consent and without violating the obligations contained in this Article 9 in the following circumstances:
 
(i)         to an Affiliate provided the Affiliate is bound to the provisions of this Article 9 and the Party disclosing is responsible for the violation of an Affiliate;
 
(ii)        to a governmental agency or other entity when required by the Contract;
 
(iii)       to the extent such information is required to be furnished in compliance with the applicable Laws/Regulations, or pursuant to any legal proceedings or because of any order of any court binding upon a Party;
 
(iv)       to attorneys engaged, or proposed to be engaged, by any Party where disclosure of such information is essential to such attorneys' work for such Party and such attorneys are bound by an obligation of confidentiality;
 
(v)        to contractors and consultants engaged, or proposed to be engaged, by any Party where disclosure of such information is essential to such contractor’s or consultant’s work for such Party;
 
(vi)       to a bank or other financial institution to the extent appropriate to a Party arranging for funding;
 
(vii)      to the extent such information must be disclosed pursuant to any rules or requirements of any government or stock exchange having jurisdiction over such Party, or its Affiliates; provided that such Party shall comply with the requirements of Article 14.10 hereunder;
 
(viii)     to its respective employees, subject to each Party taking sufficient precautions to ensure such information is kept confidential;
 
(ix)       to the other parties to the Contract and the JOA and the Government solely to the extent as may be required in connection with the Preferential Rights to satisfy the Conditions Precedent; and
 
(x)        to the other parties, including the Government of the Republic of Senegal, to the Hydrocarbon Exploration and Production Sharing Contract granted by the Republic of Senegal dated January 17, 2012 covering the Saint Louis Offshore Profond Block, and the Hydrocarbon Exploration and Production Sharing Contract granted by the Republic of Senegal dated January 17, 2012 covering the Cayar Offshore Profond Block solely
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to the extent as may be required to satisfy the conditions precedent specified in that certain Farmout Agreement concerning the Saint-Louis Offshore Profond Block and the Cayar Offshore Profond Block, Offshore Senegal between Kosmos Energy Senegal and Farmee of even date with this Agreement. 
 
9.2        Disclosure as pursuant to Articles 9.1(v) and (vi) shall not be made unless prior to such disclosure the disclosing Party has obtained a written undertaking from the recipient party to keep the information strictly confidential for at least as long as the period set out above and to use the information for the sole purpose described in Articles 9.1(v) and (vi), whichever is applicable, with respect to the disclosing Party.
 
ARTICLE 10
NOTICES 
 
A. All notices authorized or required between the Parties by any of the provisions of this Agreement shall be:
 
(i) in writing (in English) and addressed to the relevant Party as set out in this Article 10.A (unless such party gives notice in writing of a change of address or addressee as set out below);
 
(ii) must be signed or in the case of a facsimile, appear to have been signed, by an authorized representative of the sender;
 
(iii) regarded as given and received:
 
(a) if delivered by hand or by express courier, when delivered to the addressee; or
 
(b) if sent by post, three Business Days from and including the date of postage; or
 
(c) if sent by facsimile transmission, when the transmission is successfully transmitted as reported by the sender’s machine,
 
but if the delivery or receipt is on a day which is not a Business Day or is after 4.00pm (addressee’s time) it is regarded as received at 9:00am on the following Business Day.  E-mail notification of any notices delivered pursuant to this Article will also be provided for information only.
 
B. A facsimile transmission is not regarded as successfully transmitted if the addressee telephones the sender within four (4) hours after the transmission is received or regarded as received under Article 10.A(iii)(c) and informs the sender that it is not legible or incomplete.  E-mail addresses are provided for convenience only.
 
FARMOR:

Kosmos Energy Mauritania	 	
 	 	
c/o Wilmington Trust (Cayman Islands)	c/o Kosmos Energy, LLC	
4th Floor, Century Yard	8176 Park Lane, Suite 500	
 
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Cricket Square, Hutchins Drive	Dallas, TX  75231 USA	
Elgin Avenue, George Town	 	
Grand Cayman KY1-1209	E-mail: kosmosgeneralcounsel@kosmosenergy.com	
 	Fax:  +1 214 445-9705	
E-mail: MauritaniaNotifications	Attn.:  General Counsel	
@kosmosenergy.com	 	
Fax: +1 214 445-9705	 	
Attn.:  Jesse Noah, Vice President,	 	
Exploration, North Africa	 	
 	 	
FARMEE:	 	
 	 	
BP Exploration (West Africa) Limited	 	
Chertsey Road	 	
Sunbury-on-Thames	 	
Middlesex	 	
TW16 7BP	 	
United Kingdom	 	
E-mail: andy.lane@uk.bp.com	 	
Attn.:  Andy C. Lane, Head of Business Development, Gas Value Chain.	 	
 
ARTICLE 11
LAW AND DISPUTE RESOLUTION

11.1       Governing Law
 
This Agreement, and any non-contractual rights or obligations arising out of or in connection with it or its subject matter, shall be governed by and construed in accordance with the laws of England and Wales, excluding any choice of law rules which would refer the matter to the laws of another jurisdiction.
 
11.2       Dispute Resolution
 
A. Except as may be otherwise agreed in the JOA, any and all claims, demands, causes of action, disputes, controversies and other matters in question arising out of or relating to this Agreement, including any question regarding its breach, existence, validity or termination, which the Parties do not resolve amicably within a period of twenty (20) days from the giving of a notice by one Party to the other Party notifying the dispute, shall be resolved by three arbitrators in accordance with the Arbitration Rules of the International Chamber of Commerce. Each Party shall appoint one arbitrator within thirty (30) days of the filing of the arbitration, and the two arbitrators so appointed shall select the presiding arbitrator within thirty (30) days after the latter of the two arbitrators have been appointed. If a Party fails to appoint its Party-appointed arbitrator or if the two Party-appointed arbitrators cannot reach an agreement on the presiding arbitrator within the applicable time period, then the remainder of the three arbitrators not yet appointed shall be appointed in accordance with said Rules. The seat of arbitration shall
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be London, England.  The proceedings shall be in the English language.  The resulting arbitral award shall be final and binding, and judgment upon such award may be entered in any court having jurisdiction thereof.  A dispute shall be deemed to have arisen when either Party notifies the other Party in writing to that effect.  Any monetary award issued by the arbitrator shall be payable in United States Dollars.  It is expressly agreed that the arbitrators shall have no authority to award special, indirect, consequential, exemplary or punitive damages.  The Parties waive any right to refer any question of law and any right of appeal on the law and/or merits to any court.
 
B. All discussions, negotiations and arbitration conducted between the Parties under this Article 11.2 (including a settlement resulting from negotiation or an arbitral award, documents exchanged or produced during an arbitration proceeding, and memorials, briefs or other documents prepared for the arbitration) are confidential and may not be disclosed by the Parties, their employees, officers, directors, counsel, consultants, and expert witnesses, except (under Article 9) to the extent necessary to enforce this Article 11 or any arbitration award, to enforce other rights of a Party, or as required by law or stock exchange; provided, however, that breach of this confidentiality provision shall not void any settlement or award.
 
ARTICLE 12
FORCE MAJEURE
 
If as a result of Force Majeure, any Party is rendered unable, wholly or in part, to carry out its rights or obligations under this Agreement, other than the obligation to pay any amounts due, then the rights or obligations of the Party giving such notice, so far as and to the extent that the rights or obligations are affected by such Force Majeure, shall be suspended during the continuance of any inability so caused and for such reasonable period thereafter as may be necessary for the Party to put itself in the same position that it occupied prior to the Force Majeure, but for no longer period.  The Party claiming Force Majeure shall notify the other Parties of the Force Majeure within a reasonable time after the occurrence of the facts relied on and shall keep all Parties informed of all significant developments. Such notice shall give reasonably full particulars of the Force Majeure and also estimate the period of time which the Party will probably require to remedy the Force Majeure.  The affected Party shall use all reasonable diligence to remove or overcome the Force Majeure situation as quickly as possible in a commercially reasonable manner but shall not be obligated to settle any labor dispute except on terms acceptable to it. All such disputes shall be handled within the sole discretion of the affected Party.  For the purposes of this Agreement,  “Force Majeure”  shall have the same meaning as is set out in the Contract.
 
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ARTICLE 13
DEFAULT
 
If Farmee fails to pay any payment (or part thereof) that becomes due and payable pursuant to the terms of this Agreement by the due date for payment it shall pay interest on such sum for the period from and including the due date up to the date of actual payment at the rate per annum which is the aggregate of the one (1) month term, London Interbank Offered Rate (LIBOR rate) for U.S. dollar deposits (as published in London by the  Financial Times  or if not published, then by  The Wall Street Journal ) and five (5) percentage points. The interest will accrue from day to day on the basis of the actual number of days elapsed and a 365-day year and shall be payable and compounded monthly.  If the aforesaid rate is contrary to any applicable usury law, the rate of interest to be charged shall be the maximum rate permitted by such applicable law.
 
ARTICLE 14
GENERAL PROVISIONS
 
14.1      Relationship of Parties
 
The rights, duties, obligations and liabilities of the Parties under this Agreement shall be individual, not joint or collective.  It is not the intention of the Parties to create, nor shall this Agreement be deemed or construed to create, a mining or other partnership, joint venture or association or a trust.  This Agreement shall not be deemed or construed to authorize any Party to act as an agent, servant or employee for any other Party for any purpose whatsoever except as explicitly set forth in this Agreement.  In their relations with each other under this Agreement, the Parties shall not be considered fiduciaries except as expressly provided in this Agreement.
 
14.2      Further Assurances
 
Each of the Parties shall do all such acts and execute and deliver all such documents as shall be reasonably required in order to fully perform and carry out the terms of this Agreement.
 
14.3      Waiver
 
No waiver by any Party of any one or more defaults by another Party in the performance of any provision of this Agreement shall operate or be construed as a waiver of any future default or defaults by the same Party whether of a like or of a different character.  Except as expressly provided in this Agreement, no Party shall be deemed to have waived, released or modified any of its right under this Agreement unless such Party has expressly stated, in writing, that it does waive, release or modify such right.
 
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14.4       Joint Preparation
 
Each provision of this Agreement shall be construed as though all Parties participated equally in the drafting of the same. Consequently, the Parties acknowledge and agree that any rule of construction that a document is to be construed against the drafting party shall not be applicable to this Agreement.
 
14.5       Severance of Invalid Provisions
 
If and for so long as any provision of this Agreement shall be deemed to be judged invalid for any reason whatsoever, such invalidity shall not affect the validity or operation of any other provision of this Agreement except only so far as shall be necessary to give effect to the construction of such invalidity, and any such invalid provision shall be deemed severed from this Agreement without affecting the validity of the balance of this Agreement.
 
14.6       Modifications and Assignment
 
(i) Subject to Article 14.6(ii) and Article 14.6(iii), there shall be no modification or assignment of this Agreement or the rights and obligations under it except by written consent of both Parties.
 
(ii) Farmee shall be entitled to assign, novate or transfer its rights and obligations under this Agreement to a Wholly-Owned Affiliate of Farmee and Farmor shall sign any documentation reasonably required in order to effect such assignment, novation or transfer.
 
(iii) Farmor shall be entitled to assign, novate or transfer its rights and obligations under this Agreement to a Wholly-Owned Affiliate of Farmor, provided that any assignment, novation or transfer of any of Farmor's obligations under this Agreement shall be subject to and conditional upon the Farmor having first delivered to the Farmee a legally binding and enforceable guarantee from the ultimate parent company of the Farmor and the Wholly-Owned Affiliate (in a form reasonably acceptable to Farmee) guaranteeing the performance and payment of all obligations and liabilities of the Farmor under this Agreement. Subject to satisfaction of the requirements of this Article 14.6(iii), Farmee shall sign any documentation reasonably required in order to effect such assignment, novation or transfer. In the event that a Farmor parent guarantee is delivered to Farmee in accordance with this Article 14.6(iii), the obligations of Farmor under Article 7.7 of this Agreement shall cease to apply from the effective date of such Farmor parent guarantee.
 
14.7     Priority of Agreement
 
In the event of any conflict between the provisions of the main body of this Agreement and its Exhibits, the provisions of the main body of the Agreement shall prevail. In the event of any
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conflict between this Agreement and the JOA, this Agreement shall prevail. In the event of any conflict between this Agreement and the Contract, this Agreement shall prevail unless such would be in violation of the Laws/Regulations of the Islamic Republic of Mauritania or the terms of the Contract.
 
14.8       Interpretation
 
A. Headings: The topical headings used in this Agreement are for convenience only and shall not be construed as having any substantive significance or as indicating that all of the provisions of this Agreement relating to any topic are to be found in any particular Article.
 
B. Singular and Plural: Reference to the singular includes a reference to the plural and vice versa.
 
C. Gender: Reference to any gender includes a reference to all other genders.
 
D. Article: Unless otherwise provided, reference to any Article or an Exhibit means an Article or Exhibit of the Agreement.
 
E. Include: "include" and "including" shall mean to be inclusive without limiting the generality of the description proceeding such term and are used in an illustrative sense and not a limiting sense.
 
F. Performance of an obligation of any kind by a Party must be carried out at that Party’s cost, unless this Agreement states otherwise.
 
G. The Exhibits form part of this Agreement and have full force and effect as expressly set out in the main body of this Agreement.
 
H. References in this Agreement to any agreement shall be construed as a reference to such agreement as the same may be supplemented, amended or novated from time to time.
 
14.9      Counterpart Execution
 
This Agreement may be executed in any number of counterparts and each such counterpart shall be deemed an original Agreement for all purposes; provided that no Party shall be bound to this Agreement unless and until all Parties have executed a counterpart. For purposes of assembling all counterparts into one document, Farmor is authorized to detach the signature page from one or more counterparts and, after signature thereof by the respective Party, attach each signed signature page to a counterpart.
 
14.10    Public Announcements
 
No public announcement or statement regarding the terms or existence of this Agreement shall be made without prior written consent of all Parties; provided that, notwithstanding any failure to obtain such approval, no Party shall be prohibited from issuing or making any such public announcement or statement to the extent it is necessary to do so in order to comply with the
32

 

applicable laws, rules or regulations of any government, legal proceedings or stock exchange having jurisdiction over such Party or its Affiliates, however, any such required public announcement or statement shall include only that portion of information which the disclosing Party is advised by written opinion of counsel (including in-house counsel) is legally required.  Such opinion, along with the proposed public announcement or statement, shall be delivered to the other Party no later than two days prior to any such public announcement or statement.
 
14.11    Third Party Rights
 
The Parties agree that no term of this agreement is intended to be enforceable by a person, firm, company or other entity who is not a party to this agreement, whether pursuant to the Contracts (Rights of Third Parties) Act 1999 or otherwise.     
 
14.12    Entirety
 
With respect to the subject matter contained herein, this Agreement (i) is the entire agreement of the Parties; and (ii) supersedes all prior understandings and negotiations of the Parties, including the confidentiality agreement made between the Parties dated 5 April 2016 (as subsequently amended).
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IN WITNESS of their agreement each Party has caused its duly authorized representative to sign this instrument on the date set out in the first sentence of this Agreement.

