10-K 1 kos-20161231x10k.htm 10-K kos_Current folio_10K

 

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

Picture 2

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.

 

 

 


 

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

 

Cautionary Statement Regarding Forward‑Looking Statements

 

PART I

 

Item 1. 

Business

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.

14


 

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.

15


 

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.

17


 

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.

18


 

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.

19


 

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.

20


 

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.

21


 

 

 

 

 

 

 

 

 

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

22


 

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

23


 

“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.

24


 

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

25


 

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.

26


 

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

27


 

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