Executed for and on behalf of KOSMOS ENERGY MAURITANIA	
 	 	
Signed:	/s/ Christopher Ball	
 	 	
Print name:	CHRISTOPHER BALL	
 	 	
Executed for and on behalf of BP EXPLORATION (WEST AFRICA) LIMITED	
 	 	
Signed:	/s/ Andrew Lane	
 	 	
Print name:	ANDREW LANE	
 	 	
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EXHIBIT A
ELIGIBLE DISCOVERY

 
Part 1
 
Tortue Discovery Area

 
35

 

EXHIBIT A
ELIGIBLE DISCOVERY

 
Part 2
Marsouin Discovery Area

 
36

 

EXHIBIT B
NOT USED
 
37

 

EXHIBIT C
CONTRACT AREA

 
38

 

EXHIBIT D
FORM OF JOA NOVATION AGREEMENT

 
 
NOVATION AGREEMENT NO. __

To

AMENDED AND RESTATED JOINT OPERATING AGREEMENT

IN RESPECT OF

OFFSHORE MAURITANIA

 
 
Between

Kosmos Energy Mauritania

and

LA SOCIETE MAURITANIENNE DES HYDROCARBURES ET DE PATRIMOINE MINIER
 
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JOA NOVATION AND AMENDMENT AGREEMENT NO. X_
 
(Block C_, Offshore Mauritania)
 
THIS JOA NOVATION AND AMENDMENT AGREEMENT (the “Agreement”) is made as a Deed this ___ day of _______________ 201_ by and among  La Société Mauritanienne Des Hydrocarbures et de Patrimoine Minier,  the national oil company of the Islamic Republic of Mauritania, incorporated by Decree No. 2005-106 dated 7 November 2005 as amended by Decree No. 2009-168 dated 3 May 2009 and Decree No. 2014-01 dated 6 January 2014 under the laws of the Islamic Republic of Mauritania and having its registered office at Ilot K, Rue 42-133,No. 349, BP 4344, Nouakchott, Islamic Republic of Mauritania (“ SMHPM ”),  Kosmos Energy Mauritania , a Cayman Islands company whose office is located at 4 th  Floor, Century Yard, Cricket Square, Hutchins Drive, Elgin Avenue, George Town, Grand Cayman, KY1-1209, Cayman Islands (“ Kosmos ”), and  BP Exploration (West Africa) Limited , registered in England and Wales and having it registered office at Chertsey Road, Sunbury-on-Thames, Middlesex. TW16 7BP, U.K. (“ BP ”), collectively referred to as the “ Parties ” and individually as a “ Party ”.
 
RECITALS
 
SMHPM and Kosmos have entered into that certain Exploration and Production Contract for Block C_ dated 5 April 2012 with the Islamic Republic of Mauritania, as amended and supplemented, (the “ Petroleum Agreement ”) and that certain Amended and Restated Joint Operating Agreement dated 1 December 2014, as amended and supplemented, (“ JOA ”), all documents covering the area known as Block C_, Offshore Mauritania;
 
Kosmos wishes to transfer (the “Transfer”) to BP an undivided sixty-two percent (62%) Participating Interest, as defined in the JOA (the “ Transferred Interest ”);
 
This Agreement will be effective from the earlier to occur of: (a) date of the letter from the Minister of Petroleum, Energy and Mines n° ................... dated ...................... approving the Transfer; and (b) the date on which the Minister of Petroleum, Energy and Mines is deemed to have approved the Transfer in accordance with the Petroleum Agreement     (the  “Transfer Effective Date” ); and
 
SMHPM, Kosmos and BP have agreed to execute this Agreement, confirming the release of Kosmos and consent to the assumption by BP, respectively, of the Transferred Interest and amending the JOA on the terms set out herein.
 
AGREEMENT 
 
Subject to the Minister of Petroleum, Energy and Mines approving (or being deemed to approve) the Transfer, and with effect from 00.01 hours (Mauritania time) on the Transfer Effective Date the Parties hereby agree as follows:
 
1.          Each of the Parties severally agrees:
 
(a)         Kosmos shall cease to be liable for the Transferred Interest and BP shall take the place of Kosmos in respect of the Transferred Interest and shall assume the obligations and liabilities and be entitled to the rights and benefits of Kosmos in such Transferred Interest as of the Transfer Effective Date;
 
(b)        Kosmos shall continue to be liable for all liabilities, obligations, duties and claims arising under the JOA in respect of the Transferred Interest, whether actual, accrued or contingent, relating to the period prior to the Transfer Effective Date;
 
(c)         BP undertakes and covenants to observe, perform, discharge and be bound by all liabilities, obligations, duties and claims arising under the JOA in respect of the
40

 

Transferred Interest accrued or otherwise arising on or after the Transfer Effective Date; and
 
(d)         SMHPM releases and discharges Kosmos from its liabilities, obligations, duties and claims assumed by BP pursuant to sub-clauses 1(a) and 1(c) above and accept the assumption by BP of such liabilities, obligations, duties and claims in place thereof.
 
2.          Article 3.2 (A) of the JOA is hereby amended and restated in its entirety as follows:
 
The Participating Interests of the Parties are:
 
SMHPM	10%	
 	 	
Kosmos	28%	
 	 	
BP	62%	
 	 	
TOTAL	100%	
 
3.          Additionally, the following provisions  of the JOA are hereby amended and restated in their entirety as follows:
 
(a)   In the opening paragraph, Party No 2 is deleted and replaced with:
 
“2.  BP Exploration (West Africa) Limited, a company incorporated under the laws of England and Wales and having its registered office at Chertsey Road, Sunbury-on-Thames, Middlesex. TW16 7BP, U.K. (“ BP ”): and”
 
(b)   All references to “Chevron Mauritania Exploration Limited” are deleted and replaced by “BP Exploration (West Africa) Limited”; and all references to “Chevron” are deleted and replaced by “BP”.
 
(c)   Article 1.40 is deleted and all other references to the First Well and Chevron’s election regarding the First Well are deleted.
 
(d)  the third and fourth Recitals are deleted and replaced by the following:
 
“WHEREAS, Kosmos and BP entered into a Farmout Agreement dated 15 December 2016 and SMHPM elected not to exercise its pre-emption rights under this Agreement to acquire the Participating Interest proposed to be assigned to BP by letter n° ................... dated ......................:”
 
“WHEREAS, the Parties, following approval by the Minister of Petroleum, Energy and Mines by letter n° ................... dated ...................... and Kosmos’ transfer of a sixty two percent (62%) Participating Interest to BP, desire to define their respective rights and obligations with respect to their operations under the Contract.” 
 
(e)   Article 1.76 is deleted and replaced with the following:
 
“Technical Operations means exploration activities within the scope of the Agreement conducted by the Technical Operator on behalf of all Parties on or after the Operator Transfer Effective Date during the Exploration Period, as further designated in Articles 4.2(C) and 4.2(D).”
 
(f)   Article 1.77 is deleted and replaced with the following:
41

 

“Technical Operator means Kosmos or its Affiliate as designated under Article 4.1B.”
 
(g) The second paragraph of Article 3.4(E) is deleted and replaced with the following:
 
“For the avoidance of doubt, as from ________(Transfer Effective Date) the aggregate amount payable by each Party (other than the NOC) in respect of its Participating Interest and the portion of the Carried Interest Amount to be borne by such Party pursuant to Article 3.4(B) in respect of Joint Operations, based on the Participating Interests set out in Article 3.2(A) shall be:
 
Kosmos	31.11%	
 	 	
BP	68.89%	
 	 	
Total	100%”	
 
(h)   Articles 1.79 to 1.81 are renumbered as Articles 1.80 to 1.82, respectively, and the following is inserted as new Article 1.79:
 
"Transfer Effective Date has the meaning given in the Novation and Amendment Agreement entered into in respect of this Agreement on [….]."
 
(i)   Article 3.1(C) is deleted.
 
(j)  The fourth paragraph of Article 3.4(E) is deleted.
 
(k)  Article 4.1(A) is deleted and replaced with the following:
 
(A) “Operator.  Subject to Article 4.1(B) and with effect from 1 April 2017 (or such later date as is mutually agreed between the Parties) (the “ Operator Transfer Effective Date ”, each Party severally appoints BP as Operator for conducting Joint Operations other than Technical Operations within the Exploration Area during the Exploration Period and as Operator pursuant to any Exploitation Authorization and BP agrees to act as such in accordance with this Agreement as from the Operator Transfer Effective Date.”
 
(l)   Article 4.1(B) is deleted and replaced with the following:
 
“During the Exploration Period Kosmos will be the Technical Operator for Technical Operations until such time as the Exploration Period expires in accordance with article 3 of the Contract.  The costs arising in connection with those activities shall be charged to the Joint Account.  Articles 4.2(B)(1)-(4), (6)-(12) and (15)-(17), 4.2(E), 4.3, 4.4, 4.6, 4.8, 4.9, 4.10, 4.11, 4.12, 6.6, 6.7, 6.8, 10.1(D), 20.1(C) shall apply,  mutatis mutandis,  to the Technical Operator.  Exploitation Area operations will be conducted separately, with Exploration Area operations continuing in the other areas.”
 
(m)  Article 4.1(C) is deleted.
 
(n)  Article 4.2(D) is deleted and replaced with the following:
 
“Technical Operator is responsible for all exploration activities conducted prior to a decision by the Operating Committee to appraise a discovery pursuant to Article 6.1., including but not limited to:
 
42

 

1.   Undertake petroleum system analysis (PSA) including basin/play assessment and prospect identification, evaluation, maturation and ranking;
 
2.   Formulate exploration strategy, in consultation with Operator, including:
 
a.   2D / 3D seismic
 
b.   Drilling – number, timing, sequencing and location of wells;
 
3.   Oversee post – well analysis and studies for all exploration drilling;
 
4.   Define exploration relinquishment areas, as necessary, in consultation with Operator;
 
5.   Propose extensions, if applicable, for exploration areas;
 
6.   Carry out all exploration operations in coordination with Operator, including:
 
a.  EIAs;
 
b.  2D / 3D seismic – survey planning, contracting, and acquisition / processing; and
 
c.  Wells – planning, design, permitting, contracting and operating of exploration well operations (including drilling, coring, logging and testing);
 
7.   Co – ordinate all daily activities in support of exploration operations including reports and meetings;
 
8.   Provide Operator as necessary and in a timely manner, with all exploration information in support of partner and government meetings, such as TCM’s, OCM’s and visits, including:
 
 	a.	 	Information and/or reports required by Operator for submission to JOA parties (i.e. OCM materials and resolutions, exploration WP&B, AFEs, costs, cash calls, etc.);	
 
9.   Accompany and attend all Exploration–related meetings with partners and/or government; and
 
10.  Definition of discovery area under Article 6.1(C) by Technical Operator, in consultation with Operator.”
 
(o)   The reference to "Technical Operator (or Operator if he assumes the duties of Technical Operator)" in first sentence of Article 4.3(B) is replaced with a reference to "Operator". 
 
(p)   For the purpose of service of notices under the terms of Article 17 of the JOA, the contact details of BP are:
 
BP Exploration (West Africa) Limited
Chertsey Road
Sunbury-on-Thames
Middlesex
TW16 7BP
E-mail: andy.lane@uk.bp.com
Attn.:Andy C. Lane, Head of Business Development, Gas values Chain.
 
4.          By executing this Agreement, SMHPM hereby: (a) gives its consent to the Transfer pursuant to Article 12.1(D) of the JOA; and (b) waives any rights in respect of the Transfer under Article 12.1(F) of the JOA.
 
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5.         This Agreement shall constitute all actions, consents, confirmations, agreements, and undertakings required under the JOA of Kosmos and SMHPM and BP in respect of: (a) the Transfer with effect from Transfer Effective Date; and (b) the appointment of BP as Operator (as defined in the JOA) and Kosmos as Technical Operator (as defined in the JOA, as amended herein) with effect from the Operator Transfer Effective Date.
 
6.          Except as expressly provided in this Agreement, all other provisions of the JOA shall remain in full force and effect and binding on the parties thereto, insofar as the same are in force and effect and binding on those parties immediately prior to the Transfer Effective Date.
 
7.          Except as expressly provided in this Agreement, the terms of this Agreement shall be effective as of the Transfer Effective Date.  Each reference in this Agreement (including the Recitals) to the JOA shall be construed and have effect as a reference to the same as it may have been supplemented, amended, extended, or novated prior to the date hereof.
 
8.          This Agreement may be executed in any number of counterparts with the same effect as if the signatures on the counterparts were upon a single engrossment of this Agreement provided that this Agreement shall not be effective until all Parties have executed a counterpart.
 
9.          Nothing in this Agreement shall confer on any third party any right to enforce any term of this Agreement.
 
10.        This Agreement is governed by and shall be construed in accordance with the laws of England and Wales, exclusive of any conflicts of law principles that could require the application of any other law.
 
11.        Any dispute, controversy or claim (of any and every kind or type, whether based on contract, tort, statute, regulation or otherwise) arising out of, relating to, or connected with this Agreement, including any dispute as to its construction, validity, interpretation, enforceability or breach of this Agreement shall be resolved in accordance with Article 18.2 of the JOA.
 
IN WITNESS WHEREOF this Agreement has been executed and delivered as a Deed on behalf of the Parties on the day and year first above written.

LA SOCIETE MAURITANIENNE DES HYDROCARBURES ET DE PATRIMOINE MINIER	   	BP EXPLORATION (WEST AFRICA) LIMITED	
 	 	 	 	 	
BY:	 	 	BY:	 	
 	 	 	 	 	
NAME:	 	 	NAME:	 	
 	 	 	 	 	
TITLE:	 	 	TITLE:	 	
 	 	 	 	 	
WITNESS:	 	 	WITNESS:	 	

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KOSMOS ENERGY MAURITANIA	 	 	 	
 	 	 	 	 	
BY:	 	 	 	 	
 	 	 	 	 	
NAME:	 	 	 	 	
 	 	 	 	 	
TITLE:	 	 	 	 	
 	 	 	 	 	
WITNESS:	 	 	 	 	
 
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EXHIBIT E
FORM OF DEED OF ASSIGNMENT

 

 
DEED OF ASSIGNMENT

 
IN

EXPLORATION AND PRODUCTION CONTRACT

 
FOR

BLOCK C_

 
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The present deed of assignment is concluded between:
 
KOSMOS ENERGY MAURITANIA, a company organized and established under the laws of the Cayman Islands, whose registered office is located at 4 th  Floor, Century Yard, Cricket Square, Hutchins Drive, Elgin Avenue, George Town, Grand Cayman KY1-1209, Cayman Islands, hereinafter named " KOSMOS ", (the “ Assignor ”), herein represented by its __  [title, name of person signing ]_,
 
AND
 
BP EXPLORATION (WEST AFRICA) LIMITED, a company incorporated under the laws of the England and Wales, whose registered office is at Chertsey Road, Sunbury-on-Thames, Middlesex, TW167BP, England, hereinafter referred to as “ BP ” (the “ Assignee ”), herein represented by its  [title, name of person signing ]_;  
 
BP and KOSMOS are collectively referred to hereinafter as the “Parties”
 
PREAMBLE
 
A.        The Islamic Republic of Mauritania and KOSMOS are parties to the Exploration and Production Contract for Block C_, offshore Mauritania, dated 5 April 2012 and with an effective date of 15 June 2012 and pursuant to article 21 of the Contract the Government through La Société Mauritanienne Des Hydrocarbures et de Patrimoine Minier (" SMHPM ") acquired as at the effective date of the Contract a Participating Interest of ten percent (10%) (the “Petroleum Agreement”).  Pursuant to Article 3 of the Petroleum Agreement, an exploration authorization has been issued and extended by the Minister of Petroleum, Energy and Mines in accordance with the Petroleum Agreement.
 
B.        Chevron Mauritania Exploration Limited pursuant to an assignment agreement dated 1 December 2014 approved by the Minister of Petroleum, Energy and Mines (letter n° 221 dated 13 March 2015) acquired a Participating Interest of thirty percent (30%) in the Petroleum Agreement; and subsequently as of 9 June 2016 Chevron Mauritania Exploration Limited withdrew from and relinquished its Participating Interest in the Petroleum Agreement.
 
D.        In accordance with the Petroleum Agreement, SMHPM and KOSMOS are holders of the exclusive right to perform Petroleum Operations, as defined in the Petroleum Agreement in the area defined by the Petroleum Agreement;
 
E.        Article 22 of the Petroleum Agreement permits the Parties to the Petroleum Agreement to assign and transfer in whole or in part their Percentage Interest as defined by the
 
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Petroleum Agreement to a third party;
 
F.         Article 22 of the Petroleum Agreement require the approval of the Minister of Petroleum, Energy and Mines before an assignee may acquire any rights pursuant to the Petroleum Agreement;
 
G.        Kosmos requested the prior approval of the Minister of Petroleum, Energy and Mines by its letter n° ................... dated ......................; and the Minister of Petroleum, Energy and Mines provided the requested approval by letter n° ................... dated .......................
 
In witness whereof, the Parties have agreed the following between themselves in consideration of the obligations set out in the present deed of assignment:
 
Article 1
Pursuant to the Petroleum Agreement, KOSMOS assigns and transfers, and BP accepts by the present document, an undivided sixty-two percent (62%) Percentage Interest in the Petroleum Agreement (the “ BP Assigned Interest ”) effective as of the date of the letter from the Minister of Petroleum, Energy and Mines n° ................... dated ...................... (the “ Effective Date ”), so that the Percentage Interest held by the parties in the Petroleum Agreement at the Effective Date is as follows:
 
SMHPM	ten percent (10%)	
 	 	
KOSMOS	twenty-eight percent (28%)	
 	 	
BP	sixty-two percent (62%)	
 
Article 2
BP acknowledges and accepts that it shall assume and fulfil all the obligations, responsibilities and duties from the   Effective Date, under the Petroleum Agreement that may arise after this date related to the  BP  Assigned Interest.
 
BP agrees to indemnify and hold KOSMOS harmless from and against all such obligations, liabilities, duties, costs and expenses arising out of operations relating to the Petroleum Agreement which accrue after the Effective Date to the extent they are related to the  BP  Assigned Interest.
 
Article 3
KOSMOS declares and warrants by the present deed of assignment that immediately before the Effective Date it is the owner of the  BP  Assigned Interest and that it has not, with the exception of the transfers Participating Interest referenced in sections A and B of the Preamble, in any way previously transferred, assigned or pledged its interest under the Petroleum Agreement
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constituting the object of the present assignment to BP, and KOSMOS shall undertake to indemnify and shall hold  BP  harmless from all claims, losses or damages that  BP  may suffer or incur owing to a violation of the above declaration and warranty.
 
KOSMOS herein commits to indemnify and hold BP harmless from all responsibilities and obligations relating to the  BP  Assigned Interest which accrue before the Effective Date.
 
Article 4
The Parties shall sign all other documents and shall carry out all other requirements that may be necessary or desirable in order to confirm or record the assignment of the  BP  Assigned Interest, and to put this into effect in accordance with the laws of the Islamic Republic of Mauritania.
 
Article 5
All the terms used in the present deed of assignment (with the exception of the term “Parties”) have the same definition as that indicated in the Petroleum Agreement.
 
In witness whereof, the Parties have duly signed this deed of assignment in four (4) original copies in the French language and in three (3) copies in the English language on the ___ day of __________________.

BP EXPLORATION (WEST AFRICA) LIMITED	
 	 	 	
By:	 	 	
 	 	 	
Position:	 	 	
 	 	 	
Witness:	 	 	
 	 	 	
KOSMOS ENERGY MAURITANIA	
 	 	 	
By:	 	 	
 	 	 	
Position:	 	 	
 	 	 	
Witness:	 	 	
 
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EXHIBIT F
NOT USED
 
4

 

EXHIBIT G
NOT USED
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EXHIBIT H
 
Farmor Warranties
 
1.            Incorporation and Capacity
 
1.1          Farmor is duly incorporated with limited liability and validly existing under the laws of the Cayman Islands.
 
1.2         The documents which contain or establish Farmor’s constitution incorporate provisions which authorise, and all necessary corporate action has been taken to authorise, Farmor to execute and deliver this Agreement and perform the transaction contemplated by this Agreement, which Agreement will constitute legally binding obligations on Farmor and not cause Farmor to violate any applicable law, judgment, order, permit or any other Agreement, consent or instrument binding on Farmor.
 
2.           Performance
 
Subject to fulfilment of the Conditions Precedent, the signing and delivery of this Agreement and the performance of any of the transactions contemplated by this Agreement will not contravene or constitute a default under any provision contained in any agreement, instrument, law, judgment, order, licence, permit or consent by which Farmor or any of its Affiliates or their respective assets is bound or affected or cause any limitation on Farmor or the powers of its directors, whether imposed by or contained in any document which contains or establishes its constitution or in any law, order, judgment, agreement, instrument or otherwise to be exceeded and which would result in Farmor being unable to perform its obligations under this Agreement.
 
3.           Solvency
 
No order has been made, petition presented or meeting convened for the purpose of considering a resolution for the winding up or for the appointment of a liquidator or provisional liquidator of Farmor.
 
4.           Sole Ownership
 
Farmor is a party to the Interest Documents and the sole legal and beneficial owner of the Interests.
 
5.           Right to Assign
 
Following fulfilment of the Conditions Precedent, Farmor will have the right, subject to Approval, to transfer and assign full legal and beneficial ownership of the Interests to Farmee.
 
6.           No Encumbrance
 
Subject to the provisions of the Interest Documents, no Encumbrance is in existence and in force over the Interests nor, subject as aforesaid, is there in effect any agreement or commitment to create the same; nor are there any other matters which restrict Farmor’s ability freely to dispose of the Interests.
 
7.           Interests and Interest Documents
 
7.1         Farmor has not committed any breach of the Interest Documents nor received notice (in its role as Operator under the Contract and JOA) and not otherwise aware that any of the other parties to any of the above-mentioned documents has committed any breach.
 
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7.2         The Interests and all rights and interests of Farmor thereunder or deriving therefrom are in full force and effect.
 
7.3         No notice has been given to Farmor or, that Farmor is aware of, to any party to the Interest Documents (other than Farmor and Farmee) by the Government of any intention to terminate, amend or revoke the Contract.
 
7.4         No area under the Contract is in the course of being surrendered or relinquished in whole or in part, and there is no proposal to do so .
 
7.5         Farmor has not given any notice of withdrawal from the Contract.
 
7.6         Farmor is not aware of any facts which would have a material adverse impact on the value of the Interests.
 
7.7         The Contract is currently in the first renewal phase of the exploration period and no party to the Contract has issued a notice under the Contract to apply for an extension of any current Exploration Period (as defined in the Contract) or for entry into a new phase of the Exploration Period.
 
7.8         All guarantees required pursuant to the terms of the Contract have been provided by Farmor, accepted by the Government and are in full force and effect.
 
7.9         No vote to remove Farmor in its capacity as operator under the Contract or JOA is pending or has been proposed, and Farmor, in its capacity as operator under the Contract or JOA, has not intimated that it intends to resign as such.
 
7.10       Not Used
 
7.11       The Contract Area is the accurate delineated area covering the Contract and is not, in full or in part, subject to any competing or overlaying claim by a third party or group of parties.
 
8.           No Litigation
 
8.1         Farmor is not a party to any litigation or arbitration or administrative proceedings in respect of which a writ or summons or other formal pleading has been served or judgement issued, nor is there any claim (whether or not formulated within a formal pleading as aforesaid) or dispute in relation to, and which is likely materially to prejudice or detrimentally affect in any manner, the Interests, and Farmor is not aware that any such litigation, arbitration, administrative proceedings, claim or dispute are threatened or pending either by or against Farmor, and there are no facts known to Farmor which are likely to give rise to any claim or dispute which is likely so to prejudice or detrimentally affect in any manner the Interests, and none of the parties to the Interest Documents is a party to any litigation, arbitration or administrative proceedings or any claim or dispute or judgment in relation to, and which is likely to prejudice or detrimentally affect in any manner, the Interests.
 
8.2         There are no overlaps, competing claims or disputes in relation to the Contract Area from any third party.
 
9.           Insurance
 
9.1         The insurance policies maintained by Farmor in respect of the Interests have at all material times afforded to Farmor adequate cover against such risks as companies carrying on the same
7

 

type of business as Farmor commonly cover, and the full terms of all such insurance policies are included in the Disclosure Documents.
 
9.2         All premiums due in respect of those insurance policies have been fully paid and there are no circumstances which may lead to liability under any such insurances being avoided by the insurers and none of the insurances is subject to any special or unusual terms or restrictions.
 
9.3         No claim is outstanding under any of the insurances and no circumstances exist which are likely to give rise to any such claim.
 
10.         Interest Documents
 
The Interest Documents are the only documents of which Farmor is aware which govern or relate to the creation, existence and validity of the Interests and are the only agreements to which Farmor is party relating to the Interests, and Farmor has made available to Farmee accurate and complete copies of the Interest Documents, save that, where Farmor has provided any translation of a document, Farmor has done so as a courtesy to Farmee and Farmor makes no warranty as to the accuracy of such translation. 
 
11.         Provision of Information
 
11.1       Farmor has in its possession or has access to all Data and information relating to the Interests (including complete copies of all material geological, geophysical, well and field development data and any other information in the possession of Farmor or any of its Affiliates relating to the evaluation of the proven, probable and possible reserves in the Contract Area and on reservoir volume and performance) to which it is entitled under the terms of the Interest Documents and all such Data and information is included in the Disclosure Documents.
 
11.2       Each Answer is true and accurate in every material respect.
 
12.         No Force Majeure
 
Farmor is not aware of any force majeure event or other event which would excuse or has excused performance of any of the obligations of Farmor which have arisen under any of the Interest Documents and this Agreement.
 
13.         Tax
 
13.1       Farmor has, since it acquired the Interests, complied with all statutory requirements, regulations, orders, provisions, directions or conditions in relation to the Interests concerning Tax including the making on time of accurate returns and payments and the proper maintenance and preservation of records and Farmor has not been given any penalty, notice or warning regarding the same.
 
13.2       Farmor is not involved in any dispute, and is not the subject of any enquiries, with any Tax authority or any other appropriate fiscal authority, whether of the Islamic Republic of Mauritania or elsewhere, concerning any matter likely to affect the Interests in any way other than routine enquiries of a minor nature following the submission of computations and returns.
 
13.3       All documents under which Farmor derives title to the Interests and which attract transfer tax have been duly stamped, if required, and are in the possession of Farmor or under its control.
 
14.         Environmental
8

 

14.1       Farmor has not been notified of the occurrence of any environmental incident concerning the Interests and operations related thereto.
 
14.2       Farmor has not received any demands, notices, orders or directives under any environmental laws, whether or not with respect to any breach thereof, nor in relation to any environmental liabilities which require any remedial work, clean up or any other such work, repairs, construction or capital expenditures with respect to the Interests or the operations related thereto or use or ownership thereof which have not been fully complied with.
 
14.3       No complaint has been filed by any governmental department, body or agency or any non-governmental group or organization in respect of the Interests concerning any environmental damage, injury, alleged damage or breach of any legislation, rules, regulations and orders relating to the environment.
 
15.         Bribery and Anti-Corruption
 
15.1     Neither Farmor nor any of its Affiliates nor their respective Associated Persons:
 
(i)      has been, is or will be engaged in any activity, practice or conduct related to the Interest Documents or to this Agreement that would constitute a violation of the Anti-Corruption Laws and Obligations either with respect to itself or with respect to the Farmee;
 
(ii)     has paid, offered, promised or authorized the payment, directly or indirectly, of any monies or anything of value to any Government Official (as defined in the Joint Operating Agreements), for the purpose of improperly influencing any act or decision of such Government Official or improperly inducing such Government Official to use his or her influence with a government or instrumentality thereof to obtain or retain business or direct business to any Person in connection with the Interest Documents or this Agreement; or 
 
(iii)     Farmor is not aware that it is the subject of any investigation, inquiry or enforcement proceedings by any government, administrative or regulatory body regarding any offence or alleged offence under the Anti-Corruption Laws and Obligations related to the Interest Documents or this Agreement, and no such investigation, inquiry or proceedings has been threatened, and there are no circumstances likely to give rise to any such investigation, inquiry or proceedings.
 
15.2     Farmor is not aware after due inquiry, that any Person:
 
(i) has engaged in any activity, practice or conduct related to the Interest Documents or to this Agreement that would violate the terms of the Anti-Corruption Laws and Obligations, even if that Person is outside the jurisdiction or scope of those laws;
 
(ii) has paid, offered, promised or authorized the payment, directly or indirectly, of any monies or anything of value to any Government Official, for the purpose of improperly influencing any act or decision of such Government Official or improperly inducing such Government Official to use his or her influence with a government or instrumentality thereof to obtain or retain business or direct business to any Person in connection with the Interest Documents or this Agreement.
 
15.3       No principal, shareholder (or other equity holder), director, officer or employee of Farmor is or will become during the term of this Agreement a Government Official in the Islamic Republic of Mauritania.
 
16.         No Fees
 
9

 

Farmor has not incurred any obligation or entered into any agreement for any investment banking, brokerage, finder’s fee, commission, agency or similar payment in respect of any transaction contemplated by this Agreement for which Farmee may incur any liability.
 
17.         Operator
 
17.1       All material permits and licences required to carry out Joint Operations (as defined under the Contract) are held by the Farmor as Operator and valid and subsisting and there has been no material violation thereof.
 
17.2       Farmor as Operator has complied with the Contract and all applicable laws (including environmental laws) in carrying out the Joint Operations (as defined under the Contract).
 
17.3       No sole risk activities (as defined under the JOA) have been approved under the Interest Documents and no notices have been received for sole risk activities, or so far as the Farmor as Operator is aware, are likely to be issued.
10

 

EXHIBIT I
Farmee Warranties
 
1.           Incorporation and Capacity
 
1.1         Farmee is duly incorporated with limited liability and validly existing under the laws of England and Wales.
 
1.2         The documents which contain or establish Farmee’s constitution incorporate provisions which authorize, and all necessary corporate action has been taken to authorize, Farmee to execute and deliver this Agreement and perform the transaction contemplated by this Agreement, which Agreement will constitute legally binding obligations on Farmee and not cause Farmee to violate any applicable law, judgment, order, permit or any other Agreement, consent or instrument binding on Farmee.
 
2.           Performance
 
Subject to fulfilment of the Conditions Precedent, the signing and delivery of this Agreement and the performance of any of the transactions contemplated by this Agreement will not contravene or constitute a default under any provision contained in any agreement, instrument, law, judgment, order, licence, permit or consent by which Farmee or any of its Affiliates or their respective assets is bound or affected or cause any limitation on Farmee or the powers of its directors, whether imposed by or contained in any document which contains or establishes its constitution or in any law, order, judgment, agreement, instrument or otherwise to be exceeded and which would result in Farmee being unable to perform its obligations under this Agreement.
 
3.           Solvency
 
No order has been made, petition presented or meeting convened for the purpose of considering a resolution for the winding up or for the appointment of a liquidator or provisional liquidator of Farmee.
 
4.           No Litigation
 
No litigation, arbitration, administrative proceeding, dispute or judgment against Farmee or to which Farmee is a party which might by itself or together with any such other proceedings have a material adverse effect on its business, assets or condition and which would materially and adversely affect its ability to observe or perform its obligations under this Agreement and the transactions contemplated hereby, is subsisting or threatened or pending against Farmee or any of its assets.
 
5.           Anti Bribery and Corruption
 
5.1         Neither Farmee nor any of its Affiliates nor their respective Associated Persons:
 
(i)      has been, is or will be engaged in any activity, practice or conduct related to the Interest Documents or to this Agreement that would constitute a violation of the Anti-Corruption Laws and Obligations either with respect to itself or with respect to the Farmor;
 
(ii)     has paid, offered, promised or authorized the payment, directly or indirectly, of any monies or anything of value to any Government Official (as defined in the Joint Operating Agreements), for the purpose of improperly influencing any act or decision of such Government Official or improperly inducing such Government Official to use his or her influence with a government or
11

 

instrumentality thereof to obtain or retain business or direct business to any Person in connection with the Interest Documents or this Agreement; or 
 
(iii)Farmee is not aware that it is the subject of any investigation, inquiry or enforcement proceedings by any government, administrative or regulatory body regarding any offence or alleged offence under the Anti-Corruption Laws and Obligations related to the Interest Documents or this Agreement, and no such investigation, inquiry or proceedings has been threatened, and there are no circumstances likely to give rise to any such investigation, inquiry or proceedings.
 
5.2         No principal, shareholder (or other equity holder), director, officer or employee of Farmee is or will become during the term of this Agreement a Government Official in the Islamic Republic of Mauritania.
 
6.           No Fees
 
Farmee has not incurred any obligation or entered into any agreement for any investment banking, brokerage, finder’s fee, commission, agency or similar payment in respect of any transaction contemplated by this Agreement for which Farmor may incur any liability.
12

 

EXHIBIT J

EXHIBIT J
Part 1
 
Firm Work Programme (Exploration and Appraisal)
 
1.   Exploration Wells
 
a.   Two firm Exploration Wells in Mauritania to target outboard basin floor fan fairways, with the objective of testing the northern and southern source kitchens within the Contract Area
 
i.   Each of the Exploration Wells to be drilled to the top of 106_Albian;
 
ii.  The two firm Exploration Wells in Mauritania, will target, unless otherwise mutually agreed:
 
1.   A prospect in Block C8 or C13; and
 
2.   The Lamantin prospect in C12/C6 or an alternative C12/C6 prospect to be mutually agreed by the Parties
 
2.   DST
 
a.   A drill stem test (“DST”) within the Tortue Discovery Area
 
3.   Wells and Schedule
 
a.   The objective, design and duration of each Exploration Well and the DST to be determined pursuant to the JOA, Operator and Technical Operator to consult, including with the Steering Committee, if necessary, on all recommendations to the Operating Committee.
 
b.   It is anticipated that the drilling and testing program for the Exploration Wells and the DST will be continuous and conducted in an agreed order.
 
c.   The program will commence no later May 1 2017.  If for technical reasons beyond the Parties control the entire program cannot be completed in 2017, then the program will be completed as soon thereafter as practicable.
 
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EXHIBIT J
Part 2

Firm Work Programme (Development)
 
1.   Development Studies
 
a.   Operator shall conduct the following activities:
 
i.    Studies to establish (a) location of breakwater and pre-treatment facility; (b) scope of phase 1 pre-treatment facility; (c) breakwater configuration capable of expansion; and (d) LNG cooling solution capable of expansion
 
ii.   metocean survey/ report results; 
 
iii.  G&G site survey results at breakwater and Tortue sites;
 
iv.  Negotiate and finalize  all agreements required with a third party  FLNG contractor;
 
v.   concept screening to allow expansion of LNG facilities;
 
vi.  concept process safety, environmental studies and operations philosophy;
 
vii. flow assurance and water breakthrough risk mitigation studies; and
 
viii. Any other activities or studies to enable an investment decision on Tortue by the end of 2017.
 
2.   Schedule
 
a.   Operator will aim to complete this program by the end of first quarter 2017 to enable an investment decision on Tortue by the end of 2017.
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EXHIBIT K
Operator Transition Provisions
 
Transition Plan Key Principles
 
Purpose:
 
Ensure the joint venture continues to be highly efficient and the transition is seamless
 
Ensure the Tortue Project continues along its contemplated timeline safely and reliably
 
Ensure the host Governments view the joint venture transition as a highly efficient and seamless process
 
Period: Post Initialing – Pre Signing (~6 weeks)
 	·	 	Kosmos will inform and consult with BP on all key discussions and key decisions with respect to:	
oThe Governments of Mauritania and Senegal
oEngagement with Co-venturers in Mauritania and Senegal
oa third party liquefaction contractor
oICA & UOA
oCommitted exploration activities within the Area of Interest
oTortue DST operations planning & readiness
 
 	·	 	Kosmos and BP identify Joint Transition Team to be charged with creating Transition Plan and a Steering Committee to provide oversight to the Transition process	

 	·	 	BP implements New Country Entry visit with support from Kosmos	
 
Period: Post Signing – Pre Close (~6 weeks)
 
 	·	 	Joint Transition Team develops detailed plan to transition operatorship and assisting BP in the establishment of relationships post close with the objective of delivering the Purpose outlined above	

 	·	 	Kosmos will continue to inform and consult with BP on all key discussions and key decisions with respect to Co-venturers in Mauritania and Senegal	

 	·	 	BP to participate in discussions with any third party liquefaction contractor and participate as an observer in all other joint venture discussions/ working groups as permitted by the National Oil Companies and relevant agreements	

 	·	 	Kosmos and BP to initiate engagement on activities under the Exploration Partnering Agreement (EPA)	
 
Period: Post-Close
 
 	·	 	Transfer Operatorship to BP with effect from Operator Transfer Date and execute transition plan	

 	·	 	Kosmos becomes Technical Operator and maintains:	
oIts presence in Country with Country offices and Country Managers
oIts key government and NOC relationships in both countries
 	·	 	Kosmos is represented in all  key meetings with the governments and national oil companies and other key stakeholders	

 	·	 	BP to initiate set up in Country Presence in line with the transition with support from Kosmos	
15

 

EXHIBIT L
Questions and Answers
16

 

EXHIBIT M
ABC Obligations
 
1.        Neither Party nor any of its Affiliates nor their respective Associated Persons:
 
(i)        has been, is or will be engaged in any activity, practice or conduct related to the Interest Documents or to this Agreement that would constitute a violation of the Anti-Corruption Laws and Obligations either with respect to itself or with respect to the other Party;
 
(ii)       has paid, offered, promised or authorized, or will pay, offer, promise or authorize, the payment, directly or indirectly, of any monies or anything of value to any Government Official (as defined in the Joint Operating Agreements), for the purpose of improperly influencing any act or decision of such  Government Official or improperly inducing such Government Official to use his or her influence with a government or instrumentality thereof to obtain or retain business or direct business to any Person in connection with the Interest Documents or this Agreement; or 
 
(iii)      has been or is  the subject of any investigation, inquiry or enforcement proceedings by any government, administrative or regulatory body regarding any offence or alleged offence under the Anti-Corruption Laws and Obligations related to the Interest Documents or this Agreement, and no such investigation, inquiry or proceedings has been or will be threatened, and to the best of such Party’s knowledge, information and belief (after making reasonable enquiries) there are no circumstances likely to give rise to any such investigation, inquiry or proceedings.
 
2.        Each Party shall as soon as possible notify the other Parties of any suspected violations, including any investigation or proceeding initiated by a governmental authority relating to an alleged violation of applicable Anti-Corruption Laws and Obligations by such Party, or its Affiliates, or any Associated Persons, concerning operations and activities under the JOA and the Contracts. Such Party shall use reasonable efforts to keep the other Parties informed as to the progress and disposition of such investigation or proceeding, except that such Party shall not be obligated to disclose to the other Parties any information that would be considered legally privileged. 
 
3.        Each Party shall defend, indemnify and hold harmless the other Parties for any claims, damages, losses, penalties, costs (including reasonable legal costs and attorneys’ fees), and liabilities arising from, or related to: 
 
(a)       any breach by such Party of the warranties and undertakings set out in paragraph 1; 
 
(b)       such Party’s admission of allegations made by a governmental authority concerning operations and/or activities under this Agreement or the Interest Documents (or any agreements relating thereto) that such Party or its Associated Persons have violated Anti-Corruption Laws and Obligations applicable to such Party; or 
 
(c)       the final adjudication concerning operations and/or activities under this Agreement or the Interest Documents (or any agreements relating hereto) that such Party or its Affiliates or their directors, officers, employees and personnel have violated Anti-Bribery Laws and Obligations applicable to such Party, such indemnity obligations shall survive termination or expiration of this Agreement.    
 
4.          Each Party undertakes to each other Party that, to the extent it has not already done so, it shall: 
 
(a)        Devise and maintain adequate internal controls concerning such Party’s undertakings under paragraph 1; 
 
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(b)       design, implement and maintain comprehensive, “best practice” written policies, resources and procedures to ensure compliance with applicable Anti-Corruption Laws and Obligations and which will address, without limitation, sponsorship and donations, gifts and entertainment, hosting of Public Officials, anti-money laundering, whistle-blowing and responding to demands for improper payments or allegations of bribery, in each case in connection with the activities and operations conducted under or in relation to the Interest Documents and this Agreement (“ Anti-Corruption Policies ”); and
 
(c)       Retain books and records evidencing compliance with these paragraphs 1 -7 for a period of at least six (6) Calendar Years. 
 
5.        Each Party shall promptly respond in reasonable detail to any reasonable request from any other Party concerning a notice sent by such Party under paragraph 2 and shall furnish applicable documentary support for such Party’s response, including showing such Party’s compliance with the undertakings set out in paragraph 1.
 
6.        Each Party warrants that in connection with the Joint Operations it shall obligate any contractor, including but not limited to any sub-agent, representative or other service provider it may engage, that:
 
(a)       it will conduct appropriate due diligence prior to appointing or engaging such contractor to reasonably assure itself that they are duly qualified to perform the tasks for which they will be engaged and that they are of good reputation; and
 
(b)       it will impose and secure from the contractor when appropriate given the risk, in writing compliance with the Anti-Corruption Laws and Obligations or a similar obligation.
 
7.        Each Party undertakes to the other Party that, from time to time and at the reasonable request of each other Party, it shall:
 
(a)       provide written certification (by providing a certificate of compliance in the form agreed between the Parties and attached at Appendix A and signed by its authorized representative)) that it has complied with its undertakings under paragraph 1; and
 
(b)       in support of such compliance, provide the other Party with reasonable access to its personnel and to the facilities, warehouses and offices directly or indirectly serving the operation of the JOA and the Contracts and the books, records and other information relating to the JOA and the Contracts, together with the right, where reasonably requested, to make and retain copies of such books, records and information.
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Appendix A
 
FORM OF CERTIFICATE OF ANTI-BRIBERY COMPLIANCE
 
[Certifying Party Letterhead]
 
To:     [.......................], [.......................], [.......................], and [.......................]
 
Re:     Periodic Certification
 
Dear Sir,
 
Pursuant to paragraph 7 of Exhibit M of the Farm out Agreement dated [.......................] between Kosmos Energy Mauritania, and BP Exploration (West Africa) Limited (“Agreement”), the undersigned hereby confirms that throughout the twelve (12) months ending 31st December [.......................], [Certifying Party], its Affiliates and their respective directors, officers, employees and personnel, have complied with their warranties and covenants set out in paragraph 1 of Exhibit M of the Agreement.
 
The certificate is issued by the undersigned duly authorized representative for and on behalf of [Certifying Party] to the best of his or her knowledge after having made due enquiry as to the matters set out above, but without personal liability on the part of such authorized representative.
 
Yours faithfully,

Name and Title:...................................................................................................
[an executive director or officer of Certifying Party]
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EXHIBIT N
Farmor Retained Liabilities
 
Farmor retains responsibility for payment of the signature bonus for Block C6.
 
There are no other Farmor Retained Liabilities.
20

Exhibit 10.64
KOSMOS ENERGY LTD.
LONG TERM INCENTIVE PLAN
(amended and restated as of January 23, 2017)

TABLE OF CONTENTS
Page
 	 	 	
Section 1.	Purpose	1	
Section 2.	Definitions	1	
Section 3.	Eligibility	6	
Section 4.	Administration	6	
Section 5.	Shares Available for Awards	7	
Section 6.	Options	8	
Section 7.	Stock Appreciation Rights	9	
Section 8.	Restricted Stock and RSUs	9	
Section 9.	Performance Awards	10	
Section 10.	Other Stock-Based Awards	11	
Section 11.	Effect of Termination of Service or a Change in Control on Awards	12	
Section 12.	General Provisions Applicable to Awards	12	
Section 13.	Amendments and Termination	13	
Section 14.	Miscellaneous	14	
Section 15.	Effective Date of the Plan	15	
Section 16.	Term of the Plan	15	
Section 17.	Cancellation or “Clawback” of Awards	16	
Section 18.	Section 409A of the Code	16	

 

 

Exhibit 10.64
Kosmos Energy Ltd.
Long Term Incentive Plan
(amended and restated as of January 23, 2017)
Section 1.   Purpose.  The purpose of the Kosmos Energy Ltd. Long Term Incentive Plan (the “ Plan ”) is to motivate and reward those employees and other individuals who are expected to contribute significantly to the success of Kosmos Energy Ltd. (the “ Company ”) and its Affiliates to perform at the highest level and to further the best interests of the Company and its shareholders.    
Section 2.   Definitions.  As used in the Plan, the following terms shall have the meanings set forth below:
(a)   “Affiliate” means, except as provided in Section 2(h), (i) any entity that, directly or indirectly, is controlled by the Company and (ii) any entity in which the Company has a significant equity interest, in each case as determined by the Committee.
(b)   “Award” means any Option, SAR, Restricted Stock, RSU, Performance Award, Other Stock-Based Award granted under the Plan.
(c)   “Award Document” means any agreement, contract or other instrument or document evidencing any Award granted under the Plan, which may, but need not, be executed or acknowledged by a Participant.
(d)   “Beneficial Owner” has the meaning ascribed to such term in Rule 13d-3 under the Exchange Act.
(e)   “Beneficiary” means a Person entitled to receive payments or other benefits or exercise rights that are available under the Plan in the event of a Participant’s death.  If no such Person is or can be named by such Participant, or if no Beneficiary designated by such Participant is eligible to receive payments or other benefits or exercise rights that are available under the Plan at such Participant’s death, such Participant’s Beneficiary shall be such Participant’s estate. 
(f)   “Board” means the board of directors of the Company.
(g)   “Cause” means, with respect to any Participant, “cause” as defined such Participant’s Employment Agreement, if any, or if not so defined, except as otherwise provided in such Participant’s Award Document, such Participant’s:
(i)    failure to perform his or her duties to the Company or any Affiliate (other than any such failure resulting from his or her physical or mental incapacity);
(ii)   having engaged in misconduct, negligence or a breach of fiduciary duty, or breach of any applicable Employment Agreement;

 

(iii)  having been convicted of, or having entered a plea bargain or settlement admitting guilt or the imposition of unadjudicated probation for, any crime of moral turpitude or felony under any applicable law;
(iv)   breach of any restrictive covenant to which he or she is subject contained in any applicable Employment Agreement or other agreement with the Company or any Affiliate;
(v)    breach of any policy of the Company or any Affiliate, including without limitation any such policy that relates to expense management, human resources or the Foreign Corrupt Practices Act;
(vi)   unlawful use or possession of illegal drugs on the premises of the Company or any Affiliate or while performing his or her duties to the Company or any Affiliate; or
(vii)  commission of an act of fraud, embezzlement or misappropriation, in each case, against the Company or any Affiliate.
(h)   “Change in Control”  means the occurrence of any one or more of the following events:
(i)    any Person (other than the Initial Investors (as defined below), the Company, any trustee or other fiduciary holding securities under any employee benefit plan of the Company, or any company owned, directly or indirectly, by the shareholders of the Company immediately prior to the occurrence with respect to which the evaluation is being made in substantially the same proportions as their ownership of the common shares of the Company) becomes the Beneficial Owner (except that a Person shall be deemed to be the Beneficial Owner of all shares that any such Person has the right to acquire pursuant to any agreement or arrangement or upon exercise of conversion rights, warrants or options or otherwise, without regard to the 60-day period referred to in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Company representing 50% or more of the combined voting power of the Company’s then outstanding securities;
(ii)   during any period of 12 consecutive months, individuals who at the beginning of such period constitute the Board, and any new director whose election by the Board or nomination for election by the Company’s shareholders was approved by a vote of at least a majority of the directors then still in office who either were directors at the beginning of such 12-month period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board;
(iii)   the consummation of a merger, amalgamation or consolidation of the Company with any other entity, other than a merger, amalgamation or consolidation that would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving or resulting entity) more than 50% of the combined
2

 

voting power of the surviving or resulting entity outstanding immediately after such merger, amalgamation or consolidation; or
(iv)   the consummation of a transaction (or series of transactions within a 12-month period) that constitutes the sale or disposition of all or substantially all of the consolidated assets of the Company having a gross fair market value of 50% or more of the total gross fair market value of all of the consolidated assets of the Company (other than such a sale or disposition immediately after which such assets will be owned directly or indirectly by the shareholders of the Company in substantially the same proportions as their ownership of the common shares of the Company immediately prior to such sale or disposition), and the subsequent distribution of the proceeds from such transaction (or series of transactions) to the Company’s shareholders having a fair market value that is greater than 50% of the fair market value of the Company and its subsidiaries immediately prior to such transaction (or series of transactions).
For purposes of clause (i) above, “Initial Investors” means the “Blackstone Group,” the “Warburg Group” and their respective “Affiliates” (as all such terms are defined in that certain Shareholders Agreement dated as of May 10, 2011, by and among the Company and the other parties thereto).
(i)   “Code” means the Internal Revenue Code of 1986, as amended from time to time, and the rules, regulations and guidance thereunder.  Any reference to a provision in the Code shall include any successor provision thereto.
(j)   “Committee” means the Compensation Committee of the Board or such other committee as may be designated by the Board.  If the Board does not designate the Committee, references herein to the “Committee” shall refer to the Board.
(k)   “Covered Employee” means an individual who is, for a given fiscal year of the Company, (i) a “covered employee” within the meaning of Section 162(m) of the Code or (ii) designated by the Committee by not later than 90 days following the start of such year (or such other time as may be required or permitted by Section 162(m) of the Code) as an individual whose compensation for such fiscal year may be subject to the limit on deductible compensation imposed by Section 162(m) of the Code.
(l)   “Disability” means, with respect to any Participant, “disability” as defined in such Participant’s Employment Agreement, if any, or if not so defined, except as otherwise provided in such Participant’s Award Document, at any time that the Company or any Affiliate sponsors a long-term disability plan that covers such Participant, “disability” as defined in such plan for the purpose of determining such Participant’s eligibility for benefits;  provided  that if such plan contains multiple definitions of disability, then “Disability” shall refer to that definition of disability which, if Participant qualified for such benefits, would provide coverage for the longest period.  The determination of whether Participant has a Disability shall be made by the person or persons required to make final disability determinations under such plan.  At any time that the Company and the Affiliates do not sponsor a long-term disability plan that covers such Participant, Disability shall mean Participant’s physical or mental incapacity that renders him or
3

 

her unable for a period of 90 consecutive days or an aggregate of 120 days in any consecutive 12-month period to perform his or her duties to the Company or any Affiliate.
(m)  “Employment Agreement” means any employment, severance, consulting or similar agreement between the Company or any of its Affiliates and a Participant.
(n)   “Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time, and the rules, regulations and guidance thereunder.  Any reference to a provision in the Exchange Act shall include any successor provision thereto.
(o)   “Exchange Awards” means the Awards of Restricted Stock granted in exchange for unvested profit units in Kosmos Energy Holdings in connection with the initial public offering of the Shares.
(p)   “Fair Market Value” means, with respect to Shares, the closing price of a Share on the date in question (or, if there is no reported sale on such date, on the last preceding date on which any reported sale occurred) on the principal stock market or exchange on which the Shares are quoted or traded, or if Shares are not so quoted or traded, fair market value as determined by the Committee, and with respect to any property other than Shares, the fair market value of such property determined by such methods or procedures as shall be established from time to time by the Committee.
(q)   “Good Reason” means, with respect to any Participant, “good reason” as defined in such Participant’s Employment Agreement, if any, or if not so defined, except as otherwise provided in such Participant’s Award Document, the occurrence of any of the following events, in each case without such Participant’s consent:
(i)    a reduction in such Participant’s base salary or target bonus, other than any such reduction that applies generally to similarly situated employees of the Company and the Affiliates;
(ii)   relocation of the geographic location of such Participant’s principal place of employment by more than 50 miles; or
(iii)  a material reduction in such Participant’s duties or responsibilities that occurs within two years following a Change in Control;
provided that, in each case, (A) such Participant shall provide the Company with written notice specifying the circumstances alleged to constitute Good Reason within 90 days following the first occurrence of such circumstances, (B) the Company shall have 30 days following receipt of such notice to cure such circumstances, and (C) if the Company has not cured such circumstances within such 30-day period, then the date of such Participant’s Termination of Service must occur not later than 60 days after the end of such 30-day period.
(r)   “Incentive Stock Option” means an option representing the right to purchase Shares from the Company, granted pursuant to Section 6, that meets the requirements of Section 422 of the Code.
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(s)   “Intrinsic Value” means, with respect to an Option or SAR Award, the product of (i) the excess, if any, of (A) the price or implied price per Share in a Change in Control or other event over (B) the exercise or hurdle price of such Award  multiplied  by (ii) the number of Shares covered by such Award.
(t)   “Lock Up Agreement” means any agreement between the Company or any of its Affiliates and a Participant that provides for restrictions on the transfer of Shares held by such Participant.
(u)   “Non-Qualified Stock Option” means an option representing the right to purchase Shares from the Company, granted pursuant to Section 6, that is not an Incentive Stock Option.
(v)   “Option” means an Incentive Stock Option or a Non-Qualified Stock Option.
(w)  “Other Stock-Based Award” means an Award granted pursuant to Section 10.
(x)   “Participant” means the recipient of an Award granted under the Plan.
(y)   “Performance Award” means an Award granted pursuant to Section 9.
(z)   “Performance Period” means the period established by the Committee at the time any Performance Award is granted or at any time thereafter during which any performance goals specified by the Committee with respect to such Award are measured.
(aa)  “Person” has the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including “group” as defined in Section 13(d) thereof.
(bb)  “Replacement Award” means an Award granted in assumption of, or in substitution for, an outstanding award previously granted by a company or other business acquired by the Company or with which the Company combines.
(cc)  “Restricted Stock” means any Share granted pursuant to Section 8.
(dd)  “RSU” means a contractual right granted pursuant to Section 8 that is denominated in Shares.  Each RSU represents a right to receive the value of one Share (or a percentage of such value) in cash, Shares or a combination thereof.  Awards of RSUs may include the right to receive dividend equivalents.
(ee)  “SAR” means any right granted pursuant to Section 7 to receive upon exercise by a Participant or settlement, in cash, Shares or a combination thereof, the excess of (i) the Fair Market Value of one Share on the date of exercise or settlement over (ii) the exercise or hurdle price of the right on the date of grant, or if granted in connection with an Option, on the date of grant of the Option.
(ff)  “Section 162(m) Compensation” means “qualified performance-based compensation” under Section 162(m) of the Code.
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(gg)  “Shares” means shares of the Company’s common shares.
(hh)  “Termination of Service” means, with respect to any Participant:
(i)    the cessation of all services performed by such Participant for the Company and the Affiliates, including by reason of death or Disability; or
(ii)   the permanent decrease in the level of services performed by such Participant for the Company and the Affiliates (whether as an employee or as an independent contractor) to no more than 20 percent of the average level of services performed (whether as an employee or an independent contractor) over the immediately preceding 36-month period (or the full period of services to the Company and the Affiliates, if such Participant has been providing such services for less than 36 months).
Section 3.   Eligibility.
(a)   Any employee, non-employee director, consultant or other advisor of, or any other individual who provides services to, the Company or any Affiliate shall be eligible to be selected to receive an Award under the Plan.
(b)   Holders of options and other types of awards granted by a company acquired by the Company or with which the Company combines are eligible for grants of Replacement Awards under the Plan.
Section 4.   Administration.
(a)   The Plan shall be administered by the Committee.  The Committee shall be appointed by the Board and shall consist of not fewer than three directors of the Board.  All decisions of the Committee shall be final, conclusive and binding upon all parties, including the Company, its shareholders, Participants and any Beneficiaries thereof. The Committee may issue rules and regulations for the administration of the Plan. It shall meet at such times and places as it may determine.
(b)   To the extent necessary to comply with applicable regulatory regimes, any action by the Committee shall require the approval of Committee members who are (i) independent, within the meaning of and to the extent required by applicable rulings and interpretations of the applicable stock market or exchange on which the Shares are quoted or traded; (ii) a non-employee director within the meaning of Rule 16b-3 under the Exchange Act; and (iii) an outside director pursuant to Section 162(m) of the Code.  The Board may designate one or more directors as alternate members of the Committee who may replace any absent or disqualified member at any meeting of the Committee.  To the extent permitted by applicable law, the Committee may delegate to one or more officers of the Company the authority to grant Awards, except that such delegation shall not be applicable to any Award for   a Person then covered by Section 16 of the Exchange Act, and the Committee may delegate to one or more committees of the Board (which may consist of solely one director) the authority to grant all types of Awards, in accordance with applicable law. 
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(c)   Subject to the terms of the Plan and applicable law, the Committee (or its delegate) shall have full power and authority to:  (i) designate Participants; (ii) determine the type or types of Awards (including Replacement Awards) to be granted to each Participant under the Plan; (iii) determine the number of Shares to be covered by (or with respect to which payments, rights or other matters are to be calculated in connection with) Awards; (iv) determine the terms and conditions of any Award; (v) determine whether, to what extent and under what circumstances Awards may be settled or exercised in cash, Shares, other Awards, other property, net settlement, or any combination thereof, or canceled, repurchased, forfeited or suspended, and the method or methods by which Awards may be settled, exercised, canceled, repurchased, forfeited or suspended; (vi) determine whether, to what extent and under what circumstances cash, Shares, other Awards, other property and other amounts payable with respect to an Award under the Plan shall be deferred either automatically or at the election of the holder thereof or of the Committee; (vii) amend the terms or conditions of any outstanding Awards, including without limitation to accelerate the time or times at which the Awards become vested or unrestricted, will be settled or may be exercised; (viii) correct any defect, supply any omission or reconcile any inconsistency in the Plan or any Award Document, in the manner and to the extent it shall deem desirable to carry the Plan into effect; (ix) interpret and administer the Plan and any instrument or agreement relating to, or Award made under, the Plan; (x) establish, amend, suspend or waive such rules and regulations and appoint such agents and advisors and determine the terms of such appointments, in each case as it shall deem appropriate for the proper administration of the Plan and due compliance with applicable law, stock market or exchange rules and regulations or accounting or tax rules and regulations; and (xi) make any other determination and take any other action that the Committee deems necessary or desirable for the administration of the Plan and due compliance with applicable law, stock market or exchange rules and regulations or accounting or tax rules and regulations.  Notwithstanding anything to the contrary contained herein, the Board may, in its sole discretion, at any time and from time to time, grant Awards or administer the Plan.  In any such case, the Board shall have all of the authority and responsibility granted to the Committee herein.
Section 5.   Shares Available for Awards.
(a)   Subject to adjustment as provided in Section 5(c) and except for Replacement Awards and Exchange Awards, the maximum number of Shares available for issuance under the Plan shall not exceed 39,503,000 Shares in the aggregate, which includes (i) the initial reserve of 24,503,000 Shares under the Plan and (ii) an increase of 15,000,000 Shares, as approved by the Board, subject to approval by the Company’s shareholders.
(b)   Any Shares subject to an Award (other than a Replacement Award or Exchange Award) that expires, is canceled, repurchased or forfeited or otherwise terminates, without the delivery of such Shares, including (i) the number of Shares surrendered or withheld in payment of any grant, purchase, exercise or hurdle price of an Award or taxes related to an Award and (ii) any Shares subject to an Award to the extent that Award is settled without the issuance of Shares, shall again be, or shall become, available for issuance under the Plan.
(c)   In the event that the Committee determines that, as a result of any dividend or other distribution (whether in the form of cash, Shares or other securities, but excluding any ordinary cash dividend), recapitalization, stock split, reverse stock split, reorganization, merger,
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amalgamation, consolidation, split-up, spin-off, combination, repurchase or exchange of Shares or other securities of the Company, issuance of warrants or other rights to purchase Shares or other securities of the Company, issuance of Shares pursuant to the anti-dilution provisions of securities of the Company, or other similar corporate transaction or event affecting the Shares, or of changes in applicable laws, regulations or accounting principles, an adjustment is appropriate in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the Plan, then the Committee shall, subject to compliance with Section 409A of the Code, adjust equitably any or all of:
(i)    the number and type of Shares (or other securities) which thereafter may be made the subject of Awards, including the aggregate limit specified in Section 5(a) and the individual limits specified in Section 5(e);
(ii)   the number and type of Shares (or other securities) subject to outstanding Awards; and
(iii)  the grant, purchase, exercise or hurdle price with respect to any Award or, if deemed appropriate, make provision for a cash payment to the holder of an outstanding Award;
provided, however, that the number of Shares subject to any Award denominated in Shares shall always be a whole number.
(d)   Any Shares delivered pursuant to an Award may consist, in whole or in part, of authorized and unissued Shares or Shares acquired by the Company.
(e)   No Participant may receive under the Plan in any calendar year, subject to adjustment as provided in ‎Section 5(c):  (i) Options and SARs that relate to more than 3,950,300 Shares in the aggregate; (ii) Restricted Stock and RSUs that relate to more than 3,950,300 Shares in the aggregate; (iii) Share-based Performance Awards and Other Stock-Based Awards that relate to more than 3,950,300 Shares in the aggregate; and (iv) cash-based Performance Awards that relate to more than $15,000,000 in the aggregate.
Section 6.   Options.    The Committee is authorized to grant Options to Participants with the following terms and conditions and with such additional terms and conditions, in either case not inconsistent with the provisions of the Plan, as the Committee shall determine:
(a)   The exercise price per Share under an Option shall be determined by the Committee;  provided ,   however , that, except in the case of Replacement Awards, and subject to Section 6(e), such exercise price shall not be less than the Fair Market Value of a Share on the date of grant of such Option.
(b)   The term of each Option shall be fixed by the Committee but shall not exceed 10 years from the date of grant of such Option .
(c)   The Committee shall determine the time or times at which an Option may be exercised in whole or in part.
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(d)   The Committee shall determine the method or methods by which, and the form or forms, including cash, Shares, other Awards, other property, net settlement, broker-assisted cashless exercise or any combination thereof, having a Fair Market Value on the exercise date equal to the relevant exercise price, in which payment of the exercise price with respect thereto may be made or deemed to have been made.
(e)   The terms of any Incentive Stock Option granted under the Plan shall comply in all respects with the provisions of Section 422 of the Code. 
Section 7.   Stock Appreciation Rights.  The Committee is authorized to grant SARs to Participants with the following terms and conditions and with such additional terms and conditions, in either case not inconsistent with the provisions of the Plan, as the Committee shall determine: 
(a)   SARs may be granted under the Plan to Participants either alone (“freestanding”) or in addition to other Awards granted under the Plan (“tandem”) and may, but need not, relate to a specific Option granted under Section 6.
(b)   The exercise or hurdle price per Share under a SAR shall be determined by the Committee;  provided ,   however , that, except in the case of Replacement Awards, such exercise or hurdle price shall not be less than the Fair Market Value of a Share on the date of grant of such SAR.
(c)   The term of each SAR shall be fixed by the Committee but shall not exceed 10 years from the date of grant of such SAR.
(d)   The Committee shall determine the time or times at which a SAR may be exercised or settled in whole or in part.
Section 8.   Restricted Stock and RSUs.  The Committee is authorized to grant Awards of Restricted Stock and RSUs to Participants with the following terms and conditions and with such additional terms and conditions, in either case not inconsistent with the provisions of the Plan, as the Committee shall determine: 
(a)   Shares of Restricted Stock and RSUs shall be subject to such restrictions as the Committee may impose (including any limitation on the right to vote a Share of Restricted Stock or the right to receive any dividend, dividend equivalent or other right), which restrictions may lapse separately or in combination at such time or times, in such installments or otherwise, as the Committee may deem appropriate.
(b)   Any Share of Restricted Stock granted under the Plan shall be evidenced by entry in the register of members of the Company and in such other manner as the Committee may deem appropriate, including issuance of a share certificate or certificates.  In the event any share certificate is issued in respect of shares of Restricted Stock granted under the Plan, such certificate shall be registered in the name of the Participant and shall bear an appropriate legend referring to the terms, conditions and restrictions applicable to such Restricted Stock.
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(c)   If the Committee intends that an Award granted under this Section 8 shall constitute or give rise to Section 162(m) Compensation, then, to the extent the Committee determines the following to be necessary under Section 162(m) of the Code, such Award may be structured in accordance with the requirements of Section 9, including the performance criteria set forth therein and the Award limitation set forth in Section 5(e), and any such Award shall be considered a Performance Award for purposes of the Plan.
(d)   The Committee may provide in an Award Document that an Award of Restricted Stock is conditioned upon the Participant making or refraining from making an election with respect to the Award under Section 83(b) of the Code.  If a Participant makes an election pursuant to Section 83(b) of the Code with respect to an Award of Restricted Stock, such Participant shall be required to file promptly a copy of such election with the Company and the applicable Internal Revenue Service office.
Section 9.   Performance Awards.  The Committee is authorized to grant Performance Awards to Participants with the following terms and conditions and with such additional terms and conditions, in either case not inconsistent with the provisions of the Plan, as the Committee shall determine:
(a)   Performance Awards may be denominated as a cash amount, number of Shares or a combination thereof and are Awards which may be earned upon achievement or satisfaction of performance conditions specified by the Committee.  In addition, the Committee may specify that any other Award shall constitute a Performance Award by conditioning the right of a Participant to exercise the Award or have it settled, and the timing thereof, upon achievement or satisfaction of such performance conditions as may be specified by the Committee.  The Committee may use such business criteria and other measures of performance as it may deem appropriate in establishing any performance conditions.  Subject to the terms of the Plan, the performance goals to be achieved during any Performance Period, the length of any Performance Period, the amount of any Performance Award granted and the amount of any payment or transfer to be made pursuant to any Performance Award shall be determined by the Committee. 
(b)   Every Performance Award shall, if the Committee intends that such Award qualify as Section 162(m) Compensation and the Committee determines the following to be necessary under Section 162(m) of the Code, include a pre-established formula, such that payment, retention or vesting of the Award is subject to the achievement during a Performance Period or Performance Periods, as determined by the Committee, of a level or levels of, or increases in, in each case as determined by the Committee, one or more of the following performance measures with respect to the Company: captured prospects, prospecting licenses signed, operated prospects matured to drill ready, drilling programs commenced, drillable prospects, capabilities and critical path items established, operating budget, third-party capital sourcing, captured net risked resource potential, acquisition cost efficiency, acquisitions of oil and gas interests, increases in proved, probable or possible reserves, finding and development costs, recordable or lost time incident rates, overhead costs, general and administration expense, market price of a Share, cash flow, reserve value, net asset value, earnings, net income, operating income, cash from operations, revenue, margin, EBITDA (earnings before interest, taxes, depreciation and amortization), EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration expense), net capital employed, return on assets, shareholder return, reserve
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replacement, return on equity, return on capital employed, production, assets, unit volume, sales, market share, market capitalization, enterprise value, economic value added or strategic business criteria consisting of one or more objectives based on meeting specified goals relating to acquisitions or divestitures, each as determined in accordance with generally accepted accounting principles, where applicable, as consistently applied by the Company.  Performance criteria may be measured on an absolute ( e.g. , plan or budget) or relative basis,  may be established on a corporate-wide basis or with respect to one or more business units, divisions, subsidiaries or business segments, may be based on a ratio or separate calculation of any performance criterion and may be made relative to an index or one or more of the performance goals themselves.  Relative performance may be measured against a group of peer companies, a financial market index or other acceptable objective and quantifiable indices.  Except in the case of an Award intended to qualify as Section 162(m) Compensation, if the Committee determines that a change in the business, operations, corporate structure or capital structure of the Company, or the manner in which the Company conducts its business, or other events or circumstances render the performance objectives unsuitable, the Committee may modify the performance objectives or the related minimum acceptable level of achievement, in whole or in part, as the Committee deems appropriate and equitable.  Performance measures may vary from Performance Award to Performance Award and from Participant to Participant, and may be established on a stand-alone basis, in tandem or in the alternative.  The Committee shall have the power to impose such other restrictions on Awards subject to this Section 9(b) as it may deem necessary or appropriate to ensure that such Awards satisfy all requirements for Section 162(m) Compensation  or of any applicable law, stock market or exchange rules and regulations or accounting or tax rules and regulations.  Notwithstanding any provision of the Plan to the contrary, with respect to any Award intended to qualify as Section 162(m) Compensation, the Committee shall not be authorized to increase the amount payable under any Award to which this Section 9(b) applies upon attainment of such pre‑established formula.
(c)   Settlement of Performance Awards shall be in cash, Shares, other Awards, other property, net settlement, or any combination thereof, as determined in the discretion of the Committee. 
(d)   Performance Awards that are intended to qualify as Section 162(m) Compensation shall be settled only after the end of the relevant Performance Period.  The Committee may, in its discretion, increase or reduce the amount of a settlement otherwise to be made in connection with a Performance Award but, to the extent required by Section 162(m) of the Code, may not exercise discretion to increase any amount payable to a Covered Employee in respect of a Performance Award intended to qualify as Section 162(m) Compensation.  Any settlement that changes the form of payment from that originally specified shall be implemented in a manner such that the Performance Award and other related Awards do not, solely for that reason, fail to qualify as Section 162(m) Compensation.  The Committee shall specify the circumstances in which, and the extent to which, Performance Awards shall be paid or forfeited, including by way of repurchase by the Company at par value, in the event of a Participant’s Termination of Service.
Section 10.   Other Stock-Based Awards.  The Committee is authorized, subject to limitations under applicable law, to grant to Participants such other Awards that may be denominated or payable in, valued in whole or in part by reference to, or otherwise based on, or
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related to, Shares or factors that may influence the value of Shares, including convertible or exchangeable debt securities, other rights convertible or exchangeable into Shares, purchase rights for Shares, Awards with value and payment contingent upon performance of the Company or business units thereof or any other factors designated by the Committee.  Shares delivered pursuant to an Award in the nature of a purchase right granted under this Section 10 shall be purchased for such consideration, and paid for at such times, by such methods and in such forms, including cash, Shares, other Awards, other property, net settlement, broker-assisted cashless exercise or any combination thereof, as the Committee shall determine. Cash awards, as an element of or supplement to any other Award under the Plan, may also be granted pursuant to this Section 10. 
Section 11.   Effect of Termination of Service or a Change in Control on Awards.
(a)   The Committee may provide, by rule or regulation or in any Award Document, or may determine in any individual case, the circumstances in which, and the extent to which, an Award may be exercised, settled, vested, paid or forfeited, including by way of repurchase by the Company at par value, in the event of the Participant’s Termination of Service prior to the end of a Performance Period or vesting, exerci se or settlement of such Award.
(b)   The Committee may set forth the treatment of an Award upon a Change in Control in the applicable Award Document. 
(c)   In the case of an Option or SAR Award, except as otherwise provided in the applicable Award Document, upon a Change in Control, a merger or consolidation involving the Company or any other event with respect to which the Committee deems it appropriate, the Committee may cause such Award to be canceled in consideration of (i) the full acceleration of such Award and either (A) a period of at least ten days prior to such Change in Control to exercise the Award or (B) a payment in cash or other consideration to such Participant who holds such Award in an amount equal to the Intrinsic Value of such Award (which may be equal to but not less than zero), which, if in excess of zero, shall be payable upon the effective date of such Change in Control, merger, consolidation or other event or (ii) a substitute award (which immediately upon grant shall have an Intrinsic Value equal to the Intrinsic Value of such Award).
Section 12.   General Provisions Applicable to Awards.
(a)   Awards shall be granted for such cash or other consideration, if any, as the Committee determines;  provided  that in no event shall Awards be issued for less than such minimal consideration as may be required by applicable law.
(b)   Awards may, in the discretion of the Committee, be granted either alone or in addition to or in tandem with any other Award or any award granted under any other plan of the Company.  Awards granted in addition to or in tandem with other Awards, or in addition to or in tandem with awards granted under any other plan of the Company, may be granted either at the same time as or at a different time from the grant of such other Awards or awards.
(c)   Subject to the terms of the Plan, unless otherwise provided in the applicable Award Document, the Committee shall determine, in its sole discretion, whether payments or transfers
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to be made by the Company upon the grant, exercise or settlement of an Award shall be made in the form of cash, Shares, other Awards, other property, net settlement, or any combination thereof, as determined by the Committee in its discretion at the time of grant, and whether such payments or transfers shall be made in a single payment or transfer, in installments or on a delayed basis, in each case in accordance with rules and procedures established by the Committee.  Such rules and procedures may include provisions for the payment or crediting of reasonable interest on installment or deferred payments or the grant or crediting of dividend equivalents in respect of installment or deferred payments.
(d)   No Award and no right under any Award shall be assignable, alienable, saleable or transferable by a Participant otherwise than by will or pursuant to Section 12(e), and during a Participant’s lifetime, each Award, and each right under any Award, shall be exercisable only by such Participant or, if permissible under applicable law, by such Participant’s guardian or legal representative;  provided  that the foregoing restrictions shall not apply to any Award (other than an Incentive Stock Option) to the extent authorized by the Committee or as specifically provided in an Award Document.  The provisions of this Section 12(d) shall not apply to any Award that has been fully exercised or settled, as the case may be, and shall not preclude forfeiture, including by way of repurchase by the Company at par value, of an Award in accordance with the terms thereof.
(e)   A Participant may designate a Beneficiary or change a previous Beneficiary designation at such times prescribed by the Committee by using forms and following procedures approved or accepted by the Committee for that purpose.    
(f)   All certificates for Shares and/or other securities delivered under the Plan pursuant to any Award or the exercise thereof shall be subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the Plan or the rules, regulations and other requirements of the Securities and Exchange Commission, any stock market or exchange upon which such Shares or other securities are then quoted, traded or listed, and any applicable securities laws, and the Committee may cause a legend or legends to be put on any such certificates to make appropriate reference to such restrictions.
(g)   The Committee may impose restrictions on any Award with respect to non-competition, confidentiality and other restrictive covenants as it deems necessary or appropriate in its sole discretion.
Section 13.   Amendments and Termination.
(a)   Except to the extent prohibited by applicable law and unless otherwise expressly provided in an Award Document or in the Plan, the Board may amend, alter, suspend, discontinue or terminate the Plan or any portion thereof at any time;  provided, however , that no such amendment, alteration, suspension, discontinuation or termination shall be made without (i) shareholder approval if such approval is required by applicable law or the rules of the stock market or exchange, if any, on which the Shares are principally quoted, traded or listed or (ii) the consent of the affected Participant, if such action would materially adversely affect the rights of such Participant under any outstanding Award, except (x) to the extent any such amendment, alteration, suspension, discontinuance or termination is made to cause the Plan to comply with
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applicable law, stock market or exchange rules and regulations or accounting or tax rules and regulations or (y) to impose any “clawback” or cancellation provisions on any Awards (including any amounts or benefits arising from such Awards) in accordance with Section 17.  Notwithstanding anything to the contrary in the Plan, the Committee may amend the Plan, in such manner as may be necessary to enable the Plan to achieve its stated purposes in any jurisdiction in a tax‑efficient manner and in compliance with local rules and regulations.
(b)   The Committee may waive any conditions or rights under, amend any terms of, or amend, alter, suspend, discontinue or terminate any Award theretofore granted, prospectively or retroactively, without the consent of any relevant Participant or holder or Beneficiary of an Award;  provided, however , that no such action shall materially adversely affect the rights of any affected Participant or holder or Beneficiary under any Award theretofore granted under the Plan, except (x) to the extent any such action is made to cause the Plan to comply with applicable law, stock market or exchange rules and regulations or accounting or tax rules and regulations or (y) to impose any “clawback” or cancellation provisions on any Awards (including any amounts or benefits arising from such Awards) in accordance with Section 17;  provided ,   further , that, except as provided in Section 5(c), no such action shall directly or indirectly, through cancellation and regrant or any other method, reduce, or have the effect of reducing, the exercise price of any Award established at the time of grant thereof;  provided further , that the Committee’s authority under this Section 13(b) is limited in the case of Awards that are intended to qualify as Section 162(m) Compensation, as provided in Section 9.
(c)   Except as provided in Section 9, the Committee shall be authorized to make adjustments in the terms and conditions of, and the criteria included in, Awards in recognition of events (including the events described in Section 5(c)) affecting the Company, or the financial statements of the Company, or of changes in applicable laws, regulations or accounting principles, whenever the Committee determines that such adjustments are appropriate in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the Plan.
(d)   The Committee may correct any defect, supply any omission or reconcile any inconsistency in the Plan or any Award in the manner and to the extent it shall deem desirable to carry the Plan into effect.
Section 14.   Miscellaneous.
(a)   No employee, Participant or other Person shall have any claim to be granted any Award under the Plan, and there is no obligation for uniformity of treatment of employees, Participants or holders or Beneficiaries of Awards under the Plan.  The terms and conditions of Awards need not be the same with respect to each recipient.  Any Award granted under the Plan shall be a one-time Award that does not constitute a promise of future grants.  The Company, in its sole discretion, maintains the right to make available future grants under the Plan.
(b)   The grant of an Award shall not be construed as giving a Participant the right to be retained in the employ of, or to continue to provide services to, the Company or any Affiliate.  Further, the Company or the applicable Affiliate may at any time dismiss a Participant, free from any liability, or any claim under the Plan, unless otherwise expressly provided in the Plan or in
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any Award Document or in any other agreement binding the parties.  The receipt of any Award under the Plan is not intended to confer any rights on the receiving Participant except as set forth in the applicable Award Document.
(c)   Nothing contained in the Plan shall prevent the Company from adopting or continuing in effect other or additional compensation arrangements, and such arrangements may be either generally applicable or applicable only in specific cases.
(d)   The Company shall be authorized to withhold from any Award granted or any payment due or transfer made under any Award or under the Plan or from any compensation or other amount owing to a Participant the amount (in cash, Shares, other Awards, other property, net settlement, or any combination thereof) of applicable withholding taxes due in respect of an Award, its exercise or settlement or any payment or transfer under such Award or under the Plan and to take such other action (including providing for elective payment of such amounts in cash or Shares by such Participant) as may be necessary in the opinion of the Company to satisfy all obligations for the payment of such taxes .
(e)   If any provision of the Plan or any Award Document is or becomes or is deemed to be invalid, illegal or unenforceable in any jurisdiction, or as to any Person or Award, or would disqualify the Plan or any Award under any law deemed applicable by the Committee, such provision shall be construed or deemed amended to conform to applicable laws, or if it cannot be so construed or deemed amended without, in the determination of the Committee, materially altering the intent of the Plan or the Award Document, such provision shall be stricken as to such jurisdiction, Person or Award, and the remainder of the Plan and any such Award Document shall remain in full force and effect. 
(f)   Neither the Plan nor any Award shall create or be construed to create a trust or separate fund of any kind or a fiduciary relationship between the Company and a Participant or any other Person.  To the extent that any Person acquires a right to receive payments from the Company pursuant to an Award, such right shall be no greater than the right of any unsecured general creditor of the Company.
(g)   No fractional Shares shall be issued or delivered pursuant to the Plan or any Award, and the Committee shall determine whether cash or other securities shall be paid or transferred in lieu of any fractional Shares, or whether such fractional Shares or any rights thereto shall be canceled, terminated or otherwise eliminated.
Section 15.   Effective Date of the Plan.  The Plan was originally adopted on April 28, 2011.  The Plan, as amended herein, is effective as of January 23, 2015, subject to approval by the Company’s shareholders.
Section 16.   Term of the Plan.  No Award shall be granted under the Plan after the earliest to occur of (i) January 23, 2025, (ii) the maximum number of Shares available for issuance under the Plan have been issued or (iii) the Board terminates the Plan in accordance with Section 13(a).  However, unless otherwise expressly provided in the Plan or in an applicable Award Document, any Award theretofore granted may extend beyond such date, and the authority of the Committee to amend, alter, adjust, suspend, discontinue or terminate any such
15

 

Award, or to waive any conditions or rights under any such Award, and the authority of the Board to amend the Plan, shall extend beyond such date.
Section 17.   Cancellation or “Clawback” of Awards.  The Committee shall have full authority to implement any policies and procedures necessary to comply with Section 10D of the Exchange Act and any other applicable regulatory regimes.  Notwithstanding anything to the contrary contained herein, any Awards granted under the Plan (including any amounts or benefits arising from such Awards) shall be subject to any “clawback” or recoupment policies or arrangements the Company may have in effect from time to time, and the Committee may, to the extent permitted by applicable law and stock exchange rules or by any applicable Company policy or arrangement, and shall, to the extent required by any such law, rule, policy or arrangement, cancel or require reimbursement of any Awards granted to the Participant or any Shares issued or cash received upon vesting, exercise or settlement of any such Awards or sale of Shares underlying such Awards.
Section 18.   Section 409A of the Code.  With respect to Awards subject to Section 409A of the Code, the Plan is intended to comply with the requirements of Section 409A of the Code, and the provisions of the Plan and any Award Document shall be interpreted in a manner that satisfies the requirements of Section 409A of the Code, and the Plan shall be operated accordingly.  If any provision of the Plan or any term or condition of any Award would otherwise frustrate or conflict with this intent, the provision, term or condition shall be interpreted and deemed amended so as to avoid this conflict .   Notwithstanding anything in the Plan to the contrary, if the Board considers a Participant to be a “specified employee” under Section 409A of the Code at the time of such Participant’s “separation from service” (as defined in Section 409A of the Code), and any amount hereunder is “deferred compensation” subject to Section 409A of the Code, any distribution of such amount that otherwise would be made to such Participant with respect to an Award as a result of such “separation from service” shall not be made until the date that is six months after such “separation from service,” except to the extent that earlier distribution would not result in such Participant’s incurring interest or additional tax under Section 409A of the Code.  If an Award includes a “series of installment payments” (within the meaning of Section 1.409A-2(b)(2)(iii) of the Treasury Regulations), the Participant’s right to such series of installment payments shall be treated as a right to a series of separate payments and not as a right to a single payment, and if an Award includes “dividend equivalents” (within the meaning of Section 1.409A-3(e) of the Treasury Regulations), the Participant’s right to such dividend equivalents shall be treated separately from the right to other amounts under the Award.  Notwithstanding the foregoing, the tax treatment of the benefits provided under the Plan or any Award Document is not warranted or guaranteed, and in no event shall the Company be liable for all or any portion of any taxes, penalties, interest or other expenses that may be incurred by any Participant on account of non-compliance with Section 409A of the Code.
 
16

Exhibit 21.1
List of Subsidiaries
 	 	 	 	
Subsidiary	 	Jurisdiction of Incorporation	
Kosmos Energy Ltd.	 	Bermuda	
Kosmos Energy Holdings	 	Cayman Islands	
Kosmos Energy LLC	 	Texas	
Kosmos Energy Operating	 	Cayman Islands	
Kosmos Energy Ventures	 	Cayman Islands	
Kosmos Energy South Atlantic	 	Cayman Islands	
Kosmos Energy Latin America	 	Cayman Islands	
Kosmos Energy Brasil Oleo e Gas Ltda.	 	Brazil	
Kosmos Energy Deepwater Morocco	 	Cayman Islands	
Kosmos Energy Cameroon HC	 	Cayman Islands	
Kosmos Energy Offshore Morocco HC	 	Cayman Islands	
Kosmos Energy Finance International	 	Cayman Islands	
Kosmos Energy Finance	 	Cayman Islands	
Kosmos Energy International	 	Cayman Islands	
Kosmos Energy Development	 	Cayman Islands	
Kosmos Energy Ghana HC	 	Cayman Islands	
Kosmos Energy Suriname	 	Cayman Islands	
Kosmos Energy Ireland	 	Cayman Islands	
Kosmos Energy Mauritania	 	Cayman Islands	
Kosmos Energy Sierra Leone	 	Cayman Islands	
Kosmos Energy Equatorial Guinea	 	Cayman Islands	
Kosmos Energy Credit International	 	Cayman Islands	
FATE Energy Services	 	Cayman Islands	
Kosmos Energy Operating Service SARL	 	Morocco	
Kosmos Energy Liberia	 	Cayman Islands	
Kosmos Energy Portugal	 	Cayman Islands	
Kosmos Energy Senegal	 	Cayman Islands	
Kosmos Energy Global Supply	 	Cayman Islands	
Kosmos Energy Sao Tome and Principe	 	Cayman Islands	
Kosmos Energy Maroc Mer Profonde	 	Cayman Islands	
Kosmos BP Senegal Limited	 	United Kingdom	

 
Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the Registration Statements (Form S‑8 No. 333‑174234 and Form S-8 No. 333-207259) pertaining to the Kosmos Energy Ltd. Long Term Incentive Plan and the Registration Statement (Form S‑3 No. 333‑205144) of Kosmos Energy Ltd. and in the related Prospectus of our reports dated February 27, 2017, with respect to the consolidated financial statements and schedules and the effectiveness of internal control over financial reporting of Kosmos Energy Ltd., included in this Annual Report (Form 10‑K) for the year ended December 31, 2016.
 	 	
 	/s/ Ernst & Young LLP	
 
Dallas, Texas
February 27, 2017

 
Exhibit 23.2

 	February 12, 2017	
Mr. Eric Haas
Kosmos Energy, LLC
8176 Park Lane, Suite 500
Dallas, Texas 75231	 	
 
We hereby consent to (1) the reference of our firm and to the use of our reports of the Jubilee Field and TEN Project Area effective December 31, 2016 and dated January 13, 2017, in the Kosmos Energy Ltd. Annual Report on Form 10‑K for the year ended December 31, 2016, to be filed with the U.S. Securities Exchange Commission on or about February 27, 2017; and (2) the incorporation by reference of our reports of the Jubilee Field and TEN Project Area effective December 31, 2016 and dated January 13, 2017 in the Kosmos Energy Ltd. Registration Statements (Form S‑8, No. 333‑174234 and Form S-8, No. 333-207259) and Registration Statement (Form S‑3, No. 333‑205144) and in any related prospectus, including any reference to our firm under the heading “Experts” in such prospectus.
 	
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F‑1580	

 
Exhibit 31.1
Certification of Chief Executive Officer
I, Andrew G. Inglis, certify that:
 	1.	 	I have reviewed this annual report on Form 10‑K of Kosmos Energy Ltd.;	

 	2.	 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	

 	3.	 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	

 	4.	 	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:	

 	(a)	 	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	

 	(b)	 	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	

 	(c)	 	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	

 	(d)	 	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	

 	5.	 	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):	

 	(a)	 	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	

 	(b)	 	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	

Chairman of the Board of Directors and
Chief Executive Officer (Principal Executive Officer)
 	
Date: February 27, 2017	/s/ Andrew G. Inglis
Andrew G. Inglis
Chairman of the Board of Directors and
Chief Executive Officer (Principal Executive Officer)	

Exhibit 31.2
Certification of Chief Financial Officer
I, Thomas P. Chambers, certify that:
 	1.	 	I have reviewed this annual report on Form 10‑K of Kosmos Energy Ltd.;	

 	2.	 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	

 	3.	 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	

 	4.	 	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:	

 	(a)	 	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	

 	(b)	 	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	

 	(c)	 	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	

 	(d)	 	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	

 	5.	 	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):	

 	(a)	 	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	

 	(b)	 	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	

Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
 	
Date: February 27, 2017	/s/ Thomas P. Chambers
Thomas P. Chambers
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)	

Exhibit 32.1
Certification of Chief Executive Officer
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes‑Oxley Act of 2002
In connection with the accompanying annual report of Kosmos Energy Ltd. (the “Company”) on Form 10‑K for the period ended December 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Andrew G. Inglis, Chairman of the Board of Directors and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002, that to my knowledge:
 	(1)	 	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and	

 	(2)	 	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.	

Chairman of the Board of Directors and Chief Executive Officer
(Principal Executive Officer)
 	
Date: February 27, 2017	/s/ Andrew G. Inglis
Andrew G. Inglis
Chairman of the Board of Directors and Chief Executive Officer
(Principal Executive Officer)	
 
A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

 

 

Exhibit 32.2
Certification of Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes‑Oxley Act of 2002
In connection with the annual report of Kosmos Energy Ltd. (the “Company”) on Form 10‑K for the period ended December 31, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas P. Chambers, Senior Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002, that to my knowledge:
 	(1)	 	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and	

 	(2)	 	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.	

Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
 	
Date: February 27, 2017	/s/ Thomas P. Chambers
Thomas P. Chambers
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)	
 
A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

 

Exhibit 99.1

 	 
	 	
 	   TBPE REGISTERED ENGINEERING FIRM F-1580	FAX (713) 651-0849	
 	   1100 LOUISIANA   SUITE 4600	HOUSTON, TEXAS 77002-5294    	TELEPHONE (713) 651-9191	

 
 	 	
 	January 13, 2017	

Kosmos Energy, LLC	 	
8176 Park Lane, Suite 500	 	
Dallas, Texas  75231	

Gentlemen:
 
At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain interests of Kosmos Energy, LLC (Kosmos) as of December 31, 2016.  The subject properties are located in the country of Ghana offshore West Africa in the West Cape Three Points (WCTP) and Deep Water Tano (DWT) blocks, hereafter referred to as “Jubilee and TEN Project Area”.  The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).  Our third party study, completed on January 13, 2017 and presented herein, was prepared for public disclosure by Kosmos in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.
 
The properties evaluated by Ryder Scott in this report represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of Kosmos as of December 31, 2016. 
 
The estimated reserves and future net income amounts presented in this report, as of December 31, 2016, are related to hydrocarbon prices.  The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to December 31, 2016, determined as the un-weighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations.  Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The results of this study are summarized as follows.

 

SEC PARAMETERS
Estimated Net Reserves and Income Data
Derived Through Certain Interest in the Jubilee and TEN Project Area
Kosmos Energy, LLC
As of December 31, 2016

 	 	Proved	
 	    	Developed
Producing	    	Undeveloped	    	Total	
Jubilee Project Area	 	 	 	 	 	 	
Net Remaining Reserves	 	 	 	 	 	 	 	 	 	
Oil/Condensate – MBBL	 	 	42,631 	 	 	 	 	 	42,631 	
Fuel Gas – MMCF	 	 	8,221 	 	 	 	 	 	8,221 	
 	 	 	 	 	 	 	 	 	 	
TEN Project Area	 	 	 	 	 	 	 	 	 	
Net Remaining Reserves	 	 	 	 	 	 	 	 	 	
Oil/Condensate – MBBL	 	 	21,253 	 	 	10,346 	 	 	31,599 	
Fuel Gas – MMCF	 	 	4,669 	 	 	2,245 	 	 	6,914 	
 	 	 	 	 	 	 	 	 	 	
Total	 	 	 	 	 	 	 	 	 	
Net Remaining Reserves	 	 	 	 	 	 	 	 	 	
Oil/Condensate – MBBL	 	 	63,884 	 	 	10,346 	 	 	74,230 	
Fuel Gas – MMCF	 	 	12,890 	 	 	2,245 	 	 	15,135 	
 	 	 	 	 	 	 	 	 	 	
Income Data (M$)	 	 	 	 	 	 	 	 	 	
Future Gross Revenue	 	$	2,743,053 	 	$	443,840 	 	$	3,186,893 	
Deductions	 	 	1,447,319 	 	 	414,720 	 	 	1,862,039 	
Future Net Income (FNI)	 	$	1,295,734 	 	$	29,120 	 	$	1,324,854 	
 	 	 	 	 	 	 	 	 	 	
Discounted FNI @ 10% Before Taxes	 	$	972,525 	 	$	11,031 	 	$	983,556 	
Discounted FNI @ 10%  After Taxes	 	$	819,773 	 	$	17,559 	 	$	837,332 	
 	 	 	 	 	 	 	 	 	 	
Volumetric Data (Gross (100%))	 	 	 	 	 	 	 	 	 	
Jubilee Project Area	 	 	 	 	 	 	 	 	 	
Original Oil In Place (OOIP) – MBBL	 	 	1,095,399 	 	 	 	 	 	1,095,399 	
Estimated Ultimate Recovery (EUR) – MBBL	 	 	374,088 	 	 	 	 	 	374,088 	
 	 	 	 	 	 	 	 	 	 	
TEN Project Area	 	 	 	 	 	 	 	 	 	
Original Oil In Place (OOIP) – MBBL	 	 	401,674 	 	 	195,535 	 	 	597,209 	
Estimated Ultimate Recovery (EUR) – MBBL	 	 	136,916 	 	 	64,061 	 	 	200,977 	
 	 	 	 	 	 	 	 	 	 	
Total	 	 	 	 	 	 	 	 	 	
Original Oil In Place (OOIP) – MBBL	 	 	1,497,073 	 	 	195,535 	 	 	1,692,608 	
Estimated Ultimate Recovery (EUR) – MBBL	 	 	511,004 	 	 	64,061 	 	 	575,065 	

 

Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (MBBL).  All gas volumes are attributed to those volumes of gas that are consumed for fuel in field operations and are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.  In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).
 
The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PalantirCASH, a copyrighted product of Palantir Solutions.  The program was used at the request of Kosmos.  Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized.  Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding.  The rounding differences are not material.
 
The deductions include the normal direct costs of operating the wells and facilities, development costs, certain abandonment costs net of salvage, and Additional Oil Entitlements (“AOE”).  AOE is a contractual mechanism that prevents the contractor group from collecting “windfall profits” and is treated herein as a deduction to the future gross revenue; however, for the Jubilee and TEN Project Area our economic analysis indicates no AOE deductions for the proved reserves.  There are no production taxes associated with the Jubilee and TEN Project Area.  The Discounted FNI @ 10% Before Taxes shown above does not include deductions for corporate income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income.  This FNI value was then adjusted by deducting corporate income taxes and the result is shown above as “Future Net Income @ 10% After Taxes”.  The AOE calculation is determined at the block level and includes a rate of return calculation that is derived on an after corporate income tax basis based on interpretations of tax considerations made by Kosmos.  All deductions pertaining to operating expenses, depletion, abandonment and royalties that were applied towards the calculation of corporate income taxes are strictly related to the Jubilee and TEN contract area.  There are no corporate income tax deductions for the AOE calculation that are related to expenditures, royalties, or any other deductible items outside of the Jubilee and TEN Project area.  Liquid hydrocarbon reserves account for 100 percent of the total future gross revenue from proved reserves.
 
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded annually.  These results are presented for your information and should not be construed as our estimate of fair market value.
 
Reserves Included in This Report
 
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
 
The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. 
 
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.”  All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote

 

progressively increasing uncertainty in their recoverability.  At Kosmos’ request, this report addresses only the proved reserves attributable to the properties evaluated herein.
 
Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.”  The proved reserves included herein were estimated using deterministic methods.  The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” 
 
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.  For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”  Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.  Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.
 
The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production.  Furthermore, the subject properties located in Ghana may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Kosmos for the production of these volumes.  The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts.  Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Kosmos the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof.  Ryder Scott has not conducted an exhaustive audit or verification of such contractual information.  Neither our review of such contractual information nor our acceptance of Kosmos representations regarding such contractual information should be construed as a legal opinion on this matter.
 
Ryder Scott did not evaluate the country and geopolitical risks in the country of Ghana, where Kosmos operates or has interests.    Kosmos operations may be subject to various levels of governmental controls and regulations.  These controls and regulations may include, but may not be limited to, matters relating to the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time.  Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
 
The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Kosmos owns   an interest; however, we have not made any field examination of the properties.  No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
 
Estimates of Reserves
 
The estimation of reserves involves two distinct determinations.  The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures.  These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy.  These methods may be used individually or in combination by the reserve evaluator in the process of

 

estimating the quantities of reserves.  Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.
 
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator.  When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves.  If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator.  Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported.  For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.”  The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.”  The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.”  All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
 
Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available.  Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
 
The proved reserves for the properties included herein were estimated by a combination of performance methods, analogy and the volumetric methods.  One hundred percent (100%) of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by a combination of methods.  The performance methods include, but may not be limited to, reservoir simulation, which utilized extrapolations of historical production and pressure data available through December 15, 2016 in those cases where such data were considered to be definitive.  The data utilized in this analysis were furnished to Ryder Scott by Kosmos and were considered sufficient for the purpose thereof. 
 
One hundred percent (100%) of the proved undeveloped reserves included herein were estimated by a combination of the volumetric method and numerical reservoir simulation.  These methods were used as a result of limited production performance data to establish performance trends or to use as a basis for reserve estimates.  Well and seismic data incorporated into our volumetric analysis were provided by Kosmos and were considered sufficient for the purpose thereof.
 
The field development plan was incorporated into the newly developed reservoir simulation model for the TEN Project Area to estimate recovery factors.  These recovery factors, when compared with actual and predicted estimates from the offset Jubilee field are considered reasonable.  The Jubilee field has historically been operated under a pressure maintenance plan by means of gas and water injection.  The same type of pressure maintenance method is planned for the TEN Project Area.
 
To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.  Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic

 

conditions including the prices and costs at which economic producibility from a reservoir is to be determined.  While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
 
Kosmos has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation.  In preparing our forecast of future proved production and income, we have relied upon data furnished by Kosmos with respect to property interests and contractual terms that govern future net income, production and well tests from examined wells, normal direct costs of operating the  Jubilee and TEN Project Area and all the required facilities such as the FPSO, other costs such as transportation and/or processing fees, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements.  Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Kosmos.  We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
 
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein.  The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.”  In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
 
Future Production Rates
 
For the Jubilee Project Area, our forecasts of future production rates are based on a combination of historical performance data, volumetric analysis and a robust numerical simulation model.  Future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated.  An estimated “simulation based decline rate” was then applied to depletion of the reserves. 
For the TEN Project Area, our forecasts of future production rates are based on the history-matched numerical simulation model predictions.  These forecasts were adjusted to limit the daily oil production output to the FPSO capacity of 80,000 barrels per day less a five percent (5%) downtime assumption.  Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing.  For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Kosmos.  Wells or locations may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production.  Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. 
 
The future production rates from the subject wells and locations may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
 
Hydrocarbon Prices
 
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to December 31, 2016, determined as the un-weighted

 

arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements.  For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract.  All the proved volumes projected herein are forecast to be recovered prior to contract expiration. 
 
Kosmos furnished us with the above mentioned average prices in effect on December 31, 2016.  These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold.  These benchmark prices are prior to the adjustments for differentials as described herein.  The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in this report. 
 
The product prices that were actually used to determine the future gross revenue for the subject property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.”  The differentials used in the preparation of this report were furnished to us by Kosmos.  In the case of the Jubilee Project Area, Kosmos has estimated that the applicable differential is +$0.057/bbl.  In the case of the recently producing TEN Project Area with no cargo sales data available, Kosmos has estimated that no differential should be applied to the oil price. . The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Kosmos to determine these differentials.
 
In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.”  The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

 

Geographic Area	    	Product	    	Price
Reference	    	Average
Benchmark
Price	    	Average
Realized
Price	 	
West Africa	 	 	 	 	 	 	 	 	 	 	 	
Jubilee Project Area	 	Oil	 	Brent	 	$	42.90/Bbl	 	$	42.96/Bbl	 	
TEN Project Area	 	Oil	 	Brent	 	$	42.90/Bbl	 	$	42.90/Bbl	 	
 
The effects of derivative instruments designated as price hedges of oil quantities are not reflected in our individual property evaluations. 
 
Costs
 
Operating costs for the properties in this report were furnished by Kosmos and are based on their operating expense reports for the Jubilee Project Area and TEN Project Area.  Such costs include only those costs directly applicable to the subject properties.  The operating costs include a portion of general and administrative costs allocated directly to the contract area and wells.  The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Kosmos.  No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the contract area or wells.
 
Development costs were furnished to us by Kosmos and are based on authorizations for expenditure for the proposed work or actual costs for similar projects.  The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs.  The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant.  The estimates of the net abandonment costs furnished by Kosmos were accepted without independent verification.
 
The proved undeveloped reserves in this report have been incorporated herein in accordance with Kosmos’ plans to develop these reserves as of December 31, 2016.  The implementation of Kosmos’ development plans as presented to us and incorporated herein is subject to the approval process adopted by Kosmos’ management.  As the result of our inquiries during the course of preparing this report, Kosmos has informed us that the development activities included herein have been subjected to and received the internal approvals required by Kosmos management at the appropriate local, regional and/or corporate level.  In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Kosmos.  Additionally, Kosmos has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans.  While these plans could change or evolve from those under existing economic conditions as of December 31, 2016, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
 
Current costs used by Kosmos were held constant throughout the life of the properties until a time in the future where Kosmos has estimated that expected synergies from unifying the activities of both project areas and late field life ramp down activities indicate a reduction in costs.

 

TEN Project Area Boundary Dispute
 
In July 2015, Ryder Scott was made aware of an ongoing boundary dispute between the countries of Côte d’Ivoire and Ghana regarding the ownership of the maritime waters hosting some portion of the TEN Project Area and this matter was discussed extensively with Kosmos.  The case is currently before the Special Chamber of the International Tribunal of the Law of the Sea (ITLOS) with a final ruling expected in late 2017.  However, the tribunal issued some provisional measures which allowed the project to commence production in August 2016 with five (5) producing wells coming on-stream as planned.  Neither Kosmos Energy nor Ryder Scott are parties to this arbitration process.  We have relied on the information provided to us by Kosmos Energy, who has full confidence that the ITLOS will rule in Ghana’s favor with no impact on the project contract terms or schedule. Potential outcomes of a final ruling and the resultant effect on future development and reserves were not incorporated into our reserves analyses.
 
Standards of Independence and Professional Qualification
 
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937.  Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada.  We have over eighty engineers and geoscientists on our permanent staff.  By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue.  We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients.  This allows us to bring the highest level of independence and objectivity to each engagement for our services.
 
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations.  Many of our staff have authored or co-authored technical papers on the subject of reserves related topics.  We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
 
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
 
We are independent petroleum engineers with respect to Kosmos Energy, LLC.  Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
 
The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott.  The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

 

Terms of Usage
 
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Kosmos.
 
Kosmos makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act.  Furthermore, Kosmos has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference.  We have consented to the incorporation by reference in the registration statements on Forms S-3 and S-8 of Kosmos Energy, LLC of the references to our name as well as to the references to our third party report for Kosmos Energy, LLC, which appears in the December 31, 2016 annual report on Form 10-K of Kosmos Energy, LLC.  Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Kosmos Energy, LLC.
 
We have provided Kosmos with a digital version of the original signed copy of this report letter.  In the event there are any differences between the digital version included in filings made by Kosmos and the original signed report letter, the original signed report letter shall control and supersede the digital version.
 
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please contact us if we can be of further service.
 
 	Very truly yours,	    	
 	 	 	
 	RYDER SCOTT COMPANY, L.P.	 	
 	TBPE Firm Registration No. F-1580	 	

 	 	 	
 	\s\ Guale Ramirez	 	
 	 	 	
 	Guale Ramirez, P.E.	 	
 	TBPE License No. 48318	 	
 	Executive Vice President	 	

 	 	 	
 	 	 	
 	\s\ Tosin Famurewa	 	
 	 	 	
 	Tosin Famurewa, P.E., S.P.E.C.	 	
 	TBPE License No. 100569	 	
 	Senior Vice President – International	 	
 	 	 	
 	\s\ Victor Abu	 	
 	 	 	
 	Victor Abu	 	
 	Senior Petroleum Engineer	 	
 	 	 	
GR-TF-VA (DPR)/pl	 	 	

 

Professional Qualifications of Primary Technical Person
 
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.  Guadalupe Ramirez was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.
 
Mr. Ramirez, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1981, is the Executive Vice President and also serves as a member of the Board of Directors.  He is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide.  Before joining Ryder Scott, Mr. Ramirez served in a number of engineering positions with Sun Oil Company and Natomas North America.  For more information regarding Mr. Ramirez’s geographic and job specific experience, please refer to the Ryder Scott Company website at  www.ryderscott.com/Company/Employees .
 
Mr. Ramirez earned a Bachelor of Science Degree in Mechanical Engineering with honors from Texas A&M University in 1976 and is a licensed Professional Engineer in the State of Texas.  He is also a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers.
 
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Ramirez fulfills.  As part of his 2016 continuing education hours, Mr. Ramirez attended and internally received 21 hours of formalized training as well as a day-long public forum, the 2016 RSC Reserves Conference relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register.  Mr. Ramirez has also presented courses on the new SEC and SPE-PRMS reserves definitions on various occasions during 2011, 2012, 2013 and 2015 and received 8 hours of formalized external training during 2016, covering such topics as the Guidelines for Application of the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software, unconventional resources and ethics for consultants.
 
Based on his educational background, professional training and more than 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Ramirez has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

PETROLEUM RESERVES DEFINITIONS
 
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE
 
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA).  The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K.  The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”.  The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.  Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).
 
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.     All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC.  The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
 
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.
 
Reserves may be attributed to either natural energy or improved recovery methods.  Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.  Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids.  Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
 
Reserves may be attributed to either conventional or unconventional petroleum accumulations.  Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. 
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

PETROLEUM RESERVES DEFINITIONS
Page 2

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.  These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale. 
 
Reserves do not include quantities of petroleum being held in inventory.
 
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)
 
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
 
Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project. 
 
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results).  Such areas may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)
 
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
 
Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
(i) The area of the reservoir considered as proved includes:
 
(A) The area identified by drilling and limited by fluid contacts, if any, and
 
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

PETROLEUM RESERVES DEFINITIONS
Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED
 
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
 
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
 
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
 
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
 
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
 
and
 
PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs.  Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)
 
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
 
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
 
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
Developed Producing (SPE-PRMS Definitions)
 
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.
 
Developed Producing Reserves 
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
 
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 2

Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
 
Shut-In
Shut-in Reserves are expected to be recovered from:
 	(1)	 	completion intervals which are open at the time of the estimate, but which have not  started producing;	

 	(2)	 	wells which were shut-in for market conditions or pipeline connections; or	

 	(3)	 	wells not capable of production for mechanical reasons.	
 
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production. 
 
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)
 
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
 
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
 
(i)  Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
 
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
 
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS