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2015 ANNUAL REPORT F I N A N C I A L STRENGTH C A P I T A L DISCIPLINE S H A R E H O L D E R VALUE W ith three major hydrocarbon discoveries in the last year Kosmos is entering an exciting next phase in its history. Our strong balance sheet and disciplined approach to capital allocation enables us to invest through the cycle so we can continue to create value for shareholders. 1 Since its founding in 2003 Kosmos has successfully invested through the commodity cycle thanks to the maintenance of a strong balance sheet and disciplined allocation of capital. When Brent crude averaged above 100 per barrel and it was fashionable to drill exploration wells and grow at any cost we used our high-margin cash flow from the Jubilee Field to consistently reduce debt and build liquidity. Our prudent approach to managing the business has meant that we entered this latest downturn with a solid financial foundation high-margin production and exciting near- term prospects to drill following our success in opening the outboard petroleum system offshore Mauritania and Senegal. Our competitors arent so fortunate. Many are struggling to cope with continued market turbulence and are cutting expenditures just to survive. In stark contrast we enjoy robust liquidity low leverage and a well-hedged production profile. This favorable position combined with growing production enables Kosmos to continue executing its strategy to create value for shareholders. Our expected investment program for 2016 balances our ongoing commitment to capital discipline with the ambition and promise of our growth plan. We expect to spend approximately 650 million representing a nearly 20 percent reduction from last year. The work program that underpins this capital level has been high-graded to the essential activities that we believe will create the most long- term value for shareholders Delivering growth in production and cash flow from Ghana Unlocking Mauritania and Senegals full potential and Delivering further success from our exploration portfolio. With this level of capital expenditure we expect to end 2016 with liquidity of approximately 1.3 billion if Brent averages 35 per barrel for the year. DELIVERING GROWTH IN PRODUCTION AND CASH FLOW FROM GHANA In Ghana we are investing in our core asset the Jubilee Field which continues to deliver high-quality cash flow. Gross production from Jubilee averaged approximately 102500 barrels of oil per day sales throughout 2015 resulting in nine cargoes net to Kosmos. Gas production from Jubilee was also strong ending the year at more than 110 million cubic feet per day. In addition for the third consecutive year we delivered a reserve replacement ratio above 100 percent confirming the view that big fields get bigger. Kosmos proved net reserves at the end of 2015 were 76 million barrels of oil equivalent. Reserves increased primarily due to continued strong reservoir performance more than offsetting the impact of lower oil prices. In December 2015 the Greater Jubilee Full Field Development Plan and Unit Expansion Agreement for the Mahogany and Teak fields were submitted to the Government of Ghana. Approval of the plan should enable the partnership to develop the Mahogany and Teak fields through the Jubilee FPSO. The TEN project our second major oil development in Ghana is now more than 90 percent complete and remains on schedule and within budget. We expect TEN to produce first oil in the third quarter of 2016. By 2017 we anticipate significant growth from Ghana with the TEN project expected to increase net production by nearly 50 percent over 2015. With declining capital requirements this should result in significant cash flow generation from Ghana providing Kosmos with added financial flexibility. FELLOW SHAREHOLDERS 2 UNLOCKING MAURITANIA AND SENEGALS FULL POTENTIAL In Mauritania and Senegal our 2016 program is centered on the efficient appraisal of the Tortue discovery drilling one of three independent oil tests and acquiring additional seismic to better define the prospectivity of the remaining oil potential. With a series of successful exploration and appraisal wells on the West Tortue structure we have discovered a significant amount of natural gas and believe we have opened one of the largest new petroleum systems anywhere in the world over the last 15 years. Given better-than-expected results and growing confidence in our understanding of the basin we believe we have de-risked sufficient resource to underpin a world-scale LNG project. Kosmos is now working toward commercialization by developing a project concept that delivers competitive gas in the current market environment. In addition we are facilitating an intergovernmental cooperation agreement between Mauritania and Senegal to enable early development of the cross-border Tortue resource. In early 2016 we entered into a Memorandum of Understanding MOU with Socit des Ptroles du Sngal Petrosen and Socit Mauritanienne Des Hydrocarbures et de Patrimoine Minier SMHPM the national oil companies of Senegal and Mauritania which sets out the principles on which a formal agreement will be based. Beyond commercializing Tortue our focus in Mauritania and Senegal remains on fully unlocking this super-major scale hydrocarbon province. Based on our well results and seismic data we are confident in the basins potential to hold both significant gas and oil resources. At this time we have matured a stand-out oil prospect offshore Senegal in the Cayar Offshore Profond block which will test the first of three independent oil fairways in the second quarter of 2016. After we complete this well we plan to pause our drilling activity until 2017 to integrate the results into our model of the petroleum system. This will ensure we continue to drill the best prospects first in the other two oil tests and allocate our capital prudently. DELIVERING FUTURE EXPLORATION SUCCESS Looking ahead to the next phase of the companys growth in order to deliver new basin-opening success we continue to build and high-grade our exploration portfolio during this time of opportunity in which there is less competition as a result of lower commodity prices. In 2015 Kosmos withdrew from Ireland and entered So Tom and Prncipe. This natural turnover reflects the reality that everything in our portfolio has to compete for capital. In our current portfolio we are focused on maturing Suriname and Portugal for drilling through additional acquisition of seismic data and analysis. Suriname in particular remains a place where we continue to see great potential especially given recent industry success in the region. STRENGTH DISCIPLINE VALUE Looking ahead the near-term business climate is likely to remain challenging with the price of oil staying lower for even longer. I am confident that Kosmos is well-positioned to navigate through this turbulence and emerge stronger than ever. The combination of our financial strength our world-class assets in Ghana the Tortue discovery and exploration upside provides Kosmos with significant opportunity during the current down-cycle. We are focused on protecting our balance sheet and financial position to ensure we can continue to execute our plan. We have a long record of allocating capital with discipline and we will maintain that course. At the heart of our success is a dedicated group of employees among the best in the business who remain fully committed to our bright future. We accomplished a great deal in 2015 but there is much more for us to do. I am confident that our 2016 work program will create lasting value for our shareholders. ANDREW ANDY G. INGLIS Chairman of the Board and Chief Executive Officer 3 MAURITANIA AND SENEGAL With three major discoveries offshore Mauritania and Senegal within the last year Kosmos has opened one of the worlds largest new petroleum systems. With the Tortue-1 well in Block C8 offshore Mauritania and the Guembeul-1 well offshore Senegal Kosmos has discovered a world-class gas field that extends into both countries. Kosmos has entered into a Memorandum of Understanding MOU signed by Socit des Ptroles du Sngal Petrosen and Socit 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 field. Separately the Marsouin discovery located approximately 60 kilometers north of Tortue was announced in November 2015 as a significant play-extending find. With excellent well-to-seismic calibration we have growing confidence in our understanding of the regional petroleum system and continue to believe that it holds both gas and oil. EXPLORATION PORTFOLIO Kosmos acquired acreage in four blocks offshore So Tom and Prncipe marking a strategic re-entry into the Gulf of Guinea. These blocks cover an area of approximately 25000 square kilometers and are adjacent to a proven petroleum system in Equatorial Guinea and Gabon. This addition is an excellent example of how we are taking advantage of the industrys down-cycle to high-grade our exploration portfolio by pursuing select opportunities that can be competitive with other sources of oil supply even in a lower oil price environment. In September 2015 we notified the government of Ireland and our partners that we are withdrawing from all of our blocks offshore Ireland. The decision was based on the need to prioritize the opportunities within our exploration portfolio. Atlantic Ocean SENEGAL MAURITANIA CAYAR OFFSHORE PROFOND ST. LOUIS OFFSHORE PROFOND BLOCK C8 BLOCK C12 BLOCK C13 SENEGAL MAURITANIA GUEMBEUL-1 MARSOUIN-1 TORTUE-1 Gulf of Guinea EQUATORIAL GUINEA BLOCK 11 BLOCK 12 BLOCK 6 BLOCK 5 GABON SO TOM PRNCIPE HIGHLIGHTS BUSINESS EXPLORATION 4 JUBILEE FIELD We delivered our 2015 operations plan in Ghana with gross production volumes from the Jubilee Field averaging approximately 102500 barrels of oil per day for the full year 2015 resulting in nine cargo liftings net to Kosmos. In addition the companys proved net reserves at the end of 2015 were 76 million barrels of oil equivalent resulting in a reserve replacement ratio above 100 percent. Reserves increased primarily due to continued positive reservoir performance more than offsetting the impact of lower oil prices. TEN PROJECT The Tweneboa Enyenra and Ntomme TEN project the second major oil development offshore Ghana remains on schedule to deliver first oil in the third quarter of 2016. Production is expected to increase toward the FPSO capacity of approximately 80000 barrels gross of oil per day in the months following field start-up. GREATER JUBILEE FULL FIELD DEVELOPMENT PLAN The Greater Jubilee Full Field Development Plan and Unit Expansion Agreement incorporating the Mahogany and Teak fields was submitted to the Ghanaian Ministry of Petroleum in December 2015. Upon approval of the plan the partnership will be able to start developing the Greater Jubilee area by connecting the Mahogany and Teak fields to the Jubilee FPSO. WEST CAPE THREE POINTS BLOCK TEAK MAHOGANY Gulf of Guinea GHANA JUBILEE HIGHLIGHTS BUSINESS DEVELOPMENT AND PRODUCTION SURINAME GHANA SO TOM and PRNCIPE PORTUGAL MOROCCO WESTERN SAHARA SENEGAL MAURITANIA PHASE 2 Exploring the block through site and seismic surveys PHASE 3 Undertaking exploration drilling PHASE 6 Production PHASE 1 Entering a new market PHASE 4 Appraisal drilling PHASE 5 Development THE PROJECT LIFECYCLE The diagram below outlines the oil and gas project lifecycle from entering a new market to exploration and if successful production. The colors on the diagram correspond to the countries and areas of operation listed on the map above to show where we are in the project lifecycle. 5 6 CORPORATE RESPONSIBILITY FINANCIAL HIGHLIGHTS Year Ended 2015 2014 2013 in thousands except volume data Revenues and other income 471556 882738 852153 Income tax expense 155272 298898 166998 Net income loss attributable to common shareholders 69836 279370 91044 Net cash provided by operating activities 440779 443586 522404 Capital expenditures 777 204 528414 424676 Total Assets 3203050 2926859 2311665 Total long-term debt 860878 748362 865839 Total shareholders equity 1325513 1338959 992335 Production thousand barrels of oil per day 23.4 23.4 22.5 Sales volumes million barrels 8.5 8.7 7.8 Total proved reserves million barrels of oil equivalent 76 75 47 Crude oil million barrels 74 73 45 Natural gas billion cubic feet 14 14 11 Corporate responsibility is an important part of our strategy for creating value and positioning Kosmos as a preferred partner for governments and citizens alike. Our corporate character and policies are guided by our Business Principles which define our standards in the areas of ethical conduct our workplaces environmental performance human rights community engagement and commercial relationships. We invite you to learn more by reading our Corporate Responsibility Report and our Business Principles which are both available for download on our website. Statement of Business Principles 6APR201207345158 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington D.C. 20549 FORM 10-K Mark One ANNUAL REPORT PURSUANT TO SECTION 13 OR 15d OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31 2015 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15d OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 001-35167 Kosmos Energy Ltd. Exact name of registrant as specified in its charter Bermuda 98-0686001 State or other jurisdiction of I.R.S. Employer incorporation or organization Identification No. Clarendon House 2 Church Street Hamilton Bermuda HM 11 Address of principal executive offices Zip Code Registrants telephone number including area code 1 441 295 5950 Securities registered pursuant to Section 12b 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 12g 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 15d 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 15d 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 registrants 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 Smaller reporting company Do not check if a 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 registrants common shares as of the last business day of the registrants most recently completed second fiscal quarter was 1310263359. The number of the registrants Common Shares outstanding as of February 16 2016 was 385253510. 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 2015. 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Cautionary Statement Regarding Forward-Looking Statements . . . . . . . . . . . . . . . . . 6 PART I Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 Item 4. Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 PART II Item 5. Market for the Registrants Common Equity Related Stockholder Matters and Issuer Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81 Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . 101 Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149 Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149 Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150 PART III Item 10. Directors Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . 154 Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154 Item 13. Certain Relationships and Related Transactions and Director Independence . . . . . . . 154 Item 14. Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154 PART IV Item 15. Exhibits Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155 1 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 4-10a 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 6000 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. 2 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. EP . . . . . . . . . . . . . . . . . . . . . . . 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 andor for the assignee taking on a portion of the drilling costs of one or more specific wells andor other work as a condition of the assignment. 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 the depletion of the Jubilee Field plus the net present value of the forecast of certain 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. 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. 3 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 EP 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. Prospects . . . . . . . . . . . . . . . . . . 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 andor 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 4-10a2. 4 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 EP company rights to perform evaluation of existing data or potentially acquire additional data but may not convey an exclusive option to explore for develop andor 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. Structural trap . . . . . . . . . . . . . . . . A topographic feature in the earths 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. 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. 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. 5 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. Managements 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 Portugal 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 and maintain 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 6 adverse effects of sovereign boundary disputes in the jurisdictions in which we operate including an ongoing maritime boundary demarcation dispute between Cote dIvoire and Ghana impacting our operations in the Deepwater Tano Block offshore Ghana environmental liabilities geological technical drilling production and processing problems 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 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 the result of any legal proceedings or investigations we may be subject to 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 andor 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. 7 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 Margin. Our assets include existing production and development projects offshore Ghana large discoveries offshore Mauritania and Senegal as well as exploration licenses with significant hydrocarbon potential offshore Portugal 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 teamwho had previously worked together making significant discoveries and developing them in Africa the Gulf of Mexico and other areasestablished the company on a single geologic concept that previously had been overlooked 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. Gross production from the Jubilee Field averaged approximately 102500 Bopd for 2015. Following our Initial Public Offering we acquired several new exploration licenses and again proved our geologic concept with the Ahmeyim discovery in the deepwater offshore Mauritania in 2015. The Ahmeyim discovery formerly known as Tortue 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 the gas discovery into Senegal with the successful Guembeul-1 exploration well. Our business strategy focuses on achieving three key objectives 1 maximize the value of our Ghana assets 2 continue to explore and appraise the deepwater basin offshore Mauritania and Senegal to maximize and monetize value and 3 increase value further through a high-impact exploration program to unlock new petroleum systems. In Ghana we are focused on increasing production cash flows and reserves from the Jubilee Field the development of the Tweneboa-Enyenra- Ntomme TEN project and the appraisal and development of our other Ghanaian discoveries. In Mauritania and Senegal we expect to efficiently appraise and develop our current Ahmeyim discovery as well as continue to test our inventory of oil and gas prospects. We have a large inventory of leads and prospects in the remainder of our exploration portfolio which we plan to continue to build through new ventures and we plan to test this prospectivity targeting high impact opportunities along the Atlantic Margin. 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 and debottlenecking the Jubilee Field including incorporating our Mahogany and Teak discoveries into the Greater Jubilee Full Field Development Plan GJFFDP and by completing the TEN development which is expected to deliver first oil in the third quarter of 2016 through a second dedicated FPSO. In 8 the medium-term growth could also be realized following the appraisal and ongoing assessment of commerciality and development over all or a portion of our new discoveries in Mauritania and Senegal. In the longer-term we plan to drill exploration prospects with the intent to provide further growth in reserves and ultimately production. Successfully open and develop our offshore exploration plays We believe the prospects and leads potentially existing offshore Mauritania Portugal Sao Tome and Principe Senegal Suriname and Western Sahara in particular provide a favorable opportunity to create substantial value through exploration drilling. 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. Apply our entrepreneurial culture which fosters innovation and creativity to continue our successful exploration and development program We differentiate ourselves from other exploration and production companies through our approach to exploration and development. Our geoscientists and engineers are critical to the success of our business strategy. 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 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. Focus on optimally developing our discoveries to initial production We focus on field developments 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 detail 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. Additionally we look to partner with high quality industry partners with world-class development capabilities early in our exploration projects. This strategy is designed to ensure that upon successful exploration and appraisal activities the project can benefit from development and production 9 operations expertise provided by these partners as we have done with BP plc BP in Morocco and Chevron Corporation Chevron in Suriname. 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 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 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 approach reduces the exploratory risk in poorly understood under-explored or otherwise overlooked hydrocarbon basins that offer significant hydrocarbon potential. 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. 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. Maintain Financial Discipline We strive to maintain a conservative financial profile and strong balance sheet with ample liquidity. Typically we fund exploration activities from a combination of production cash flows or partner carries and development activities from a combination of production cash flows and debt. As of December 31 2015 we have approximately 1.8 billion of liquidity available to fund our opportunities. 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 2015 we have hedged positions covering 10.9 million barrels of oil from 2016 to 2018 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 asset. Kosmos Exploration Approach Kosmos exploration philosophy is deeply rooted in a fundamental geologically-based approach geared toward the identification of misunderstood under-explored or overlooked petroleum systems. This process begins with detailed geologic studies that methodically assess a particular regions subsurface with careful consideration given to those attributes that lead to 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 reservoirseal 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 accumulation. Once an area is high-graded based on this playfairway analysis geophysical analysis based on new 3D seismic is conducted to identify prospective traps of interest. 10 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 countrys 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 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. Operations by Geographic Area We currently have operations in Africa Europe 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 1A1 . . . . . . . . WCTPDT2 24.14 Tullow Production Jubilee Field subsequent phases . . . . . . . . . . . . . WCTPDT2 24.14 Tullow Development TEN1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . DT 17.05 Tullow Development Mahogany . . . . . . . . . . . . . . . . . . . . . . . . . . . . WCTP 24.16 Kosmos6 Appraisal Teak . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . WCTP 24.16 Kosmos6 Appraisal Akasa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . WCTP 30.967 Kosmos Appraisal Wawa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . DT 18.07 Tullow Appraisal Mauritania Ahmeyim . . . . . . . . . . . . . . . . . . . . . . . . . . . . Block C83 90.089 Kosmos8 Appraisal Marsouin . . . . . . . . . . . . . . . . . . . . . . . . . . . . Block C8 90.089 Kosmos8 Appraisal Senegal Guembeul . . . . . . . . . . . . . . . . . . . . . . . . . . . . Saint Louis 60.010 Kosmos Appraisal Offshore Profond3 1 For information concerning our estimated proved reserves as of December 31 2015 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. Consistent with the Ghana Petroleum Exploration and Production Law of 1984 PNDCL 84 the Ghanaian Petroleum Law the WCTP petroleum contract and DT petroleum contract and as required by Ghanas Ministry of Petroleum formerly Ghanas Ministry of Energy and Petroleum 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. 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 11 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 development 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 Ghanas Ministry of Petroleum 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 GNPCs 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 2015 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 Ghanas Ministry of Petroleum. 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 In March 2015 we closed a farm-out agreement covering our three license areas in Mauritania with Chevron. As a component of the consideration for the farm-out Chevron was required to make an election by February 1 2016 to either farm-in to the Tortue-1 exploration well by paying a disproportionate share of the costs incurred in drilling of the well or alternatively elect to not farm-in to the Tortue-1 exploration well and pay a disproportionate share of the costs of a second contingent exploration or appraisal well in the contract areas subject to maximum expenditure caps. Chevron failed to make this mandatory election by the required date. Consequently pursuant to the terms of the farm-out agreement Chevron has withdrawn from our Mauritania blocks. Subsequently Chevron requested that we engage in discussions related to the possible reinstatement of Chevrons interests in our Mauritania blocks and such discussions are ongoing. However if no such agreement is reached in these discussions Chevrons 30 non-operated participating interest will be reassigned to us subject to requisite government approvals and our participating interests in the Block C8 C12 and C13 petroleum contracts will be 90. 9 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. 10 PETROSEN has the option to acquire up to an additional 10 paying interests in a commercial development on the Saint Louis Offshore Profond block. The interest percentage does not give effect to the exercise of such option. 12 Exploration License Areas1 Operator Participating Interest Partners Participating Interest Mauritania Block C8 . . . . . . . . . . . . . . . . . . . . Kosmos 903 SMHPM 10 Block C12 . . . . . . . . . . . . . . . . . . . . Kosmos 903 SMHPM 10 Block C13 . . . . . . . . . . . . . . . . . . . . Kosmos 903 SMHPM 10 Morocco including Western Sahara Cap Boujdour . . . . . . . . . . . . . . . . . Kosmos 55 Cairn 20 ONHYM 25 Essaouira . . . . . . . . . . . . . . . . . . . . Kosmos 30 BP 45 ONHYM 25 Foum Assaka . . . . . . . . . . . . . . . . . Kosmos 29.9 BP 26.3 ONHYM 25.0 Pathfinder 9.4 SK Innovation Co. Ltd 9.4 Tarhazoute . . . . . . . . . . . . . . . . . . . Kosmos 30 BP 45 ONHYM 25 Portugal Ameijoa . . . . . . . . . . . . . . . . . . . . . Repsol 34 Kosmos 31 Galp 30 Partex 5 Camarao . . . . . . . . . . . . . . . . . . . . Repsol 34 Kosmos 31 Galp 30 Partex 5 Mexilhao . . . . . . . . . . . . . . . . . . . . Repsol 34 Kosmos 31 Galp 30 Partex 5 Ostra . . . . . . . . . . . . . . . . . . . . . . . Repsol 34 Kosmos 31 Galp 30 Partex 5 Sao Tome and Principe Block 52 . . . . . . . . . . . . . . . . . . . Kosmos 65 ANP 15 Equator 20 Block 6 . . . . . . . . . . . . . . . . . . . . . . Galp 45 Kosmos 45 ANP 10 Block 11 . . . . . . . . . . . . . . . . . . . . . Kosmos 85 ANP 15 Senegal Cayar Offshore Profond . . . . . . . . . . Kosmos 60 PETROSEN 10 Timis 30 Saint Louis Offshore Profond . . . . . Kosmos 60 PETROSEN 10 Timis 30 Suriname Block 42 . . . . . . . . . . . . . . . . . . . . . Kosmos 50 Chevron 50 Block 45 . . . . . . . . . . . . . . . . . . . . . Kosmos 50 Chevron 50 1 In September 2015 we notified the government of Ireland and our partners that we are withdrawing from the Frontier Exploration Licenses 113 213 and 313 offshore Ireland. 2 In January 2016 we closed a farm-in agreement with Equator an affiliate of Oando for Block 5 offshore Sao Tome and Principe whereby we acquired a 65 participating interest and operatorship in the block. Certain governmental approvals and processes are still required to be completed before this acquisition is effective. 3 In March 2015 we closed a farm-out agreement covering our three license areas in Mauritania with Chevron. As a component of the consideration for the farm-out Chevron was required to make an election by February 1 2016 to either farm-in to the Tortue-1 exploration well by paying a disproportionate share of the costs incurred in drilling of the well or alternatively elect to not farm-in to the Tortue-1 exploration well and pay a disproportionate share of the costs of a second contingent exploration or appraisal well in the contract areas subject to maximum expenditure caps. Chevron failed to make this mandatory election by the required date. Consequently pursuant to the terms of the farm-out agreement Chevron has withdrawn from our Mauritania blocks. Subsequently Chevron requested that we engage in discussions related to the possible reinstatement of Chevrons interests in our Mauritania blocks and such discussions are ongoing. However if no such agreement is reached in these discussions Chevrons 30 non-operated 13 participating interest will be reassigned to us subject to requisite government approvals and our participating interests in the Block C8 C12 and C13 petroleum contracts will be 90. 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. 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 andor 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 Discovery 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 3250 to 5800 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 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 Petroleum 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. 14 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 Ghanas Ministry of Petroleum. The GJFFDP was submitted to the government of Ghana in December 2015. 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 2016 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 flare such natural gas. Currently we have not been issued an amended permit from the Ghana Environmental Protection Agency Ghana EPA to flare natural gas produced from the Jubilee Field in substantial quantities. 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. 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. The Jubilee Unit partners identified a means of successfully mitigating the near wellbore productivity issues with ongoing acid stimulation treatments and we are in the process of correcting the mechanical issues experienced in the Jubilee Field. Oil production from the Jubilee Field averaged approximately 102500 barrels gross of oil per day during 2015. Following a February 2016 inspection of the turret area of the FPSO by SOFEC Inc. SOFEC the original turret manufacturer a potential issue was identified with the turret bearing. As a precautionary measure additional operating procedures to monitor the turret bearing and reduce the degree of rotation of the vessel are being put in place. SOFEC will now undertake further offshore examinations and Tullow will work with SOFEC to determine what further measures will be required. Oil production and gas export is continuing as normal. Deepwater Tano Block Discoveries The Tweneboa Enyenra and Ntomme fields are located in the western and central portions of the DT Block approximately 30 miles offshore Ghana in water depths of approximately 3300 to 5700 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. Fluid samples recovered from the fields indicate an oil gravity of approximately 31-35 degrees API and a natural gas condensate gravity of between 41 and 48 degrees API. The TEN development is 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 development includes the drilling and completion of up to 17 wells 11 of which have been drilled and are being 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 15 dependent on the International Tribunal for the Law of the Sea the ITLOS ruling expected by late 2017. The TEN development is on schedule and expected to deliver first oil in the third quarter of 2016 and is expected to increase towards the FPSO capacity of 80000 barrels gross per day as the phased development progresses. Future development of gas resources at the TEN development is anticipated following the commencement of oil production. The Wawa-1 exploration well intersected oil and gas-condensate in a Turonian-aged turbidite channel system. Pressure data shows that it is a separate accumulation from the TEN fields. Following additional appraisal and evaluation a decision regarding the commerciality of the Wawa discovery will be made by the DT Block partners. Should the discovery be declared commercial a PoD would be prepared for submission to Ghanas Ministry of Petroleum within six months of the declaration of commerciality. West Cape Three Points Block 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 4100 to 5900 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 3600 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 3200 to 5050 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 Petroleum 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 Petroleum 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 for the Mahogany and Teak discoveries to be developed contemporaneously with the Jubilee Field. Upon approval of the GJFFDP by the Ministry of Petroleum 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 Ghanas Ministry of Petroleum. Mauritania We are operator of three Offshore Blocks C8 C12 and C13 which are located on the western margin of the Mauritania Salt Basin. Our blocks both include and are adjacent to proven petroleum systems with our primary targets being Cretaceous sediments 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 basin floor channels and fans in trapping geometries outboard of the Salt Basin. Cretaceous source rocks penetrated by wells and typed to oils in the Mauritania Salt Basin are the same age as those which charge other oil and gas fields in the Late Cretaceous of West Africa. 16 Our acreage is located outboard of the Chinguetti Field and range in water depth from 4900 to 9800 feet. These blocks cover an aggregate area of approximately 6.6 million acres. We have obtained approximately 6000 line-kilometers of 2D seismic data and 10300 square kilometers of 3D seismic data covering portions of our blocks in Mauritania. Based on these 2D and 3D seismic programs we have identified numerous prospects in our blocks and we continue to integrate the results of our successful drilling program in Mauritania to further evaluate our reservoir model and delineate prospectivity. The following is a brief discussion of our discoveries to date in Block C8 offshore Mauritania. Block C8 Discoveries The Ahmeyim discovery formerly named Tortue is located in Block C8 offshore Mauritania. The discovery is a significant play-opening gas discovery for the outboard Cretaceous petroleum system. Based on analysis of drilling results and logging data the well 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 well was drilled to a total depth of 5107 meters. The Ahmeyim discovery extends across the Mauritania border into our Saint Louis Offshore Profond block offshore Senegal. In January 2016 we drilled the Guembeul-1 well in Senegal which confirmed the extension of the Ahmeyim discovery into Senegal. We are currently drilling the Ahmeyim-2 well as part of the appraisal program in Mauritania to further delineate the Ahmeyim discovery. The Marsouin discovery located in Block C8 offshore Mauritania is a significant play-extending gas discovery building on our successful exploration program in the outboard Cretaceous petroleum system offshore Mauritania. The Marsouin-1 well is located approximately 60 kilometers north of the Ahmeyim discovery and was drilled to a total depth of 5153 meters in nearly 2400 meters 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. An appraisal program is currently being planned to delineate the Marsouin discovery. Senegal We are the operator of the Cayar Offshore Profond and Saint Louis Offshore Profond Blocks offshore Senegal. The blocks are located in the Senegal River Mid-Cretaceous deep water system which is an extention of a working petroleum system in the Mauritania Salt Basin. We believe the area has multiple Lower Cretaceous source rocks with Albo-Cenomanian reservoir sands. We obtained approximately 7000 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. The results of these 3D seismic programs provided sufficient encouragement to begin acquiring additional seismic data in November 2015 in the western portions of both blocks to fully evaluate the prospectivity. This survey is expected to be completed in February 2016. We have identified numerous prospects in our blocks and we continue to integrate the results of our successful drilling program in Mauritania and Senegal to further evaluate our reservoir model and delineate prospectivity. The following is a brief discussion of our discovery in the Saint Louis Offshore Profond Block offshore Senegal. 17 Saint Louis Offshore Profond Discoveries The Guembeul-1 exploration well located in the northern part of the Saint Louis Offshore Profond license area in Senegal has made a significant gas discovery. The Guembeul-1 exploration well is located approximately five kilometers south of the Tortue-1 exploration well in Mauritania in approximately 2700 meters of water and was drilled to a total depth of 5245 meters. 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. Importantly the Guembeul-1 exploration well has demonstrated reservoir continuity as well as static pressure communication with the Tortue-1 exploration well in the Lower Cenomanian. 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 and French Guyana. The Guyana-Suriname Basin resulted from rock deformation caused 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 nearby discoveries offshore Guyana. 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 Zaedysus oil discovery. We believe that there are several independent play types of importance to 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 offshore West Africa in the Ghanaian Jubilee Field. 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. 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 are 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 3900 square kilometers over portions of Block 42 and Block 45 offshore Suriname. In August 2013 we completed a 2D seismic program of approximately 1400 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. We have compiled an initial inventory of prospects on the license areas in Suriname and will continue to refine and assess the prospectivity of these areas during 2016. 18 Morocco including Western Sahara Our petroleum contracts in Morocco include the Cap Boujdour Offshore Block which is within the Aaiun Basin and the Essaouira Offshore Block the Foum Assaka Offshore Block and the Tarhazoute Offshore Block which are within the Agadir Basin. We are the operator of these petroleum contracts. Aaiun Basin The Cap Boujdour Offshore Block is located within the Aaiun Basin along the Atlantic passive margin and covers a high-graded area within the original Boujdour Offshore Block which expired in February 2011. 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 Cap Boujdour Offshore 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 5100 square kilometers over the Cap Boujdour Offshore Block. The processing of this seismic data was completed in 2015. 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. Agadir Basin The Foum Assaka Offshore Essaouira Offshore and Tarhazoute Offshore Blocks are 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. The offshore Agadir Basin sediments are interpreted to comprise thick sequences of Lower to Upper Cretaceous age formations consisting of deep water channels and lobes. The interpreted prospects trapping styles are varied and include pre-salt ponded slope fans salt domes salt-cored anticlines and sub-salt structures. We completed interpretation of approximately 7800 square kilometers of new and reprocessed 3D seismic data in our Foum Assaka Offshore and Essaouira Offshore Blocks. During 2014 we conducted a 3D seismic data acquisition program of approximately 4300 square kilometers over the Tarhazoute Offshore and Essaouira Offshore Blocks. The processing of this seismic data was completed in late 2015. During 2014 we drilled the FA-1 exploration well in the Foum Assaka Offshore block. The well encountered oil and gas shows while drilling and in sidewall cores suggesting the presence of a working petroleum system however it failed to encounter commercial reservoirs and was plugged and abandoned. 19 We are currently assessing prospectivity on our Agadir Basin Blocks offshore Morocco and plan to continue processing and interpreting seismic information to assess the prospectivity of these license areas. Portugal In March 2015 we closed a farm-in agreement to acquire a non-operated interest in the Camarao Ameijoa Mexilhao and Ostra Blocks offshore Portugal. Offshore Atlantic Portugal has been identified as a potentially attractive Central Atlantic margin area with Jurassic source rocks and Lower Cretaceous reservoirs in combination traps. This overlooked and underexplored area has a number of wells showing good evidence for working charge from oil shows and drill stem tests in Late Jurassic and Early Cretaceous sandstones and limestones. These blocks cover an area of approximately 3.0 million acres in water depths ranging from approximately 200 to 3200 meters. During 2015 we conducted a 3D seismic survey of approximately 3200 square kilometers over the Camarao Block. The processing of this seismic data is expected to be completed in 2016. We are integrating the results from the 3D seismic survey into our geologic model to further assess prospectivity on the blocks. Sao Tome and Principe During the fourth quarter of 2015 and in January 2016 Kosmos acquired acreage in Blocks 5 6 and 11 offshore Sao Tome and Principe in the Gulf of Guinea. We are the operator of Block 11 Equator Exploration Limited Equator an affiliate of Oando Energy Resources is the operator of Block 5 and Galp Energia Sao Tome E Principe Unipessoal LDA Galp a wholly owned subsidiary of Petrogal S.A. is the operator of Block 6. These blocks cover an area of approximately 4.2 million acres in water depth ranging from 2250 to 3000 meters and provide an opportunity to pursue the core Cretaceous theme that was successful for us in Ghana. Block 5 is subject to certain governmental approvals and processes required to be completed before this acquisition is effective. Our blocks are adjacent to a proven and prolific petroleum system in Equatorial Guinea and northern Gabon comprising Early Cretaceous post-rift source rocks and Late Cretaceous reservoirs and provide an extension of this basin. 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 trapping 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 1250 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 seismic acquisition program which will facilitate a detailed geologic evaluation. Our Reserves The following table sets forth summary information about our estimated proved reserves as of December 31 2015. See Item 8. Financial Statements and Supplementary DataSupplemental Oil and Gas Data Unaudited for additional information. 20 All of our estimated proved reserves as of December 31 2015 and 2014 were associated with our Jubilee Field and the TEN development in Ghana. Our estimated proved reserves as of December 31 2013 were associated with our Jubilee Field in Ghana. Summary of Oil and Gas Reserves 2015 Net Proved Reserves1 2014 Net Proved Reserves1 2013 Net Proved Reserves1 Oil Oil Oil Condensate Natural Condensate Natural Condensate Natural NGLs Gas2 Total NGLs Gas2 Total NGLs Gas2 Total MMBbl Bcf MMBoe MMBbl Bcf MMBoe MMBbl Bcf MMBoe Reserves Category Proved developed . . . . 50 10 52 43 9 45 36 10 38 Proved undeveloped3 . 24 4 25 30 6 31 9 1 9 Total . . . . . . . . . . . . . 74 14 76 73 14 75 45 11 47 1 Our reserves associated with the Jubilee Field are based on the 54.445.6 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 development 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 from their initial disclosure as proved undeveloped reserves. As of December 31 2015 we recognized 25 MMBoe of proved undeveloped reserves related to the TEN development which is expected to begin first oil production in the third quarter of 2016. 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 development 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 incurred 80.6 million of capital expenditures related to the Jubilee Field Phase 1A and 1A addendum developments which consisted of drilling and completing two wells resulting in the conversion of approximately 3 MMBbl of net proved undeveloped reserves at December 31 2014 to proved developed reserves as of December 31 2015. 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 development. 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 incurred 82.8 million of capital expenditures related to the Jubilee Field Phase 1A development which resulted in the conversion of approximately 6 MMBbl of net proved undeveloped reserves at December 31 2013 to proved developed reserves as of December 31 2014. This conversion of proved undeveloped reserves to proved developed reserves was due to the drilling of the remaining Jubilee Field Phase 1A development wells. Changes for the year ended December 31 2013 include an increase of 11 MMBbl of proved reserves as a result of drilling and reservoir performance which is partially offset by 8 MMBbl of net production during 2013. During 2013 approximately 1 MMBbl of proved undeveloped reserves at December 31 2012 were converted to proved developed reserves as of December 31 2013. During the year ended December 31 2013 we incurred 116.6 million of capital expenditures related to the Jubilee Field Phase 1A development. 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 2015. All estimated future net revenues are attributable to projected production from the Jubilee Field and the TEN development in Ghana. If we are unable to export associated natural gas in 21 large quantities from the Jubilee Field and TEN development then production could be limited and the future net revenues discussed herein will be adversely affected. Estimated Future Net Revenues4 in millions except Bbl Estimated future net revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1546 Present value of estimated future net revenues PV-101 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1169 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 Measure2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1169 Benchmark and differential oil priceBbl3 . . . . . . . . . . . . . . . . . 53.72 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 2015 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 22 proved oil and gas reserves levied at a corporate parent level on future net revenues. Therefore the year-end 2015 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 54.13 for Dated Brent at December 31 2015. The price was adjusted for crude handling transportation fees quality and a regional price differential. These adjustments are estimated to include a 0.41 discount relative to Dated Brent for the Jubilee Field. The adjusted price utilized to derive the Jubilee Field PV-10 is 53.72. It was determined that no differential should be applied for the TEN development since oil production has not yet begun for those fields hence the price utilized to derive the TEN PV-10 is 54.13. 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 2015 and 2014 has been prepared by Ryder Scott Company L.P. RSC our independent reserve engineering firm and for the year ended December 31 2013 was prepared by Netherland Sewell Associates Inc. NSAI our independent reserve engineering firm for such years in accordance with the rules and regulations of the Securities and Exchange Commission SEC applicable to companies involved in oil and natural gas producing activities. These rules require SEC reporting companies to prepare their reserve estimates using reserve definitions and pricing based on 12-month historical unweighted first-day-of-the-month average prices rather than year-end prices. For a definition of proved reserves under the SEC rules see the Glossary and Selected Abbreviations. For more information regarding our independent reserve engineers please see Independent petroleum engineers below. Our estimated proved reserves and related future net revenues PV-10 and Standardized Measure were determined using index prices for oil without giving effect to derivative transactions and were held constant throughout the life of the assets. Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs including operating expenses and production taxes. Such calculations at December 31 2015 are based on costs in effect at December 31 2015 and the 12-month unweighted arithmetic average of the first-day-of-the-month price for the year ended December 31 2015 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 2015 and 2014 was established in 1937. Over the past 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 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 23 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 2015 and 2014 and related future net revenues and PV-10 at December 31 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 2015 reserve report was completed on January 21 2016 and a copy is included as an exhibit to this report. In connection with the preparation of the December 31 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 4-10a2 of Regulation S-X. RSC issued a report on our proved reserves at December 31 2015 based upon its evaluation. RSCs primary economic assumptions in estimates included an ability to sell Jubilee Field oil and TEN development oil at a price of 53.72 and 54.13 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. Netherland Sewell Associates Inc. NSAI was established in 1961. Over the past 50 years NSAI has provided services to the worldwide petroleum industry that include the issuance of reserves reports and audits acquisition and divestiture evaluations simulation studies exploration resources assessments equity determinations and management and advisory services. NSAI professionals subscribe to a code of professional conduct and NSAI is a Registered Engineering Firm in the State of Texas. For the year ended December 31 2013 we engaged NSAI 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 2013 and related future net revenues and PV-10 at December 31 2013 are taken from reports prepared by NSAI in accordance with petroleum engineering and evaluation principles which NSAI believes are commonly used in the industry and definitions and current regulations established by the SEC. In connection with the preparation of the December 31 2013 reserves report NSAI prepared its own estimates of our proved reserves. In the process of the reserves evaluation NSAI 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 NSAI which brought into question the validity or sufficiency of any such information or data NSAI 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. NSAI 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 24 and operating conditions consistent with the definition in Rule 4-10a2 of Regulation S-X. NSAI issued a report on our proved reserves at December 31 2013 based upon its evaluation. Technology used to establish proved reserves Under the SEC rules proved reserves are those quantities of oil and natural gas which by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions operating methods and government regulations. The term reasonable certainty implies a high degree of confidence that the quantities of oil andor 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 and NSAI 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 AM 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. 25 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. 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 2015 for the countries in which we currently operate. Developed Area Undeveloped Area Acres Acres Total Area Acres Gross Net1 Gross Net1 Gross Net1 In thousands Ghana Jubilee Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 7 27 7 West Cape Three Points2 . . . . . . . . . . . . . . . . . 101 31 101 31 Deepwater Tano2 . . . . . . . . . . . . . . . . . . . . . . . 138 24 138 24 Mauritania Block C83 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2962 2666 2962 2666 Block C123 . . . . . . . . . . . . . . . . . . . . . . . . . . . 1748 1573 1748 1573 Block C133 . . . . . . . . . . . . . . . . . . . . . . . . . . . 1940 1746 1940 1746 Morocco including Western Sahara Cap Boujdour . . . . . . . . . . . . . . . . . . . . . . . . . . 5503 3026 5503 3026 Essaouira . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2171 651 2171 651 Foum Assaka . . . . . . . . . . . . . . . . . . . . . . . . . . . 1200 359 1200 359 Tarhazoute . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1916 575 1916 575 Portugal Ameijoa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 733 227 733 227 Camarao . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 709 220 709 220 Mexilhao . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 791 245 791 245 Ostra . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 772 239 772 239 Sao Tome and Principe4 Block 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1241 558 1241 558 Block 11 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2209 1878 2209 1878 Senegal Cayar Offshore Profond . . . . . . . . . . . . . . . . . . . 1350 810 1350 810 Saint Louis Offshore Profond . . . . . . . . . . . . . . . 1650 990 1650 990 Suriname Block 42 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1526 763 1526 763 Block 45 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1267 633 1267 633 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 7 29927 17214 29954 17221 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 development 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. 26 3 In March 2015 we closed a farm-out agreement covering our three license areas in Mauritania with Chevron. As a component of the consideration for the farm-out Chevron was required to make an election by February 1 2016 to either farm-in to the Tortue-1 exploration well by paying a disproportionate share of the costs incurred in drilling of the well or alternatively elect to not farm-in to the Tortue-1 exploration well and pay a disproportionate share of the costs of a second contingent exploration or appraisal well in the contract areas subject to maximum expenditure caps. Chevron failed to make this mandatory election by the required date. Consequently pursuant to the terms of the farm-out agreement Chevron has withdrawn from our Mauritania blocks. Subsequently Chevron requested that we engage in discussions related to the possible reinstatement of Chevrons interests in our Mauritania blocks and such discussions are ongoing. However if no such agreement is reached in these discussions Chevrons 30 non-operated participating interest will be reassigned to us subject to requisite government approvals and our participating interests in the Block C8 C12 and C13 petroleum contracts will be 90. 4 In January 2016 we closed a farm-in agreement with Equator an affiliate of Oando for Block 5 offshore Sao Tome and Principe whereby we acquired a 65 participating interest and operatorship in the block. Certain governmental approvals and processes are still required to be completed before this acquisition is effective. Once the farm-in agreement becomes effective the gross and net undeveloped acres in Block 5 will be 703 thousand acres and 457 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 2015 Productive Productive Oil Wells Gas Wells Total Gross Net Gross Net Gross Net GhanaJubilee Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 6.24 26 6.24 GhanaTen1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 0.68 4 0.68 1 Of the four productive oil wells three gross or 0.51 net have multiple completions within the wellbore. 27 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 Wells1 Development Wells1 Productive2 Dry3 Total Productive2 Dry3 Total Total Total Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net 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 Year Ended December 31 2013 Ghana Jubilee Unit . . . . . . . . . . . . 2 0.48 2 0.48 2 0.48 Deepwater Tano . . . . . . . . . . 1 0.18 1 0.18 1 0.18 Cameroon Ndian River . . . . . . . . . . . . 1 1.00 1 1.00 1 1.00 Total . . . . . . . . . . . . . . . . . . 2 1.18 2 1.18 2 0.48 2 0.48 4 1.66 1 As of December 31 2015 12 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 13 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. 28 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 2015. 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0.17 11 1.87 Deepwater Tano . . . . . . . . . . . . . . . . . . . 1 0.18 Mauritania C81 . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 2.70 Senegal Saint Louis Offshore Profond . . . . . . . . . 1 0.60 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0.60 1 0.17 13 5.66 13 2.35 1 In March 2015 we closed a farm-out agreement covering our three license areas in Mauritania with Chevron. As a component of the consideration for the farm-out Chevron was required to make an election by February 1 2016 to either farm-in to the Tortue-1 exploration well by paying a disproportionate share of the costs incurred in drilling of the well or alternatively elect to not farm-in to the Tortue-1 exploration well and pay a disproportionate share of the costs of a second contingent exploration or appraisal well in the contract areas subject to maximum expenditure caps. Chevron failed to make this mandatory election by the required date. Consequently pursuant to the terms of the farm-out agreement Chevron has withdrawn from our Mauritania blocks. Subsequently Chevron requested that we engage in discussions related to the possible reinstatement of Chevrons interests in our Mauritania blocks and such discussions are ongoing. However if no such agreement is reached in these discussions Chevrons 30 non-operated participating interest will be reassigned to us subject to requisite government approvals and our participating interests in the Block C8 C12 and C13 petroleum contracts will be 90. 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 oilgas 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. 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 EO Group 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 29 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 Petroleum. 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 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 it would exercise its right 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 GNPCs 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. Effective January 14 2014 the Ministry of Petroleum and GNPC entered into a Memorandum of Understanding with Kosmos Energy on behalf of the WCTP petroleum contract Block partners wherein all parties have settled all matters pertaining to the Notices of Dispute for the Mahogany East PoD and the Cedrela Notice of Force Majeure and the Ministry of Petroleum has approved the Appraisal Programs for the Mahogany Teak and Akasa discoveries. As a result of the settlement a portion of the WCTP petroleum contract area which contained the Cedrela prospect has been relinquished. 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 Petroleum 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 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 PetroSAs 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 TEN 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 30 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 that it would exercise its right for the contractor group to pay its 5 DT Block share of the Jubilee Field development costs and be reimbursed for such costs plus interest out of a portion of GNPCs production revenues under the terms of the DT petroleum contract. Kosmos is required to pay a fixed royalty of 5 and an additional oil entitlement which escalates as the nominal project rate of return increases. These royalties are to be paid in-kind or at the election of the government of Ghana in cash. A corporate tax rate of 35 is applied to profits at a country level. In January 2013 at the end of the seven-year Exploration Period parts of the DT Block on which we had not declared a discovery area were not in a development and production area or were not in the Jubilee Unit were relinquished DT Relinquishment Area. Our existing Wawa discovery within the DT Block was not subject to relinquishment upon expiration of the Exploration Period of the DT petroleum contract as the DT petroleum contract remains in effect after the end of the Exploration Period while commerciality is being determined. Pursuant to our DT petroleum contract we and our DT Block partners have certain rights to negotiate a new petroleum contract with respect to the DT Relinquishment Area until such time as either a new petroleum contract is negotiated and entered into with us or we decline to match a bona fide third party offer GNPC may receive for the DT Relinquishment Area. The Ghanaian Petroleum Law and the WCTP and DT petroleum contracts form the basis of our exploration development and production operations on the WCTP and DT blocks. Pursuant to these petroleum contracts most significant decisions including PoDs and annual work programs for operations other than exploration and appraisal must be approved by a joint management committee consisting of representatives of certain block partners and GNPC. Certain decisions require unanimity. Jubilee Field Unitization The Jubilee Field discovered by the Mahogany-1 well in June 2007 covers an area within both the WCTP and DT Blocks. Consistent with the Ghanaian Petroleum Law the WCTP and DT petroleum contracts and as required by Ghanas Ministry of Petroleum it was agreed the Jubilee Field would be unitized for optimal resource recovery. A Pre Unit Agreement was agreed to between the contractors groups of the WCTP and DT Blocks in 2008 with a more comprehensive unit agreement the UUOA agreed to in 2009 which govern each partys respective rights and duties in the Jubilee Unit. Tullow is the Unit Operator while Kosmos was the Technical Operator for the initial development of the Jubilee Field. The Jubilee Unit holders interests are subject to redetermination in accordance with the terms of the UUOA. As a result of the initial redetermination process completed in October 2011 the tract participation was determined to be 54.4 for the WCTP Block and 45.6 for the DT Block. Our Unit Interest was increased from 23.5 to 24.1. The accounting for the Jubilee Unit is in accordance with the redetermined tract participation stated. Although the Jubilee Field is unitized Kosmos participating interests in each block outside the boundary of the Jubilee Unit remain the same. Kosmos remains operator of the WCTP Block outside the Jubilee Unit area. Morocco including Western Sahara Exploration Agreements Effective September 1 2011 we entered into the Cap Boujdour Offshore Petroleum Agreement as the operator. In October 2013 we entered into a farm-out agreement with Cairn Energy PLC Cairn covering the Cap Boujdour Offshore block offshore Western Sahara. In the first quarter of 2014 the Moroccan government issued a joint ministerial order approving the farm-out agreement. Under the terms of the farm-out agreement Cairn acquired a 20 non-operated interest in the exploration permits comprising the Cap Boujdour Offshore block. Cairn paid 150 of its share of costs of a 3D seismic survey capped at 25.0 million. The 3D seismic survey was completed in September 2014. Cairn also contributed 12.3 million towards our future costs and paid 1.5 million for their share 31 of costs incurred from the effective date of the contract through the closing date. Cairn funded Kosmos share of the CB-1 exploration well capped at 100.0 million. After giving effect to the farm-out our participating interest in the Cap Boujdour Offshore block is 55 and we remain the operator. The Moroccan national oil company Office National des Hydrocarbures et des Mines ONHYM has a carried 25 participating interest. We are required to pay a 10 royalty on oil produced in water depths of 200 meters or less the first 300000 tons produced are exempt from royalty and a 7 royalty on oil produced in water depths deeper than 200 meters the first 500000 tons produced are exempt from royalty. These royalties are to be paid in-kind or at the election of the government of Morocco in cash. A corporate tax rate of 30 is applied to profits at the license level following a 10-year tax holiday post first production if any. The exploration term of the Cap Boujdour Offshore Permits is eight years and includes an initial exploration period of one year and six months which was extended for one year to March 5 2014 followed by the first extension period of two years and the second extension period of three years and six months. We entered the first extension period on March 5 2014. By entering the first extension period we were obligated to drill one exploration well. To meet this obligation we drilled the CB-1 exploration well which was completed in March 2015. The well failed to encounter commercial reservoirs and was plugged and abandoned. In the event of commercial success we have the right to develop and produce oil andor gas for a period of 25 years from the grant of an exploitation authorization from the government which may be extended for an additional period of 10 years under certain circumstances. Effective July 1 2011 we entered into the Foum Assaka Offshore Petroleum Agreement as operator. In August 2013 final government approvals and processes were completed for the acquisition of an additional 18.8 participating interest in the Foum Assaka block in the Agadir Basin offshore Morocco from Pathfinder a wholly owned subsidiary of Fastnet one of our block partners and resulted in our participating interest being 56.2. In October 2013 we entered into a farm-out agreement with BP. In the first quarter of 2014 the Moroccan government issued joint ministerial orders approving the farm-out agreement. Under the terms of the agreement BP acquired a 26.3 non-operating interest in the Foum Assaka Offshore block. BP funded Kosmos share of the cost of the FA-1 exploration well in the block subject to a maximum spend of 120.0 million and paid its proportionate share of any well costs above the maximum spend. In the event a second exploration well is drilled BP will pay 150 of its share of costs subject to a maximum spend of 120.0 million. After giving effect to the farm-out our participating interest is 29.9 in the Foum Assaka Offshore block and we remain the operator. The Moroccan national oil company ONHYM has a 25 participating interest and is carried by the block partners proportionately during the exploration phase. We are required to pay a 10 royalty on oil produced in water depths of 200 meters or less the first 300000 tons produced are exempt from royalty and a 7 royalty on oil produced in water depths deeper than 200 meters the first 500000 tons produced are exempt from royalty. These royalties are to be paid in-kind or at the election of the government of Morocco in cash. A corporate tax rate of 30 is applied to profits at the license level following a 10-year tax holiday post first production. The term of the Foum Assaka Offshore Permits beginning on July 1 2011 is eight years and includes an initial exploration period of two years and six months followed by the first extension period of two years and six months and the second extension period of three years. We entered the first extension period effective January 1 2014. By entering the first extension period we were obligated to drill one exploration well. To meet this obligation we drilled the FA-1 exploration well in 2014. The well failed to encounter commercial reservoirs and was plugged and abandoned. In the event of commercial success we have the right to develop and produce oil andor gas for a period of 25 years from the grant of an exploitation authorization from the government which may be extended for an additional period of 10 years under certain circumstances. Effective April 2 2012 we entered into the Essaouria Offshore Petroleum Agreement as operator. In January 2013 we closed on an agreement to acquire an additional 37.5 participating interest in the Essaouira Offshore block from Canamens Energy Morocco SARL one of our block partners. 32 Governmental approvals and processes for this acquisition were finalized in November 2013 and resulted in our participating interest in the Essaouira Offshore block being 75. In October 2013 we entered into a farm-out agreement with BP. In the first quarter of 2014 the Moroccan government issued joint ministerial orders approving the farm-out agreement. Under the terms of the agreement BP acquired a non-operating interest in the Essaouria Offshore block. BP will fund Kosmos share of the cost of one exploration well in the block subject to a maximum spend of 120.0 million and pay its proportionate share of any well costs above the maximum spend. In the event a second exploration well is drilled BP will pay 150 of its share of costs subject to a maximum spend of 120.0 million. After giving effect to the farm-out our participating interest is 30 in the Essaouria Offshore block and we remain the operator. The Moroccan national oil company ONHYM has a 25 participating interest and is carried by the block partners proportionately during the exploration phase. We are required to pay a 10 royalty on oil produced in water depths of 200 meters or less the first 300000 tons produced are exempt from royalty and 7 royalty on oil produced in water depths deeper than 200 meters the first 500000 tons produced are exempt from royalty. These royalties are to be paid in-kind or at the election of the government of Morocco in cash. A corporate tax rate of 30 is applied to profits at the license level following a 10-year tax holiday post first production. The term of the Essaouria Offshore Permits beginning November 8 2011 is eight years and includes an initial exploration period of two years and six months followed by the first extension period of three years and the second extension period of two years and six months. We are currently in the first extension period of the exploration permit which ends in May 2017. The work program for the first extension period includes a drilling obligation. The extension of the exploration phases are subject to fulfillment of specific work obligations. In the event of commercial success we have the right to develop and produce oil andor gas for a period of 25 years from the grant of an exploitation authorization from the government which may be extended for an additional period of 10 years under certain circumstances. Effective December 6 2013 we entered into the Tarhazoute Offshore Petroleum Agreement as operator with a 75 participating interest. The Moroccan national oil company ONHYM has a 25 participating interest and is carried by the block partners proportionately during the exploration phase. In October 2013 we entered into a farm-out agreement with BP. In the first quarter of 2014 the Moroccan government issued joint ministerial orders approving the farm-out agreement. Under the terms of the agreement BP acquired a 45 non-operating interest in the Tarhazoute Offshore block. BP will fund Kosmos share of the cost of one exploration well in the block subject to a maximum spend of 120.0 million and pay its proportionate share of any well costs above the maximum spend. In the event a second exploration well is drilled BP will pay 150 of its share of costs subject to a maximum spend of 120.0 million. After giving effect to the farm-out our participating interest is 30 in the Tarhazoute Offshore block and we remain the operator. We are required to pay a 10 royalty on oil produced in water depths of 200 meters or less the first 300000 tons produced are exempt from royalty and 7 royalty on oil produced in water depths deeper than 200 meters the first 500000 tons produced are exempt from royalty. These royalties are to be paid in-kind or at the election of the government of Morocco in cash. A corporate tax rate of 30 is applied to profits at the license level following a 10-year tax holiday post first production. The exploration term of the Tarhazoute Offshore Permits beginning December 9 2013 is eight years and includes an initial exploration period of two years and six months followed by the first extension period of two years and six months and the second extension period of three years. In the event of commercial success we have the right to develop and produce oil andor gas for a period of 25 years from the grant of an exploitation authorization from the government which may be extended for an additional period of 10 years under certain circumstances. 33 Suriname Exploration Agreements On December 13 2011 we signed a petroleum contract covering Offshore Block 42 located offshore Suriname. We have a 50 participating interest in the block and are the operator. Staatsolie Maatschappij Suriname N.V. Staatsolie Surinames national oil company has the option to back into the contract with an interest of not more than 10 upon approval of a development plan. In November 2012 Kosmos closed an agreement with Chevron under which Kosmos assigned half of its interest in Block 42 offshore Suriname to Chevron. Each party now has a 50 participating interest in Block 42 and Kosmos remains the operator. The Block 42 petroleum contract provides for us to recover our share of expenses incurred cost recovery oil and our share of remaining oil profit oil. Cost recovery oil is apportioned to Kosmos from up to 80 of gross production prior to profit oil being split between the government of Suriname and the contractor. Profit oil is then apportioned based upon R-factor tranches where the R-factor is cumulative net revenues divided by cumulative net investment. A corporate tax rate of 36 is applied to profits. We are in the initial period of the exploration phase which has been extended and ends in September 2018. There are two renewal periods consisting of three years for the first renewal period and two years for the second renewal period. Each renewal period carries a one well drilling obligation. In the event of commercial success the duration of the contract will be 30 years from the effective date or 25 years from governmental approval of a plan of development whichever is longer. Block 42 comprises approximately 1.5 million acres approximately 6176 square kilometers. On December 13 2011 we signed a petroleum contract covering Offshore Block 45 located offshore Suriname. We have a 50 participating interest in the block and are the operator. Staatsolie will be carried through the exploration and appraisal phases and has the option to back into the petroleum contract with an interest of not more than 15 upon approval of a development plan. In November 2012 Kosmos closed an agreement with Chevron under which Kosmos assigned half of its interest in Block 45 offshore Suriname to Chevron. Each party now has a 50 participating interest in Block 45 and Kosmos remains the operator. The Block 45 petroleum contract provides for us to recover our share of expenses incurred cost recovery oil and our share of remaining oil profit oil. Cost recovery oil is apportioned to Kosmos from up to 80 of gross production prior to profit oil being split between the government of Suriname and the contractor. Profit oil is then apportioned based upon R-factor tranches where the R-factor is cumulative net revenues divided by cumulative net investment. A corporate tax rate of 36 is applied to profits. We are currently in the initial period of the exploration phase which has been extended and ends in September 2016. Following the initial period there are two renewal periods consisting of two years each. Each renewal period carries a one well drilling obligation. In the event of commercial success the duration of the contract will be 30 years from the effective date or 25 years from governmental approval of a plan of development whichever is longer. Mauritania Exploration Agreements Effective June 15 2012 we entered into three petroleum contracts covering offshore Mauritania blocks C8 C12 and C13 with the Islamic Republic of Mauritania. We have a 90 participating interest and are the operator. The Mauritanian national oil company SMHPM currently has a 10 carried participating interest during the exploration period only. Should a commercial discovery be made SMHPMs 10 carried interest is extinguished and SMHPM will have an option to acquire a participating interest between 10 and 14. SMHPM will pay its portion of development and production costs in a commercial development. Cost recovery oil is apportioned to Kosmos from up to 55 of total production prior to profit oil being split between the government of Mauritania and the contractor. Profit oil is then apportioned based upon R-factor tranches where the R-factor is cumulative net revenues divided by the cumulative investment. At the election of the government of Mauritania the government may receive its share of production in cash or in kind. A corporate tax rate of 27 is applied to profits at the license level. The terms of exploration periods of these Offshore 34 Blocks are all ten years and include an initial exploration period of four years followed by the first extension period of three years and the second extension period of three years. Kosmos is currently in the first exploration period of the blocks expiring in June 2016. The first extension period carries a seismic obligation and a one well drilling obligation and the second extension period carries an additional one well drilling obligation for each block. These obligations have been met for Block C8 and the seismic obligation has been met for Block C12 with work completed during the initial exploration period. In the event of commercial success we have the right to develop and produce oil for 25 years and gas for 30 years from the grant of an exploitation authorization from the government which may be extended for an additional period of 10 years under certain circumstances. In March 2015 we closed a farm-out agreement with Chevron covering the C8 C12 and C13 petroleum contracts offshore Mauritania. Under the terms of the farm-out agreement Chevron acquired a 30 non-operated working interest in each of the contract areas. As partial consideration for the farm-out Chevron paid a disproportionate share of the costs of one exploration well the Marsouin-1 exploration well as well as its proportionate share of certain previously incurred exploration costs. As a further component of the consideration for the farm-out Chevron was required to make an election by February 1 2016 to either farm-in to the Tortue-1 exploration well by paying a disproportionate share of the costs incurred in drilling of the well or alternatively elect to not farm-in to the Tortue-1 exploration well and pay a disproportionate share of the costs of a second contingent exploration or appraisal well in the contract areas subject to maximum expenditure caps. Chevron failed to make this mandatory election by the required date. Consequently pursuant to the terms of the farm-out agreement Chevron has withdrawn from our Mauritania blocks. Subsequently Chevron requested we engage in discussions related to the possible reinstatement of Chevrons interests in our Mauritania blocks and such discussions are ongoing. However if no such agreement is reached in these discussions Chevrons 30 non-operated participating interest will be reassigned to us subject to requisite government approvals and our participating interests in the Block C8 C12 and C13 petroleum contracts will be 90. Portugal Explorations Agreements In August 2014 we entered into a farm-in agreement with Repsol to acquire a non-operated interest in the Camarao Ameijoa Mexilhao and Ostra blocks in the Peniche Basin offshore Portugal. In March 2015 the Portuguese government issued the requisite approvals for the assignment to us. As part of the agreement we reimbursed a portion of Repsols previously incurred exploration costs as well as partially carried Repsols share of the costs of a 3D seismic program. After giving effect to the farm-in agreement our participating interest is 31 in each of the blocks. Repsol is the operator. The petroleum contracts for the four blocks were awarded in May of 2007 and each provides for an initial exploration phase of eight years and possible extensions. The initial exploration period has been extended through various amendments. The exploration period now ends in 2022 with drilling obligations in years eleven June 2017 to June 2018 thirteen June 2019 to June 2020 and fifteen June 2021 to June 2022. At the end of each contract year we may elect to fully relinquish the blocks without further obligation. Drilling a well on any block serves to fulfill the requirement for all four blocks. We are obligated to relinquish at least 50 of the total contract areas at the end of contract year twelve with at least 25 from each contract area and at least 50 of the total contract areas at the end of the second year of extension of the initial term. In September 2015 we completed a 3D seismic survey of approximately 3200 square kilometers over the Camarao block offshore Portugal. Senegal Exploration Agreements In August 2014 we entered into a farm-in agreement with Timis Corporation Limited Timis whereby we acquired a 60 participating interest and operatorship covering the Cayar Offshore 35 Profond and Saint Louis Offshore Profond Contract Areas offshore Senegal. In September 2014 the Senegal government issued the requisite approvals for the assignment to us. As part of the agreement we carried the full costs of a 3D seismic program which was completed in January 2015. Additionally we carried the full costs of the Guembeul-1 exploration well and will fund the Timis share of the costs of a second contingent exploration well in either contract area subject to a maximum gross cost per well of 120.0 million should Kosmos elect to drill such well. We also retain the option to increase our equity interest in each contract area to 65 in exchange for carrying the full cost of a third exploration or appraisal well in either contract area subject to a maximum gross cost of 120.0 million. In June 2015 we entered the first renewal of the exploration period for the Cayar Offshore Profond and Saint Louis Offshore Profond Contract Areas which lasts for three years. The exploration phase of each contract area may be extended to December 2020 at our election subject to our fulfilling specific work obligations including an exploration well in the current exploration period and an exploration well in the final period of two and one half years. In the event of commercial success we have the right to develop and produce oil andor gas for a period of 25 years from the grant of an exploitation authorization from the government which may be extended for at least one additional period of 10 years under certain circumstances. Sao Tome and Principe Exploration Agreements In October 2015 we closed a sale and purchase agreement with ERHC Energy EEZ LDA whereby we acquired an 85 participating interest and operatorship in Block 11 offshore Sao Tome and Principe. The Agencia Nacional do Petroleo ANP has a carried 15 participating interest. The production sharing contract was awarded in July 23 2014 and provides for an initial exploration period of eight years with possible extensions and includes a first phase exploration period of four years followed by the second phase of two years and the third phase of two years. The work program for the first phase includes a 2D seismic acquisition obligation and the next the exploration phases are subject to fulfillment of specific work obligations. In the event of commercial success we have the right to develop and produce oil andor gas for a period of 20 years from the approval of a field development program from ANP which may be extended for additional periods of five years until all hydrocarbons have been economically depleted. In November 2015 we closed a farm-in agreement with Galp to acquire a non-operated 45 participating interest in Block 6 offshore Sao Tome and Principe. The ANP has a carried 10 participating interest. The production sharing contract was awarded in October 2015 and provides for an initial exploration period of eight years with possible extensions and includes a first phase exploration period of four years followed by the second phase of two years and the third phase of two years. The work program for the first phase includes a 2D or 3D seismic acquisition obligation and the next exploration phases are subject to fulfillment of specific work obligations. In the event of commercial success we have the right to develop and produce oil andor gas for a period of 20 years from the approval of a field development program from ANP which may be extended for additional periods of five years until all hydrocarbons have been economically depleted. In January 2016 we closed a farm-in agreement with Equator an affiliate of Oando for Block 5 offshore Sao Tome and Principe whereby we acquired a 65 participating interest and operatorship in each block. Certain governmental approvals and processes are still required to be completed before these acquisitions are effective. Sales and Marketing As provided under the UUOA and the WCTP and DT petroleum contracts we are entitled to lift and sell our share of the Jubilee production in conjunction with the Jubilee Unit partners. We have entered into an agreement with an oil marketing agent to market our share of the Jubilee Field oil 36 and we approve the terms of each sale proposed by such agent. We do not anticipate entering into any long term sales agreements at this time. There are a variety of factors which affect the market for oil including the proximity and capacity of transportation facilities demand for oil the marketing of competitive fuels and the effects of government regulations on oil production and sales. Our revenue can be materially affected by current economic conditions and the price of oil. However based on the current demand for crude oil and the fact that alternative purchasers are available we believe that the loss of our marketing agent andor any of the purchasers identified by our marketing agent would not have a long-term material adverse effect on our financial position or results of operations. Competition The oil and gas industry is competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring and developing licenses. Many of these competitors have financial and technical resources and staff that are substantially larger than ours. As a result our competitors may be able to pay more for desirable oil and natural gas assets or to evaluate bid for and purchase a greater number of licenses than our financial or personnel resources will permit. Furthermore these companies may also be better able to withstand the financial pressures of lower commodity prices unsuccessful wells volatility in financial markets and generally adverse global and industry-wide economic conditions. These companies may also be better able to absorb the burdens resulting from changes in relevant laws and regulations which may adversely affect our competitive position. Historically we have also been affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs supplies services equipment and crews. Shortages of or increasing costs for experienced drilling crews and equipment and services may restrict our ability to drill wells and conduct our operations. The oil and gas industry as a whole experienced an extended decline in crude oil prices. Dated Brent crude the benchmark for our oil sales ranged from approximately 35-67 per barrel during 2015. Excluding the impact of hedges our realized price for 2015 was 52.32 per barrel. We believe lower prices will generally result in greater availability of assets and necessary equipment however the impacts on the industry from a competition perspective are not entirely known at this point. Title to Property Other than as specified in this annual report on Form 10-K we believe that we have satisfactory title to our oil and natural gas assets in accordance with standards generally accepted in the international oil and gas industry. Our licenses are subject to customary royalty and other interests liens under operating agreements and other burdens restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of or affect the carrying value of our interests. Environmental Matters General We are subject to various stringent and complex international foreign federal state and local environmental health and safety laws and regulations governing matters including the emission and discharge of pollutants into the ground air or water the generation storage handling use and transportation of regulated materials and the health and safety of our employees. These laws and regulations may among other things require the acquisition of various permits before operations commence 37 enjoin some or all of the operations or facilities deemed not in compliance with permits restrict the types quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling production and transportation activities limit cap tax or otherwise restrict emissions of GHG and other air pollutants or otherwise seek to address or minimize the effects of climate change limit or prohibit drilling activities in certain locations lying within protected or otherwise sensitive areas and require measures to mitigate or remediate pollution including pollution resulting from our operations. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. Compliance with these laws can be costly the regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. We cannot assure you that we have been or will be at all times in compliance with such laws or that environmental laws and regulations will not change or become more stringent in the future in a manner that could have a material adverse effect on our financial condition and results of operations. Moreover public interest in the protection of the environment continues to increase. Offshore drilling in some areas has been opposed by environmental groups and in other areas has been restricted. Our operations could be adversely affected to the extent laws or regulations are enacted or other governmental action is taken that prohibits or restricts offshore drilling or imposes environmental requirements that increase costs to the oil and gas industry in general such as more stringent or costly waste handling disposal or cleanup requirements or financial responsibility and assurance requirements. For example the Macondo spill in the Gulf of Mexico in 2010 has resulted and will likely continue to result in increased scrutiny regulation costs and liabilities in the United States. The governments of the countries in which we currently or in the future may operate may also impose increased regulation as a result of this or similar incidents which could materially delay restrict or prevent our operations in those countries. Capping and Containment We entered into an agreement with a third party service provider to supply subsea capping and containment equipment on a global basis. The equipment includes capping stacks debris removal subsea dispersant and auxiliary equipment. The equipment meets industry accepted standards and can be deployed by air cargo and other conventional means to suit multiple application scenarios. We also developed an emergency response plan and response organization to prepare and demonstrate our readiness to respond to a subsea well control incident. Oil Spill Response To complement our agreement discussed above for subsea capping and containment equipment we became a charter member of the Global Dispersant Stockpile. The new dispersant stockpile which is managed by Oil Spill Response Limited OSRL of Southampton United Kingdom UK an oil spill response contractor consists of 5000 cubic meters of dispersant strategically located at OSRL bases around the world. The total volume of the stockpile located at the OSRL bases is approximate to the amount used in the Macondo spill response. 38 Ghana Kosmos maintains an Oil Spill Contingency Plan OSCP for the coordination of responses to oil spills that might arise from our operations in Ghana. No exploration drilling is expected in the WCTP Block in 2016. Tullow our partner and the operator of the Jubilee Unit and TEN development however maintains an OSCP covering the Jubilee Field and DT Block. Both plans are based on the principle of Tiered Response to oil spills Guide to Tiered Response and Preparedness IPIECA Report Series Volume 14 2007. A Tier 1 spill is defined as a small-scale operational incident which can be addressed with resources that are immediately available to us. A Tier 2 spill is a larger incident which would need to be addressed with regionally based shared resources. A Tier 3 spill is a large incident which would require assistance from national or world-wide spill co-operatives. Under the OSCPs emergency response teams may be activated to respond to oil spill incidents. We maintain a tiered response system for the mobilization of resources depending on the severity of an incident. While a Tier 3 incident is not expected in Ghana in the case of a Tier 3 incident we would engage the services of OSRL. Tullow has access to OSRLs oil spill response services comprising technical expertise and assistance including access to response equipment and dispersant spraying systems. Tullow maintains lease agreements with OSRL for Tier 1 and Tier 2 packages of oil spill response equipment. Tier 1 equipment which is stored in ready to go trailers for effective mobilization and deployment includes booms and ancillaries recovery systems pumps and delivery systems oil storage containers personal protection equipment sorbent materials hand tools containers and first aid equipment. Tier 2 equipment consists of larger boom and oil recovery systems pump and delivery systems and auxiliary equipment such as generators and lighting sets and is also containerized and pre-packed in trailers and ready for mobilization. Tullow has additional response capability to handle an offshore Tier 1 response. Further our membership in the West and Central Africa Aerial Surveillance and Dispersant Spraying Service WACAF gives us access to aircraft for surveillance and spraying of dispersant which is administered by OSRL for a Tier 2 offshore response. The aircraft is based at the Kotoka International Airport in Accra Ghana with a contractual response time loaded with dispersant of six hours. Additional stockpiles of dispersant are maintained in Takoradi. Although the above arrangement is in place we can make no assurance that these resources will be available or respond in a timely manner as intended perform as designed or be able to fully contain or cap any oil spill blow-out or uncontrolled flow of hydrocarbons. Morocco including Western Sahara Mauritania and Senegal We have a specific Oil Spill Contingency Plan to support our drilling operations in countries where we operate. The plan calls for the addition of Tier 1 spill equipment to our shorebase in Agadir Morocco Nouakchott Mauritania and Dakar Senegal to respond to a harbor or shoreline incident in the area. In Senegal we also have access to the WACAF aircraft described above. We will have access to additional Tier 2 and Tier 3 equipment from the Southampton UK location. Per common industry practice under the agreements currently in place or agreements we may enter into during the future governing the terms of use of the drilling rigs contracted by us or our block partners the drilling rig contractors indemnify us and our block partners in respect of pollution and environmental damage arising out of operations which originate above the surface of the water and from a drilling rig contractors property including but not limited to their drilling rig and other related equipment. Furthermore pursuant to the terms of the operating agreements covering the blocks in which we or our block partners are currently drilling except in certain circumstances each block partner is responsible for the share of liabilities in proportion to its respective participating interest in the block incurred as a result of pollution and environmental damage containment and clean-up activities loss or damage to any well loss of oil or natural gas resulting from a blowout crater fire or 39 uncontrolled well loss of stored oil and natural gas and liabilities incurred in connection with plugging or bringing under control any well. We maintain or expect to maintain upon commencement of drilling operations insurance coverage typical of the industry in the areas we operate in these include property damage insurance loss of production insurance wreck removal insurance control of well insurance general liability including pollution liability to cover pollution from wells and other operations. We also participate in an insurance coverage program for the Jubilee FPSO. Our insurance is or will be carried in amounts typical for the industry and relative to our size and operations and in accordance with our contractual and regulatory obligations. Other Regulation of the Oil and Gas Industry Ghana The Ghanaian Petroleum Law currently governs the upstream Ghanaian oil and natural gas regulatory regime and sets out the policy and framework for industry participants. All petroleum found in its natural state within Ghana is deemed to be national property and is to be developed on behalf of the people of Ghana. GNPC is empowered to carry out exploration and development work either on its own or in association with local or foreign contractors. Companies who wish to gain rights to explore and produce in Ghana can only do so by entering into a petroleum agreement with Ghana and GNPC. The law requires for the terms of the petroleum agreement to be negotiated and agreed between GNPC and oil and gas companies. The Parliament of Ghana has final approval rights over the negotiated petroleum agreement. Ghanas Ministry of Petroleum represents the state in its executive capacity. The Petroleum Commission is the regulatory body for the upstream petroleum industry and the advisor to the Ministry of Petroleum. GNPC has rights to undertake petroleum operations in any acreage declared open by Ghanas Ministry of Petroleum. As well when petroleum operations are undertaken by GNPC under a petroleum contract GNPC has a carried interest in each petroleum agreement and following the declaration of any commercial discovery such carried interest is typically subject to increase by a certain agreed upon amount at the option of GNPC. Petroleum agreements are required to include certain domestic supply requirements including the sale to Ghana of oil for consumption in Ghana at international market prices. The Ghanaian Petroleum Law and our Ghanaian petroleum agreements contain provisions restricting the direct or indirect assignment or transfer of such petroleum agreements or interests thereunder without the prior written consent of GNPC and the Ministry of Petroleum. The Ghanaian Petroleum Law also imposes certain restrictions on the direct or indirect transfer by a contractor of shares of its incorporated company in Ghana to a third party without the prior written consent of Ghanas Minister of Petroleum. The Ghanaian Tax Law may impose certain taxes upon the direct or indirect transfer of interests in the petroleum agreements or interests thereunder. Ghanas Parliament is considering the enactment of a new Petroleum Exploration and Production Act and has enacted a Petroleum Revenue Management Act and the Petroleum Commission Act of 2011. The Petroleum Exploration and Production Act remains in a draft form with industry comments having been submitted. The new Petroleum Revenue Management Act of 2011 pertains primarily to the collection allocation and management by the government of Ghana of the petroleum revenue. The Petroleum Commission Act created the Petroleum Commission whose objective is to regulate and manage the use of petroleum resources and coordinate the policies thereto. The Petroleum Commission became effective in January 2012. Among the Petroleum Commissions functions are advising the Minister of Energy on matters such as appraisal plans field development plans recommending to the Minister national policies related to petroleum and storing and managing data. We understand the primary purpose of the Petroleum Commission is to fulfill the regulatory functions previously undertaken by GNPC. We currently believe that such laws will only have prospective application and as such will not modify the terms of or interests under the agreements governing our license interests in Ghana including the WCTP and DT petroleum contracts which include 40 stabilization clauses and the UUOA and will not impose additional restrictions on the direct or indirect transfer of our license interests including upon a change of control. The Petroleum Local Content and Local Participation in Petroleum Activities Regulations came into effect in February 2014. The Regulations mandate certain levels of local participation in service companies in-country manufacturing of goods and the provision of services and certain reporting requirements. Mauritania The main legislative act in the Islamic Republic of Mauritania relevant to petroleum exploration and production is Law No. 2010-033 dated July 20 2010 as amended the Hydrocarbon Laws. The regulatory authority in Mauritania is the Ministry of Petroleum Energy and Mines and the national oil company acting on its behalf is SMHPM. SMHPM was instituted by Decree No. 2005-106 of November 7 2005 and modified by Decree No. 2009-168 of May 3 2009 and Decree No. 2014-01 dated January 6 2014. Pursuant to the Hydrocarbon Laws Mauritania or SMHPM may undertake petroleum operations and may authorize other legal entities to undertake petroleum operations under petroleum contracts. The Ministry shall sign petroleum contracts on behalf of Mauritania. Assignments of interests in petroleum contracts also require the consent of the Ministry. The exploration period shall not be more than ten years subject to certain permitted extensions and the exploitation period shall not be more than 25 years. Petroleum contracts may provide that Mauritania has a carried interest of up to 10 during the exploration period. Petroleum contracts shall grant Mauritania the option to participate for a percentage not less than 10 nor more than 14 in the rights of the contractor during the exploitation period. Morocco including Western Sahara The two main legislative acts in Morocco relevant to petroleum exploration and production are i the Law 21-90 April 1 1992 as amended and completed by the Law 27-99 February 15 2000 and ii the Decree 2-93-786 November 3 1993 as amended and completed by decree 2-99-210 March 16 2000 together Moroccos Petroleum Laws. The regulatory authority in Morocco is the Ministry of Energy Mines Water and Environment and the national oil company acting on its behalf is ONHYM. ONHYM is a public establishment etablissement public with the legal personality and financial autonomy created pursuant to the Law 33-01 November 11 2003 which was further completed by the Decree 2-04-372 December 29 2004. Pursuant to the Law 21-90 the granting of an exploration permit is subject to the conclusion of a petroleum contract with the Moroccan State. Therefore companies who wish to gain rights to explore and produce in Morocco can only do so by entering into a petroleum contract with ONHYM acting on behalf of the State. It is further provided that the State of Morocco via ONHYM shall retain a participation in exploration permits or exploitation concessions which shall not be in excess of 25. More generally ONHYM is representing the State of Morocco for licensing exploration and exploitation matters within the limit of its prerogatives set out pursuant to the Law 33-01. Assignments of interests in exploration permits also require the consent of the administration pursuant to the Law 21-90. The Sahrawi Arab Democratic Republic the SADR has claimed sovereignty over the Western Sahara territory including the area offshore and has issued exploration licenses which conflict with those issued by Morocco including certain licenses which conflict with the Cap Boujdour Offshore block license issued to Kosmos. Other countries have formally recognized the SADR but the UN has not. It is uncertain when and how Western Saharas sovereignty issues will be resolved. Portugal The primary legislative acts in Portugal relevant to petroleum exploration and production are Decree-Law 10994 of April 16 1994governing petroleum exploration and production activities the 41 Petroleum Lawand Order 79094 of September 5 1994concerning the standard terms for concession contracts. The main regulatory authorities in Portugal are the Ministry of Environment Spatial Planning and Energy the General Directorate for Energy and Geology the DGEG and the National Entity for the Fuel Market ENMC. This latter entity is fairly recent and for that reason there is ambiguity between DGEGs and ENMCs powers and authority in respect of the upstream oil sector. DGEGs authority derives from Decree-Law 1302014 of August 29 2014which approves DGEGs organic statuteand ENMCs from Decree-Law 1652013 of December 16 2013which created ENMC and defined its responsibilities. The award of petroleum exploration and production rights is made through concession contracts. As a general rule the awarding procedure is a public tender. The assignment or transfer of interests in concession contracts as well as transfers of 50 or more of the concessionaires share capital requires the consent of the Minister. Sao Tome and Principe The Fundamental Law on Petroleum Operations Law No. 162009 governs petroleum operations in Sao Tome and Principe including the exploration development and production of hydrocarbons and the marketing and transportation thereof. There is also the Petroleum Taxation Law Law No. 152009. The ANP is established by Law No. 52004 and is responsible for the regulation contracting and supervision of hydrocarbon operations in Sao Tome and Principe. Senegal The Petroleum Code of Senegal Law No. 98-05 of January 8 1998 governs petroleum operations in Senegal including the exploration development and production of hydrocarbons and the marketing and transportation thereof as well as the rights of landowners. The implementing decree is No 98-810 of October 6 1998. The Ministry in charge of Energy grants or denies applications for petroleum agreements and such are granted by decree. Any amendment to the petroleum agreements requires the consent of the Minister. The Senegalese national oil company Societe des Petroles du Senegal PETROSEN as the regulatory body tasked with both upstream and downstream missions is under the supervision of the Ministry of Energy. PETROSEN prepares and negotiates all hydrocarbon licenses and contracts. PETROSEN has a carried interest during the exploration phase. The assignment of interests in petroleum contracts as well as amendments thereto require the consent of the Minister. Suriname The three sets of rules governing petroleum exploration and production in Suriname are i Staatsolies Concession Agreement Decree E8-B Official Gazette 1981 no. 59 ii the Mining Decree of 1986 Official Gazette 1986 no. 28 and iii the Petroleum Law 1990 Official Gazette 1991 no. 7 as amended in 2001. The Mining Decree granted concession rights for petroleum activities to state enterprises. Staatsolie the national oil company was founded in 1980 as a state enterprise and holds mining rights onshore and offshore in Suriname. The Suriname Petroleum Law granted state enterprises with petroleum concession rights the authority upon the approval of the Minister of Natural Resources to enter into petroleum contracts with EP companies. Therefore companies who wish to gain rights to explore and produce in Suriname can only do so by entering into a petroleum contract with Staatsolie subject to approval by the Minister of Natural Resources. Assignments of interests in petroleum contracts also require the consent of Staatsolie andor The Minister of Natural Resources. Certain Bermuda Law Considerations As a Bermuda exempted company we are subject to regulation in Bermuda. Among other things we must comply with the provisions of the Bermuda Companies Act regulating the payment of dividends and making of distributions from contributed surplus. 42 We have been designated by the Bermuda Monetary Authority as a non-resident for Bermuda exchange control purposes. This designation allows us to engage in transactions in currencies other than the Bermuda dollar and there are no restrictions on our ability to transfer funds other than funds denominated in Bermuda dollars in and out of Bermuda or to pay dividends to United States residents who are holders of our common shares. Under Bermuda law exempted companies are companies formed for the purpose of conducting business outside Bermuda from a principal place of business in Bermuda. As an exempted company we may not without a license or consent granted by the Minister of Finance participate in certain business transactions including transactions involving Bermuda landholding rights and the carrying on of business of any kind for which we are not licensed in Bermuda. Employees As of December 31 2015 we had approximately 260 employees. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are satisfactory. Corporate Information We were incorporated pursuant to the laws of Bermuda as Kosmos Energy Ltd. in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings was formed as an exempted company limited by guarantee pursuant to the laws of the Cayman Islands in March 2004. Pursuant to the terms of a corporate reorganization that was completed simultaneously with the closing of our initial public offering all of the interests in Kosmos Energy Holdings were exchanged for newly issued common shares of Kosmos Energy Ltd. and as a result Kosmos Energy Holdings became a wholly owned subsidiary of Kosmos Energy Ltd. We maintain a registered office in Bermuda at Clarendon House 2 Church Street Hamilton HM 11 Bermuda. The telephone number of our registered offices is 441 295-5950. Our U.S. subsidiary maintains its headquarters at 8176 Park Lane Suite 500 Dallas Texas 75231 and its telephone number is 214 445-9600. Available Information Kosmos is listed on the New York Stock Exchange and our common shares are traded under the symbol KOS. We file or furnish annual quarterly and current reports proxy statements and other information with the SEC. The public may read and copy any reports statements or other information at the SECs Public Reference Room at 100 F Street N.E. Washington D.C. 20549. The public may obtain information about the operation of the public reference room by calling the SEC at 1-800-SEC-0330. In addition the SEC maintains a website at httpwww.sec.gov that contains documents we file electronically with the SEC. The Company also maintains an internet website under the name www.kosmosenergy.com. The information on our website is not incorporated by reference into this annual report on Form 10-K and should not be considered a part of this annual report on Form 10-K. Our website is included as an inactive technical reference only. We make available free of charge on our website our annual report on Form 10-K quarterly reports on Form 10-Q current reports on Form 8-K and if applicable amendments to those reports filed or furnished pursuant to Section 13a of the Exchange Act as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. 43 Item 1A. Risk Factors You should consider and read carefully all of the risks and uncertainties described below together with all of the other information contained in this report including the consolidated financial statements and the related notes included in Item 8. Financial Statements and Supplementary Data. If any of the following risks actually occurs our business business prospects financial condition results of operations or cash flows could be materially adversely affected. The risks below are not the only ones we face. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us. Risks Relating to the Oil and Natural Gas Industry and Our Business We have limited proved reserves and areas that we decide to drill may not yield oil and natural gas in commercial quantities or quality or at all. We have limited proved reserves. A portion of our oil and natural gas assets consists of discoveries without approved PoDs and with limited well penetrations as well as identified yet unproven prospects based on available seismic and geological information that indicates the potential presence of hydrocarbons. However the areas we decide to drill may not yield oil or natural gas in commercial quantities or quality or at all. Many of our current discoveries and all of our prospects are in various stages of evaluation that will require substantial additional analysis and interpretation. Even when properly used and interpreted 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are in fact present in those structures. Accordingly we do not know if any of our discoveries or prospects will contain oil or natural gas in sufficient quantities or quality to recover drilling and completion costs or to be economically viable. Even if oil or natural gas is found on our discoveries or prospects in commercial quantities construction costs of gathering lines subsea infrastructure and floating production systems and transportation costs may prevent such discoveries or prospects from being economically viable and approval of PoDs by various regulatory authorities a necessary step in order to develop a commercial discovery may not be forthcoming. Additionally the analogies drawn by us using available data from other wells more fully explored discoveries or producing fields may not prove valid with respect to our drilling prospects. We may terminate our drilling program for a discovery or prospect if data information studies and previous reports indicate that the possible development of a discovery or prospect is not commercially viable and therefore does not merit further investment. If a significant number of our discoveries or prospects do not prove to be successful our business financial condition and results of operations will be materially adversely affected. The deepwater offshore Ghana an area in which we focus a substantial amount of our appraisal and development efforts has only recently been considered economically viable for hydrocarbon production due to the costs and difficulties involved in drilling for oil at such depths and the relatively recent discovery of commercial quantities of oil in the region. Likewise our deepwater offshore Morocco including Western Sahara Portugal Sao Tome and Principe Senegal Suriname and Mauritania licenses have not yet proved to be economically viable production areas. We have limited proved reserves and we may not be successful in developing additional commercially viable production from our other discoveries and prospects. We face substantial uncertainties in estimating the characteristics of our unappraised discoveries and our prospects. In this report we provide numerical and other measures of the characteristics of our discoveries and prospects. These measures may be incorrect as the accuracy of these measures is a function of available data geological interpretation and judgment. To date a limited number of our prospects have been drilled. Any analogies drawn by us from other wells discoveries or producing fields may not prove 44 to be accurate indicators of the success of developing proved reserves from our discoveries and prospects. Furthermore we have no way of evaluating the accuracy of the data from analog wells or prospects produced by other parties which we may use. It is possible that few or none of our wells to be drilled will find accumulations of hydrocarbons in commercial quality or quantity. Any significant variance between actual results and our assumptions could materially affect the quantities of hydrocarbons attributable to any particular prospect. Drilling wells is speculative often involving significant costs that may be more than we estimate and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs estimates or underlying assumptions will materially affect our business. Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of planning drilling completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services or unanticipated geologic conditions. Before a well is spud we incur significant geological and geophysical seismic costs which are incurred whether a well eventually produces commercial quantities of hydrocarbons or is drilled at all. Drilling may be unsuccessful for many reasons including geologic conditions weather cost overruns equipment shortages and mechanical difficulties. Exploratory wells bear a much greater risk of loss than development wells. In the past we have experienced unsuccessful drilling efforts having drilled dry holes. Furthermore the successful drilling of a well does not necessarily result in the commercially viable development of a field or be indicative of the potential for the development of a commercially viable field. A variety of factors including geologic and market-related can cause a field to become uneconomic or only marginally economic. A lack of drilling opportunities or projects that cease production may cause us to incur significant costs associated with an idle rig particularly if we cannot contract out rig slots to other parties. Many of our prospects that may be developed require significant additional exploration appraisal and development regulatory approval and commitments of resources prior to commercial development. In addition a successful discovery would require significant capital expenditure in order to develop and produce oil and natural gas even if we deemed such discovery to be commercially viable. See Our business plan requires substantial additional capital which we may be unable to raise on acceptable terms or at all in the future which may in turn limit our ability to develop our exploration appraisal development and production activities. In the areas in which we operate we face higher above-ground risks necessitating higher expected returns the requirement for increased capital expenditures due to a general lack of infrastructure and underdeveloped oil and gas industries and increased transportation expenses due to geographic remoteness which either require a single well to be exceptionally productive or the existence of multiple successful wells to allow for the development of a commercially viable field. See Our operations may be adversely affected by political and economic circumstances in the countries in which we operate. Furthermore if our actual drilling and development costs are significantly more than our estimated costs we may not be able to continue our business operations as proposed and could be forced to modify our plan of operation. Development drilling may not result in commercially productive quantities of oil and gas reserves. Our exploration success has provided us with major development projects on which we are moving forward and any future exploration discoveries will also require significant development efforts to bring to production. We must successfully execute our development projects including development drilling in order to generate future production and cash flow. However development drilling is not always successful and the profitability of development projects may change over time. 45 For example in new development projects available data may not allow us to completely know the extent of the reservoir or choose the best locations for drilling development wells. A development well we drill may be a dry hole or result in noncommercial quantities of hydrocarbons. All costs of development drilling and other development activities are capitalized even if the activities do not result in commercially productive quantities of hydrocarbon reserves. This puts a property at higher risk for future impairment if commodity prices decrease or operating or development costs increase. Our identified drilling locations are scheduled out over several years making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. Our management team has identified and scheduled drilling locations on our license areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors including the availability of equipment and capital approval by block partners and regulators seasonal conditions oil prices assessment of risks costs and drilling results. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this report as well as to some degree the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties we do not know if the drilling locations we have identified will be drilled within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. As such our actual drilling activities may be materially different from our current expectations which could adversely affect our results of operations and financial condition. A substantial or extended decline in both global and local oil and natural gas prices may adversely affect our business financial condition and results of operations. The prices that we will receive for our oil and natural gas will significantly affect our revenue profitability access to capital and future growth rate. Historically the oil and natural gas markets have been volatile and will likely continue to be volatile in the future. Oil prices have recently experienced significant and sustained declines and will likely continue to be volatile in the future. The prices that we will receive for our production and the levels of our production depend on numerous factors. These factors include but are not limited to the following changes in supply and demand for oil and natural gas the actions of the Organization of the Petroleum Exporting Countries speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts global economic conditions political and economic conditions including embargoes in oil-producing countries or affecting other oil-producing activities particularly in the Middle East Africa Russia and Central and South America the continued threat of terrorism and the impact of military and other action including U.S. military operations in the Middle East the level of global oil and natural gas exploration and production activity the level of global oil inventories and oil refining capacities weather conditions and natural or man-made disasters technological advances affecting energy consumption governmental regulations and taxation policies 46 proximity and capacity of transportation facilities the price and availability of competitors supplies of oil and natural gas and the price availability or mandated use of alternative fuels. Lower oil prices may not only reduce our revenues but also may limit the amount of oil that we can produce economically. A substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business financial condition results of operations liquidity or ability to finance planned capital expenditures. Under the terms of our various petroleum contracts we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas failure to drill these wells or declare any discoveries may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas which may include certain of our prospects. In order to protect our exploration and production rights in our license areas we must meet various drilling and declaration requirements. In general unless we make and declare discoveries within certain time periods specified in our various petroleum agreements and licenses our interests in the undeveloped parts of our license areas may lapse. Should the prospects we have identified in this annual report on Form 10-K under the license agreements currently in place yield discoveries we cannot assure you that we will not face delays in drilling these prospects or otherwise have to relinquish these prospects. The costs to maintain petroleum contracts over such areas may fluctuate and may increase significantly since the original term and we may not be able to renew or extend such petroleum contracts on commercially reasonable terms or at all. Our actual drilling activities may therefore materially differ from our current expectations which could adversely affect our business. Under these petroleum contracts we have work commitments to perform exploration and other related activities. Failure to do so may result in our loss of the licenses. As of December 31 2015 we have unfulfilled drilling obligations in our Essaouria and Senegal petroleum contracts. In certain other petroleum contracts we are in the initial exploration phase some of which have certain obligations that have yet to be fulfilled. Over the course of the next several years we may choose to enter into the next phase of those petroleum contracts which will likely include firm obligations to drill wells. Failure to execute our obligations may result in our loss of the licenses. The Exploration Period of each of the WCTP and DT petroleum contracts has expired. Pursuant to the terms of such petroleum contracts while we and our respective block partners have certain rights to negotiate new petroleum contracts with respect to the WCTP Relinquishment Area and DT Relinquishment Area we cannot assure you that we will determine to enter any such new petroleum contracts. For each of our petroleum contracts we cannot assure you that any renewals or extensions will be granted or whether any new agreements will be available on commercially reasonable terms or in some cases at all. For additional detail regarding the status of our operations with respect to our various petroleum contracts please see Item 1. BusinessOperations by Geographic Area. The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results. We may be liable for certain costs if third parties who contract with us are unable to meet their commitments under such agreements. We are currently exposed to credit risk through joint interest receivables from our block andor unit partners. If any of our partners in the blocks or unit in which we hold interests are unable to fund their share of the exploration and development expenses we may be liable for such costs. In the past certain of our WCTP and DT Block partners have not paid their share of block costs in the time frame required by the joint operating agreements for these blocks. This has resulted in such party being in default which in return requires Kosmos and its non-defaulting 47 block partners to pay their proportionate share of the defaulting partys costs during the default period. Should a default not be cured Kosmos could be required to pay its share of the defaulting partys costs going forward. In addition we contract with third parties to conduct drilling and related services on our development projects and exploration prospects. Such third parties may not perform the services they provide us on schedule or within budget. Furthermore the drilling equipment facilities and infrastructure owned and operated by the third parties we contract with is highly complex and subject to malfunction and breakdown. Any malfunctions or breakdowns may be outside our control and result in delays which could be substantial. Any delays in our drilling campaign caused by equipment facility or equipment malfunction or breakdown could materially increase our costs of drilling and cause an adverse effect on our business financial position and results of operations. Our principal exposure to credit risk will be through receivables resulting from the sale of our oil which we sell to an energy marketing company and to cover our commodity derivatives contracts. The inability or failure of our significant customers or counterparties to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Joint interest receivables arise from our block partners. The inability or failure of third parties we contract with to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We are unable to predict sudden changes in creditworthiness or ability to perform. Even if we do accurately predict sudden changes our ability to negate the risk may be limited and we could incur significant financial losses. The unit partners respective interests in the Jubilee Unit are subject to redetermination and our interests in such unit may decrease as a result. The interests in and development of the Jubilee Field are governed by the terms of the UUOA. The parties to the UUOA the collective interest holders in each of the WCTP and DT Blocks initially agreed that interests in the Jubilee Unit will be shared equally with each block deemed to contribute 50 of the area of such unit. The respective interests in the Jubilee Unit were therefore initially determined by the respective interests in such contributed block interests. Pursuant to the terms of the UUOA the percentage of such contributed interests is subject to a process of redetermination once sufficient development work has been completed in the unit. The initial redetermination process was completed on October 14 2011. As a result of the initial redetermination process the tract participation was determined to be 54.4 for the WCTP Block and 45.6 for the DT Block. Our Unit Interest participating interest in the Jubilee Unit was increased from 23.5 to 24.1. An additional redetermination could occur sometime if requested by a party that holds greater than a 10 interest in the Jubilee Unit. We cannot assure you that any redetermination pursuant to the terms of the UUOA will not negatively affect our interests in the Jubilee Unit or that such redetermination will be satisfactorily resolved. We are not and may not be in the future the operator on all of our license areas and do not and may not in the future hold all of the working interests in certain of our license areas. Therefore we will not be able to control the timing of exploration or development efforts associated costs or the rate of production of any non-operated and to an extent any non-wholly owned assets. As we carry out our exploration and development programs we have arrangements with respect to existing license areas and may have agreements with respect to future license areas that result in a greater proportion of our license areas being operated by others. Currently we are not the Unit Operator on the Jubilee Unit and do not hold operatorship in one of our two blocks offshore Ghana the DT Block. In addition the terms of the UUOA governing the unit partners interests in the Jubilee Unit require certain actions be approved by at least 80 of the unit voting interests and the 48 terms of our other current or future license or venture agreements may require at least the majority of working interests to approve certain actions. As a result we may have limited ability to exercise influence over the operations of the discoveries or prospects operated by our block or unit partners or which are not wholly owned by us as the case may be. Dependence on block or unit partners could prevent us from realizing our target returns for those discoveries or prospects. Further because we do not have majority ownership in all of our properties we may not be able to control the timing or the scope of exploration or development activities or the amount of capital expenditures and therefore may not be able to carry out one of our key business strategies of minimizing the cycle time between discovery and initial production. The success and timing of exploration and development activities operated by our block partners will depend on a number of factors that will be largely outside of our control including the timing and amount of capital expenditures the operators expertise and financial resources approval of other block partners in drilling wells the scheduling pre-design planning design and approvals of activities and processes selection of technology and the rate of production of reserves if any. This limited ability to exercise control over the operations on some of our license areas may cause a material adverse effect on our financial condition and results of operations. Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and natural gas reserves is technically complex. It requires interpretations of available technical data and many assumptions including those relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report. See Item 1. BusinessOur Reserves for information about our estimated oil and natural gas reserves and the present value of our net revenues at a 10 discount rate PV-10 and Standardized Measure of discounted future net revenues as defined herein as of December 31 2015. In order to prepare our estimates we must project production rates and the timing of development expenditures. We must also analyze available geological geophysical production and engineering data. The process also requires economic assumptions about matters such as oil and natural gas prices drilling and operating expenses capital expenditures taxes and availability of funds. Actual future production oil and natural gas prices revenues taxes development expenditures operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition we may adjust estimates of proved reserves to reflect production history results of exploration and development prevailing oil and natural gas prices and other factors many of which are beyond our control. 49 The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with the SEC requirements we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months adjusted for an anticipated market premium without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas assets will be affected by factors such as actual prices we receive for oil and natural gas actual cost of development and production expenditures derivative transactions the amount and timing of actual production and changes in governmental regulations or taxation. The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas assets will affect the timing and amount of actual future net revenues from proved reserves and thus their actual present value. In addition the 10 discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates included in this report. If oil prices decline by 1.00 per Bbl from prices used in calculating such estimates then the PV-10 and the Standardized Measure as of December 31 2015 would each decrease by approximately 51.5 million. Oil prices have recently experienced significant declines. See Item 1. BusinessOur Reserves. We are dependent on certain members of our management and technical team. Our performance and success largely depend on the ability expertise judgment and discretion of our management and the ability of our technical team to identify discover evaluate and develop reserves. The loss or departure of one or more members of our management and technical team could be detrimental to our future success. Additionally a significant amount of shares in Kosmos held by members of our management and technical team has vested. There can be no assurance that our management and technical team will remain in place. If any of these officers or other key personnel resigns or becomes unable to continue in their present roles and is not adequately replaced our results of operations and financial condition could be materially adversely affected. Our ability to manage our growth if any will require us to continue to train motivate and manage our employees and to attract motivate and retain additional qualified personnel. Competition for these types of personnel is intense and we may not be successful in attracting assimilating and retaining the personnel required to grow and operate our business profitably. Our business plan requires substantial additional capital which we may be unable to raise on acceptable terms or at all in the future which may in turn limit our ability to develop our exploration appraisal development and production activities. We expect our capital outlays and operating expenditures to be substantial as we expand our operations. Obtaining seismic data as well as exploration appraisal development and production activities entail considerable costs and we may need to raise substantial additional capital through 50 additional debt financing strategic alliances or future private or public equity offerings if our cash flows from operations or the timing of are not sufficient to cover such costs. Our future capital requirements will depend on many factors including the scope rate of progress and cost of our exploration appraisal development and production activities the success of our exploration appraisal development and production activities oil and natural gas prices our ability to locate and acquire hydrocarbon reserves our ability to produce oil or natural gas from those reserves the terms and timing of any drilling and other production-related arrangements that we may enter into the cost and timing of governmental approvals andor concessions and the effects of competition by larger companies operating in the oil and gas industry. We do not currently have any commitments for future external funding beyond the capacity of our commercial debt facility and revolving credit facility. Additional financing may not be available on favorable terms or at all. Even if we succeed in selling additional equity securities to raise funds at such time the ownership percentage of our existing shareholders would be diluted and new investors may demand rights preferences or privileges senior to those of existing shareholders. If we raise additional capital through debt financing the financing may involve covenants that restrict our business activities. If we choose to farm-out interests in our licenses we would dilute our ownership interest subject to the farm-out and any potential value resulting therefrom and may lose operating control or influence over such license areas. Assuming we are able to commence exploration appraisal development and production activities or successfully exploit our licenses during the exploratory term our interests in our licenses or the developmentproduction area of such licenses as they existed at that time as applicable could extend beyond the term set for the exploratory phase of the license to a fixed period or life of production depending on the jurisdiction. If we are unable to meet our well commitments andor declare commerciality of the prospective areas of our licenses during this time we may be subject to significant potential forfeiture of all or part of the relevant license interests. If we are not successful in raising additional capital we may be unable to continue our exploration and production activities or successfully exploit our license areas and we may lose the rights to develop these areas. See Under the terms of our various license agreements we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas which may include certain of our prospects. All of our proved reserves oil production and cash flows from operations are currently associated with our licenses offshore Ghana. Should any event occur which adversely affects such proved reserves oil production and cash flows from these licenses including without limitation any event resulting from the risks and uncertainties outlined in this Risk Factors section our business financial condition results of operations liquidity or ability to finance planned capital expenditures may be materially and adversely affected. 51 We may be required to take write-downs of the carrying values of our oil and natural gas assets as a result of decreases in oil and natural gas prices and such decreases could result in reduced availability under our corporate revolver and commercial debt facility. We capitalize costs to acquire find and develop our oil and natural gas properties under the successful efforts accounting method. Under such method we are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of appraisal and development plans production data oil and natural gas prices economics and other factors we may be required to write down the carrying value of our oil and natural gas assets. A write-down constitutes a non-cash charge to earnings. As a result of the recent drop in oil and natural gas prices we may incur future write-downs and charges should prices remain at low levels. In addition our borrowing base under the commercial debt facility is subject to periodic redeterminations. We could be forced to repay a portion of our borrowings under the commercial debt facility due to redeterminations of our borrowing base. Redeterminations may occur as a result of a variety of factors including oil and natural gas commodity price assumptions assumptions regarding future production from our oil and natural gas assets operating costs and tax burdens or assumptions concerning our future holdings of proved reserves. If we are forced to do so we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results. We may not be able to commercialize our interests in any natural gas produced from our license areas. The development of the market for natural gas in our license areas is in its early stages. Currently the infrastructure to transport and process natural gas on commercial terms is limited and the expenses associated with constructing such infrastructure ourselves may not be commercially viable given local prices currently paid for natural gas. Accordingly there may be limited or no value derived from any natural gas produced from our license areas. In Ghana we currently produce associated gas from the Jubilee Field. A gas pipeline from the Jubilee Field has been constructed to transport such natural gas for processing and sale. However we granted the first 200 Bcf of natural gas from the Jubilee Phase 1 to Ghana at no cost. Through December 31 2015 Ghana has received approximately 26 Bcf. Thus in Ghana even if additional infrastructure was in place for natural gas processing and sales it would still be quite some time before we would be able to commercialize our Ghana natural gas. As a result we do not have proved gas reserves associated with future natural gas sales from Jubilee Field in Ghana. Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production. Our ability to market our oil and natural gas production will depend substantially on the availability and capacity of processing facilities oil tankers and other infrastructure including FPSOs owned and operated by third parties. Our failure to obtain such facilities on acceptable terms could materially harm our business. We also rely on continuing access to drilling rigs suitable for the environment in which we operate. The delivery of drilling rigs may be delayed or cancelled and we may not be able to gain continued access to suitable rigs in the future. We may be required to shut in oil wells because of the absence of a market or because access to processing facilities may be limited or unavailable. If that were to occur then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market which could cause a material adverse effect on our financial condition and results of operations. In addition the shutting in of wells can lead 52 to mechanical problems upon bringing the production back on line potentially resulting in decreased production and increased remediation costs. Additionally the future exploitation and sale of associated and non-associated natural gas and liquids will be subject to timely commercial processing and marketing of these products which depends on the contracting financing building and operating of infrastructure by third parties. The Government of Ghana completed the construction and connection of a gas pipeline from the Jubilee Field to transport such natural gas to the mainland for processing and sale. However the uptime of the facility during 2016 and in future periods is not known. In the absence of the continuous removal of large quantities of natural gas from the Jubilee Field it is anticipated that we will need to flare such natural gas in order to maintain crude oil production. Currently we have not been issued an amended permit from the Ghana EPA to flare natural gas produced from the Jubilee Field in substantial quantities. If we are unable to resolve potential issues related to the continuous removal of associated natural gas in large quantities from the Jubilee Field our oil production will be negatively impacted. We are subject to numerous risks inherent to the exploration and production of oil and natural gas. Oil and natural gas exploration and production activities involve many risks that a combination of experience knowledge and interpretation may not be able to overcome. Our future will depend on the success of our exploration and production activities and on the development of an infrastructure that will allow us to take advantage of our discoveries. Additionally many of our license areas are located in deepwater which generally increases the capital and operating costs chances of delay planning time technical challenges and risks associated with oil and natural gas exploration and production activities. As a result our oil and natural gas exploration and production activities are subject to numerous risks including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase explore or develop discoveries prospects or licenses will depend in part on the evaluation of seismic data through geophysical and geological analyses production data and engineering studies the results of which are often inconclusive or subject to varying interpretations. Furthermore the marketability of expected oil and natural gas production from our discoveries and prospects will also be affected by numerous factors. These factors include but are not limited to market fluctuations of prices such as recent significant declines in oil prices proximity capacity and availability of drilling rigs and related equipment qualified personnel and support vessels processing facilities transportation vehicles and pipelines equipment availability access to markets and government regulations including without limitation regulations relating to prices taxes royalties allowable production domestic supply requirements importing and exporting of oil and natural gas the ability to flare or vent natural gas environmental protection and climate change. The effect of these factors individually or jointly may result in us not receiving an adequate return on invested capital. In the event that our currently undeveloped discoveries and prospects are developed and become operational they may not produce oil and natural gas in commercial quantities or at the costs anticipated and our projects may cease production in part or entirely in certain circumstances. Discoveries may become uneconomic as a result of an increase in operating costs to produce oil and natural gas. Our actual operating costs and rates of production may differ materially from our current estimates. Moreover it is possible that other developments such as increasingly strict environmental climate change health and safety laws and regulations and enforcement policies thereunder and claims for damages to property or persons resulting from our operations could result in substantial costs and liabilities delays an inability to complete the development of our discoveries or the abandonment of such discoveries which could cause a material adverse effect on our financial condition and results of operations. 53 We are subject to drilling and other operational and environmental risks and hazards. The oil and natural gas business involves a variety of operating risks including but not limited to fires blowouts spills cratering and explosions mechanical and equipment problems including unforeseen engineering complications. For example following a February 2016 inspection of the turret area of the Jubilee field FPSO by SOFEC the original turret manufacturer a potential issue was identified with the turret bearing. As a precautionary measure additional operating procedures to monitor the turret bearing and reduce the degree of rotation of the vessel are being put in place. SOFEC will now undertake further offshore examinations and Tullow operator of the Jubilee Unit will work with SOFEC to determine what further measures will be required uncontrolled flows or leaks of oil well fluids natural gas brine toxic gas or other pollutants or hazardous materials gas flaring operations marine hazards with respect to offshore operations formations with abnormal pressures pollution other environmental risks and geological problems and weather conditions and natural or man-made disasters. These risks are particularly acute in deepwater drilling and exploration. Any of these events could result in loss of human life significant damage to property environmental or natural resource damage impairment delay or cessation of our operations lower production rates adverse publicity substantial losses and civil or criminal liability. In accordance with customary industry practice we expect to maintain insurance against some but not all of these risks and losses. The occurrence of any of these events whether or not covered by insurance could have a material adverse effect on our financial position and results of operations. The development schedule of oil and natural gas projects including the availability and cost of drilling rigs equipment supplies personnel and oilfield services is subject to delays and cost overruns. Historically some oil and natural gas development projects have experienced delays and capital cost increases and overruns due to among other factors the unavailability or high cost of drilling rigs and other essential equipment supplies personnel and oilfield services as well as mechanical and technical issues. The cost to develop our projects has not been fixed and remains dependent upon a number of factors including the completion of detailed cost estimates and final engineering contracting and procurement costs. Our construction and operation schedules may not proceed as planned and may experience delays or cost overruns. Any delays may increase the costs of the projects requiring additional capital and such capital may not be available in a timely and cost-effective fashion. Our offshore and deepwater operations will involve special risks that could adversely affect our results of operations. Offshore operations are subject to a variety of operating risks specific to the marine environment such as capsizing sinking collisions and damage or loss to pipeline subsea or other facilities or from weather conditions. We could incur substantial expenses that could reduce or eliminate the funds available for exploration development or license acquisitions or result in loss of equipment and license interests. 54 Deepwater exploration generally involves greater operational and financial risks than exploration in shallower waters. Deepwater drilling generally requires more time and more advanced drilling technologies involving a higher risk of equipment failure and usually higher drilling costs. In addition there may be production risks of which we are currently unaware. If we participate in the development of new subsea infrastructure and use floating production systems to transport oil from producing wells these operations may require substantial time for installation or encounter mechanical difficulties and equipment failures that could result in loss of production significant liabilities cost overruns or delays. For example we have experienced mechanical issues in the Jubilee Field including failures of our water injection facilities on the FPSO and water and gas injection wells. This equipment downtime negatively impacted oil production during the year. Furthermore deepwater operations generally and operations in Africa and South America in particular lack the physical and oilfield service infrastructure present in other regions. As a result a significant amount of time may elapse between a deepwater discovery and the marketing of the associated oil and natural gas increasing both the financial and operational risks involved with these operations. Because of the lack of and the high cost of this infrastructure further discoveries we may make in Africa South America and Europe may never be economically producible. In addition in the event of a well control incident containment and potentially cleanup activities for offshore drilling are costly. The resulting regulatory costs or penalties and the results of third party lawsuits as well as associated legal and support expenses including costs to address negative publicity could well exceed the actual costs of containment and cleanup. As a result a well control incident could result in substantial liabilities for us and have a significant negative impact on our earnings cash flows liquidity financial position and stock price. We have had disagreements with the Republic of Ghana and the Ghana National Petroleum Corporation regarding certain of our rights and responsibilities under the WCTP and DT Petroleum Agreements. Multiple discovered fields and all of our proved reserves are located offshore Ghana. The WCTP petroleum contract the DT petroleum contract and the UUOA cover the two blocks and the Jubilee Unit that form the basis of our current operations in Ghana. Pursuant to these petroleum contracts most significant decisions including our plans for development and annual work programs must be approved by GNPC andor Ghanas Ministry of Petroleum. We have previously had disagreements with the Ministry of Petroleum and GNPC regarding certain of our rights and responsibilities under these petroleum contracts the Ghanaian Petroleum Law and the Internal Revenue Act 2000 Act 592 the Ghanaian Tax Law. These included disagreements over sharing information with prospective purchasers of our interests pledging our interests to finance our development activities potential liabilities arising from discharges of small quantities of drilling fluids into Ghanaian territorial waters the failure to approve the proposed sale of our Ghanaian assets assertions that could be read to give rise to taxes payable under the Ghanaian Tax Law failure to approve PoDs relating to certain discoveries offshore Ghana and the relinquishment of certain exploration areas on our licensed blocks offshore Ghana. These past disagreements have been resolved. The resolution of certain of these disagreements required us to pay agreed settlement costs to GNPC andor the government of Ghana. There can be no assurance that future disagreements will not arise with any host government andor national oil companies that may have a material adverse effect on our exploration or development activities our ability to operate our rights under our licenses and local laws or our rights to monetize our interests. 55 The geographic locations of our licenses in Africa South America and Europe subject us to an increased risk of loss of revenue or curtailment of production from factors specifically affecting those areas. Our current exploration licenses are located in Africa South America and Europe. Some or all of these licenses could be affected should any region experience any of the following factors among others severe weather natural or man-made disasters or acts of God delays or decreases in production the availability of equipment facilities personnel or services delays or decreases in the availability of capacity to transport gather or process production military conflicts or civil unrest andor international border disputes. For example oil and natural gas operations in our license areas in Africa and South America may be subject to higher political and security risks than those operations under the sovereignty of the United States. We plan to maintain insurance coverage for only a portion of the risks we face from doing business in these regions. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss. Further as many of our licenses are concentrated in the same geographic area a number of our licenses could experience the same conditions at the same time resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of licenses. Our operations may be adversely affected by political and economic circumstances in the countries in which we operate. Oil and natural gas exploration development and production activities are subject to political and economic uncertainties including but not limited to changes in energy policies or the personnel administering them changes in laws and policies governing operations of foreign-based companies expropriation of property cancellation or modification of contract rights revocation of consents or approvals obtaining various approvals from regulators foreign exchange restrictions currency fluctuations royalty increases and other risks arising out of foreign governmental sovereignty as well as risks of loss due to civil strife acts of war guerrilla activities terrorism acts of sabotage territorial disputes and insurrection. In addition we are subject both to uncertainties in the application of the tax laws in the countries in which we operate and to possible changes in such tax laws or the application thereof each of which could result in an increase in our tax liabilities. These risks may be higher in the developing countries in which we conduct a majority of our activities as it is the case in Ghana where the Ghanaian Revenue Authority the GRA has disputed certain tax deductions we have claimed in prior fiscal years Ghanaian tax returns as non-allowable under the terms of the Ghanaian Petroleum Income Tax Law as well as non-payment of certain transactional taxes. Our operations in these areas increase our exposure to risks of war local economic conditions political disruption civil disturbance expropriation piracy tribal conflicts and governmental policies that may disrupt our operations require us to incur greater costs for security restrict the movement of funds or limit repatriation of profits lead to U.S. government or international sanctions or 56 limit access to markets for periods of time. Some countries in the geographic areas where we operate have experienced political instability in the past or are currently experiencing instability. Disruptions may occur in the future and losses caused by these disruptions may occur that will not be covered by insurance. Consequently our exploration development and production activities may be substantially affected by factors which could have a material adverse effect on our results of operations and financial condition. Furthermore in the event of a dispute arising from non-U.S. operations we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the United States which could adversely affect the outcome of such dispute. Our operations may also be adversely affected by laws and policies of the jurisdictions including the jurisdictions where our oil and gas operating activities are located as well as the United States the United Kingdom Bermuda and the Cayman Islands and other jurisdictions in which we do business that affect foreign trade and taxation. Changes in any of these laws or policies or the implementation thereof could materially and adversely affect our financial position results of operations and cash flows. A portion of our asset portfolio is in Western Sahara and we could be adversely affected by the political economic and military conditions in that region. Our exploration licenses in this region conflict with exploration licenses issued by the Sahrawi Arab Democratic Republic SADR. Morocco claims the territory of Western Sahara where our Cap Boujdour Offshore block is geographically located as part of the Kingdom of Morocco and it has de facto administrative control of approximately 80 of Western Sahara. However Western Sahara is on the United Nations the UN list of Non-Self-Governing territories and the territorys sovereignty has been in dispute since 1975. The Polisario Front representing the SADR has a conflicting claim of sovereignty over Western Sahara. No countries have formally recognized Moroccos claim to Western Sahara although some countries implicitly support Moroccos position. Other countries have formally recognized the SADR but the UN has not. A UN-administered cease-fire has been in place since 1991 and while there have been intermittent UN-sponsored talks between Morocco and SADR represented by the Polisario Front the dispute remains stalemated. It is uncertain when and how Western Saharas sovereignty issues will be resolved. We own a 55 participating interest in the Cap Boujdour Offshore block located geographically offshore Western Sahara. Our license was granted by the government of Morocco however the SADR has issued its own offshore exploration licenses which in some areas conflict with our licenses. As a result of SADRs conflicting claim of rights to oil and natural gas licenses granted by Morocco and the SADRs claims that Moroccos exploitation of Western Saharas natural resources violates international law our interests could decrease in value or be lost. Any political instability terrorism changes in government or escalation in hostilities involving the SADR Morocco or neighboring states could adversely affect our operations and assets. In addition Morocco has recently experienced political and social disturbances that could affect its legal and administrative institutions. A change in U.S. foreign policy or the policies of other countries regarding Western Sahara could also adversely affect our operations and assets. We are not insured against political or terrorism risks because management deems the premium costs of such insurance to be currently prohibitively expensive relative to the limited coverage provided thereby. Furthermore various activist groups have mounted public relations campaigns to force companies to cease and divest operations in Western Sahara and we could come under similar public pressure. Some investors have refused to invest in companies with operations in Western Sahara and we could be subject to similar pressure. Any of these factors could have a negative impact on our stock price and a material adverse effect on our results of operations and financial condition. 57 A maritime boundary demarcation between Cote DIvoire and Ghana may affect a portion of our license areas offshore Ghana. The historical maritime boundary between Ghana and its western neighbor the Republic of Cote dIvoire forms the western boundary of the DT Block offshore Ghana. In early 2010 Cote dIvoire petitioned the United Nations to demarcate the Ivorian territorial maritime boundary with Ghana. In response to the petition Ghana established a Boundary Commission to undertake negotiations with Cote dIvoire in an effort to resolve their respective maritime boundary. The Ivorian Government then issued a map in September 2011 which reflected potential petroleum license areas that overlap with the DT Block. In September 2014 Ghana submitted the matter to arbitration under the United Nations Convention on the Law of the Sea and in December 2014 the two parties agreed to transfer the dispute to the ITLOS. On January 12 2015 the ITLOS formed a special chamber to address the maritime boundary dispute. On March 2 2015 Cote DIvoire applied to the ITLOS for a provisional measures order suspending activities in the disputed area in which the TEN development is located until the substantive case concerning the border dispute is adjudicated. More specifically the provisional measures application asked that Ghana be ordered to i suspend all ongoing exploration and exploitation operations in the disputed area ii refrain from granting any authorizations for new exploration and exploitation in the disputed area iii not use any data acquired in the disputed area in any way that would be detrimental to Cote dIvoire and iv take any necessary action for the preservation of the continental shelf its water and its underground in the disputed area. In late April 2015 the Special Chamber of ITLOS issued its order in response to Cote dIvoires provisional measures application. In its order ITLOS rejected Cote dIvoires requests that Ghana suspend its ongoing exploration and development operations in the disputed area but ordered Ghana to i take all necessary steps to ensure that no new drilling either by Ghana or any entity or person under its control takes place in the disputed area ii take all necessary steps to prevent information resulting from past ongoing or future exploration activities conducted by Ghana or with its authorization in the disputed area that is not already in the public domain from being used in any way whatsoever to the detriment of Cote dIvoire iii carry out strict and continuous monitoring of all activities undertaken by Ghana or with its authorization in the disputed area with a view to ensuring the prevention of serious harm to the marine environment iv take all necessary steps to prevent serious harm to the marine environment including the continental shelf and its superjacent waters in the disputed area and shall cooperate to that end and v pursue cooperation with Cote dIvoire and refrain from any unilateral action that might lead to aggravating the dispute. On June 11 2015 the Ghana Attorney General issued a letter to the DT Operator which confirmed the DT Block partners may i continue to drill wells that had been started but not completed prior to the ITLOS order and ii carry out completion work on wells that have already been drilled. The TEN development is currently estimated to be 80 percent complete. We expect the TEN development activities will continue as planned with first oil expected in the third quarter of 2016. With respect to the Wawa Discovery we plan to discuss with the Government of Ghana the effects of the ITLOS order on the proposed Wawa appraisal activities so that we can more clearly define our future plans and corresponding timeline. We do not know if the maritime boundary dispute will change our and our block partners rights to develop our discoveries within such areas. In the event that the ITLOS proceedings result in an unfavorable outcome for Ghana our operations within such areas could be materially impacted. The oil and gas industry including the acquisition of exploratory licenses is intensely competitive and many of our competitors possess and employ substantially greater resources than us. The international oil and gas industry is highly competitive in all aspects including the exploration for and the development of new license areas. We operate in a highly competitive environment for 58 acquiring exploratory licenses and hiring and retaining trained personnel. Many of our competitors possess and employ financial technical and personnel resources substantially greater than us which can be particularly important in the areas in which we operate. These companies may be better able to withstand the financial pressures of unsuccessful drilling efforts sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions and may be better able to absorb the burdens resulting from changes in relevant laws and regulations which could adversely affect our competitive position. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable licenses and to consummate transactions in a highly competitive environment. Also there is substantial competition for available capital for investment in the oil and gas industry. As a result of these and other factors we may not be able to compete successfully in an intensely competitive industry which could cause a material adverse effect on our results of operations and financial condition. Participants in the oil and gas industry are subject to numerous laws that can affect the cost manner or feasibility of doing business. Exploration and production activities in the oil and gas industry are subject to local laws and regulations. We may be required to make large expenditures to comply with governmental laws and regulations particularly in respect of the following matters licenses for drilling operations tax increases including retroactive claims unitization of oil accumulations local content requirements including the mandatory use of local partners and vendors and environmental requirements liabilities and obligations including those related to remediation investigation or permitting. Under these and other laws and regulations we could be liable for personal injuries property damage and other types of damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative civil and criminal penalties. Moreover these laws and regulations could change or their interpretations could change in ways that could substantially increase our costs. These risks may be higher in the developing countries in which we conduct a majority of our operations where there could be a lack of clarity or lack of consistency in the application of these laws and regulations. Any resulting liabilities penalties suspensions or terminations could have a material adverse effect on our financial condition and results of operations. For example Ghanas Parliament has enacted the Petroleum Revenue Management Act and is considering the enactment of a new Petroleum Exploration and Production Act. There can be no assurance that these laws will not seek to retroactively either on their face or as interpreted modify the terms of the agreements governing our license interests in Ghana including the WCTP and DT petroleum contracts and the UUOA require governmental approval for transactions that effect a direct or indirect change of control of our license interests or otherwise affect our current and future operations in Ghana. Any such changes may have a material adverse effect on our business. We also cannot assure you that government approval will not be needed for direct or indirect transfers of our petroleum agreements or interests thereunder based on existing legislation. See Item 1. Business Other Regulation of the Oil and Gas IndustryGhana. The SEC promulgated final rules under the Dodd-Frank Act requiring SEC reporting companies that engage in the commercial development of oil natural gas or minerals to disclose payments including taxes royalties fees and other amounts made by such companies or an entity controlled by 59 such companies to the United States or to any non-U.S. government for the purpose of commercial development of oil natural gas or minerals. The final rules do not contain an exception that would allow companies to exclude payments which may not be disclosed pursuant to foreign laws or confidentiality agreements. However in July 2013 the United States District Court for the District of Columbia vacated the final rules. The SEC has proposed revised rules implementing the applicable section of the Dodd-Frank Act however such rules have not been approved. There can be no assurance that we will be able to comply with these regulations once promulgated without creating disagreements with these partners or governments. Further such regulations may place us at a disadvantage to our non-U.S. competitors in doing business in the international oil and gas industry. Any of these consequences could have a material adverse effect on our financial condition and our results of operations. We are subject to numerous environmental health and safety regulations which may result in material liabilities and costs. We are subject to various international foreign federal state and local environmental health and safety laws and regulations governing among other things the emission and discharge of pollutants into the ground air or water the generation storage handling use transportation and disposal of regulated materials and the health and safety of our employees. We are required to obtain environmental permits from governmental authorities for our operations including drilling permits for our wells. We have not been or may not be at all times in complete compliance with these permits and laws and regulations to which we are subject and there is a risk such requirements could change in the future or become more stringent. If we violate or fail to comply with such requirements we could be fined or otherwise sanctioned by regulators including through the revocation of our permits or the suspension or termination of our operations. If we fail to obtain maintain or renew permits in a timely manner or at all due to opposition from partners community or environmental interest groups governmental delays or other reasons or if we face additional requirements imposed as a result of changes in or enactment of laws or regulations such failure to obtain maintain or renew permits or such changes in or enactment of laws or regulations could impede or affect our operations which could have a material adverse effect on our results of operations and financial condition. We as an interest owner or as the designated operator of certain of our past current and future discoveries and prospects could be held liable for some or all environmental health and safety costs and liabilities arising out of our actions and omissions as well as those of our block partners third-party contractors predecessors or other operators. To the extent we do not address these costs and liabilities or if we do not otherwise satisfy our obligations our operations could be suspended or terminated. We have contracted with and intend to continue to hire third parties to perform services related to our operations. There is a risk that we may contract with third parties with unsatisfactory environmental health or safety records or that our contractors may be unwilling or unable to cover any losses associated with their acts and omissions. Accordingly we could be held liable for all costs and liabilities arising out of their acts or omissions which could have a material adverse effect on our results of operations and financial condition. We are not fully insured against all risks and our insurance may not cover any or all environmental health or safety claims that might arise from our operations or at any of our license areas. If a significant accident or other event occurs and is not covered by insurance such accident or event could have a material adverse effect on our results of operations and financial condition. Releases of regulated substances may occur and can be significant. Under certain environmental laws we could be held responsible for all of the costs relating to any contamination at our current or former facilities and at any third party waste disposal sites used by us or on our behalf. In addition offshore oil and natural gas exploration and production involves various hazards including human exposure to regulated substances which include naturally occurring radioactive and other materials. As 60 such we could be held liable for any and all consequences arising out of human exposure to such substances or for other damage resulting from the release of any regulated or otherwise hazardous substances to the environment property or to natural resources or affecting endangered species. In addition we expect continued and increasing attention to climate change issues and emissions of GHGs including methane a primary component of natural gas and carbon dioxide a byproduct of oil and natural gas combustion. For example on December 12 2015 195 nations finalized the text of an international climate change accord in Paris France the Paris Agreement which nations may sign and officially enter into beginning in April 2016. The Paris Agreement calls for countries to set their own GHG emissions targets make these emissions targets more stringent over time and be transparent about the GHG emissions reporting and the measures each country will use to achieve its GHG targets. A long-term goal of the Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the pre-industrial era. The Paris Agreement is in effect a successor to the Kyoto Protocol an international treaty aimed at reducing emissions of GHGs to which various countries and regions including Ghana Mauritania Morocco including Western Sahara Portugal Sao Tome and Principe Senegal and Suriname are parties. While the Kyoto Protocol was set to expire in 2012 it has been extended by amendment until 2020. It cannot be determined at this time what effect the Paris Agreement and any related GHG emissions targets regulations or other requirements will have on our business results of operations and financial condition. The physical impacts of climate change in the areas in which our assets are located or in which we otherwise operate including through increased severity and frequency of storms floods and other weather events could adversely impact our operations or disrupt transportation or other process- related services provided by our third-party contractors. Environmental health and safety laws are complex change frequently and have tended to become increasingly stringent over time. Our costs of complying with current and future climate change environmental health and safety laws the actions or omissions of our block partners and third party contractors and our liabilities arising from releases of or exposure to regulated substances may adversely affect our results of operations and financial condition. See Item 1. Business Environmental Matters for more information. We face various risks associated with increased activism against oil and gas exploration and development activities. Opposition toward oil and gas drilling and development activity has been growing globally. Companies in the oil and gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety human rights environmental matters sustainability and business practices. Anti-development activists are working to among other things delay or cancel certain operations such as offshore drilling and development. Future activist efforts could result in the following delay or denial of drilling permits shortening of lease terms or reduction in lease size restrictions or delays on our ability to obtain additional seismic data restrictions on installation or operation of gathering or processing facilities restrictions on the use of certain operating practices legal challenges or lawsuits damaging publicity about us increased regulation 61 increased costs of doing business reduction in demand for our products and other adverse effects on our ability to develop our properties. Our need to incur costs associated with responding to these initiatives or complying with any resulting new legal or regulatory requirements resulting from these activities that are substantial and not adequately provided for could have a material adverse effect on our business financial condition and results of operations. We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act and other anti-corruption laws and any determination that we violated the U.S. Foreign Corrupt Practices Act or other such laws could have a material adverse effect on our business. We are subject to the U.S. Foreign Corrupt Practices Act FCPA and other laws that prohibit improper payments or offers of payments to foreign government officials and political parties for the purpose of obtaining or retaining business or otherwise securing an improper business advantage. In addition the United Kingdom has enacted the Bribery Act of 2011 and we may be subject to that legislation under certain circumstances. We do business and may do additional business in the future in countries and regions in which we may face directly or indirectly corrupt demands by officials. We face the risk of unauthorized payments or offers of payments by one of our employees contractors or consultants. Our existing safeguards and any future improvements may prove to be less than effective in preventing such unauthorized payments and our employees and consultants may engage in conduct for which we might be held responsible. Violations of the FCPA may result in severe criminal or civil sanctions and we may be subject to other liabilities which could negatively affect our business operating results and financial condition. In addition the U.S. government may seek to hold us liable for successor liability for FCPA violations committed by companies in which we invest in for example by way of acquiring equity interests in participating as a joint venture partner with acquiring the assets of or entering into certain commercial transactions with or that we acquire. Deterioration in the credit or equity markets could adversely affect us. We have exposure to different counterparties. For example we have entered or may enter into transactions with counterparties in the financial services industry including commercial banks investment banks insurance companies investment funds and other institutions. These transactions expose us to credit risk in the event of default by our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill existing obligations to us and their willingness to enter into future transactions with us. We may have exposure to these financial institutions through any derivative transactions we have or may enter into. Moreover to the extent that purchasers of our future production if any rely on access to the credit or equity markets to fund their operations there is a risk that those purchasers could default in their contractual obligations to us if such purchasers were unable to access the credit or equity markets for an extended period of time. We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations for which we may not have adequate insurance coverage. We intend to maintain insurance against certain risks in the operation of the business we plan to develop and in amounts in which we believe to be reasonable. Such insurance however may contain exclusions and limitations on coverage or may not be available at a reasonable cost or at all. For example we are not insured against political or terrorism risks. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our 62 business financial condition and results of operations. Further even in instances where we maintain adequate insurance coverage potential delays related to receipt of insurance proceeds as well as delays associated with the repair or rebuilding of damaged facilities could also materially and adversely affect our business financial condition and results of operations. We operate in a litigious environment. Some of the jurisdictions within which we operate have proven to be litigious environments. Oil and gas companies such as us can be involved in various legal proceedings such as title or contractual disputes in the ordinary course of business. From time to time we may become involved in various legal and regulatory proceedings arising in the normal course of business. We cannot predict the occurrence or outcome of these proceedings with certainty and if we are unsuccessful in these disputes and any loss exceeds our available insurance this could have a material adverse effect on our results of operations. Because we maintain a diversified portfolio of assets overseas the complexity and types of legal procedures with which we may become involved may vary and we could incur significant legal and support expenses in different jurisdictions. If we are not able to successfully defend ourselves there could be a delay or even halt in our exploration development or production activities or other business plans resulting in a reduction in reserves loss of production and reduced cash flows. Legal proceedings could result in a substantial liability andor negative publicity about us and adversely affect the price of our common shares. In addition legal proceedings distract management and other personnel from their primary responsibilities. We face various risks associated with global populism. Globally certain individuals and organizations are attempting to focus public attention on income distribution wealth distribution and corporate taxation levels and implement income and wealth redistribution policies. These efforts if they gain political traction could result in increased taxation on individuals andor corporations as well as potentially increased regulation on companies and financial institutions. Our need to incur costs associated with responding to these developments or complying with any resulting new legal or regulatory requirements as well as any potential increased tax expense could increase our costs of doing business reduce our financial flexibility and otherwise have a material adverse effect on our business financial condition and results of our operations. Slower global economic growth rates may materially adversely impact our operating results and financial position. The recovery from the global economic crisis of 2008 and resulting recession has been slow and uneven. Market volatility and reduced consumer demand have increased economic uncertainty and the current global economic growth rate is slower than what was experienced in the decade preceding the crisis. Many developed countries are constrained by long term structural government budget deficits and international financial markets and credit rating agencies are pressing for budgetary reform and discipline. This need for fiscal discipline is balanced by calls for continuing government stimulus and social spending as a result of the impacts of the global economic crisis. As major countries implement government fiscal reform such measures if they are undertaken too rapidly could further undermine economic recovery reducing demand and slowing growth. Impacts of the crisis have spread to China and other emerging markets which have fueled global economic development in recent years slowing their growth rates reducing demand and resulting in further drag on the global economy. Global economic growth drives demand for energy from all sources including hydrocarbons. A lower future economic growth rate is likely to result in decreased demand growth for our crude oil and natural gas production. A decrease in demand notwithstanding impacts from other factors could 63 potentially result in lower commodity prices which would reduce our cash flows from operations our profitability and our liquidity and financial position. Increased costs of capital could adversely affect our business. Our business and operating results can be harmed by factors such as the availability terms and cost of capital increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase limit our access to capital limit our ability to pursue acquisition opportunities reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results. Our derivative activities could result in financial losses or could reduce our income. To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas we have and may in the future enter into derivative arrangements for a portion of our oil and natural gas production including but not limited to puts collars and fixed-price swaps. In addition we currently and may in the future hold swaps designed to hedge our interest rate risk. We do not currently designate any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments. Derivative arrangements also expose us to the risk of financial loss in some circumstances including when production is less than the volume covered by the derivative instruments the counter-party to the derivative instrument defaults on its contract obligations or there is an increase in the differential between the underlying price and actual prices received in the derivative instrument. In addition these types of derivative arrangements may limit the benefit we could receive from increases in the prices for oil and natural gas or beneficial interest rate fluctuations and may expose us to cash margin requirements. Our commercial debt facility revolving credit facility and indenture governing the Senior Notes contain certain covenants that may inhibit our ability to make certain investments incur additional indebtedness and engage in certain other transactions which could adversely affect our ability to meet our future goals. Our commercial debt facility revolving credit facility and indenture governing the Senior Notes include certain covenants that among other things restrict our investments loans and advances and certain of our subsidiaries payment of dividends and other restricted payments our incurrence of additional indebtedness the granting of liens other than liens created pursuant to the commercial debt facility revolving credit facility or the indenture governing the Senior Notes and certain permitted liens mergers consolidations and sales of all or a substantial part of our business or licenses 64 the hedging forward sale or swap of our production of crude oil or natural gas or other commodities the sale of assets other than production sold in the ordinary course of business and in the case of the commercial debt facility and the revolving credit facility our capital expenditures that we can fund with the proceeds of our commercial debt facility and revolving credit facility. Our commercial debt facility revolving credit facility and letter of credit facility require us to maintain certain financial ratios such as debt service coverage ratios and cash flow coverage ratios. All of these restrictive covenants may limit our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our commercial debt facility revolving credit facility and indenture governing the Senior Notes may be impacted by changes in economic or business conditions our results of operations or events beyond our control. The breach of any of these covenants could result in a default under our commercial debt facility revolving credit facility and indenture governing the Senior Notes in which case depending on the actions taken by the lenders thereunder or their successors or assignees such lenders could elect to declare all amounts borrowed under our commercial debt facility revolving credit facility and indenture governing the Senior Notes together with accrued interest to be due and payable and in the case of the letter of credit facility the breach of any of the applicable covenants could result in a default in which case the cash collateral we are required to maintain under the letter of credit facility would increase from 75 to 100 of all outstanding letters of credit and if such additional cash is not posted the lenders thereunder could elect to declare all amounts outstanding thereunder together with accrued interest to be due and payable. If we were unable to repay such borrowings or interest our lenders successors or assignees could proceed against their collateral. If the indebtedness under our commercial debt facility revolving credit facility letter of credit facility and indenture governing the Senior Notes were to be accelerated our assets may not be sufficient to repay in full such indebtedness. In addition the limitations imposed by the commercial debt facility the revolving credit facility the letter of credit facility and the indenture governing the Senior Notes on our ability to incur additional debt and to take other actions might significantly impair our ability to obtain other financing. Provisions of our Senior Notes could discourage an acquisition of us by a third party. Certain provisions of the indenture governing the Senior Notes could make it more difficult or more expensive for a third party to acquire us or may even prevent a third party from acquiring us. For example upon the occurrence of a change of control triggering event as defined in the indenture governing the Senior Notes holders of the notes will have the right at their option to require us to repurchase all of their notes or any portion of the principal amount of such notes. By discouraging an acquisition of us by a third party these provisions could have the effect of depriving the holders of our common shares of an opportunity to sell their common shares at a premium over prevailing market prices. Our level of indebtedness may increase and thereby reduce our financial flexibility. At December 31 2015 we had 400.0 million outstanding and 1.1 billion of committed undrawn capacity under our commercial debt facility subject to borrowing base availability. As of December 31 2015 there were no borrowings outstanding under the Corporate Revolver and the undrawn availability was 400.0 million. As of December 31 2015 there were nine outstanding letters of credit totaling 15.3 million under the letter of credit facility agreement and 525.0 million principal amount of Senior Notes outstanding. We also currently have and may in the future incur significant off balance sheet obligations. In the future we may incur significant indebtedness in order to make investments or acquisitions or to explore appraise or develop our oil and natural gas assets. 65 Our level of indebtedness could affect our operations in several ways including the following a significant portion or all of our cash flows when generated could be used to service our indebtedness a high level of indebtedness could increase our vulnerability to general adverse economic and industry conditions the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds dispose of assets pay dividends and make certain investments a high level of indebtedness may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore may be able to take advantage of opportunities that our indebtedness could prevent us from pursuing our debt covenants may also affect our flexibility in planning for and reacting to changes in the economy and in our industry additional hedging instruments may be required as a result of our indebtedness a high level of indebtedness may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings and a high level of indebtedness may impair our ability to obtain additional financing in the future for working capital capital expenditures acquisitions general corporate or other purposes. A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions risks associated with exploring for and producing oil and natural gas oil and natural gas prices and financial business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our indebtedness and future working capital borrowings or equity financing may not be available to pay or refinance such indebtedness. Factors that will affect our ability to raise cash through an offering of our equity securities or a refinancing of our indebtedness include financial market conditions the value of our assets and our performance at the time we need capital. We are a holding company and our ability to make payments on our outstanding indebtedness including our Senior Notes and our commercial debt facility is dependent upon the receipt of funds from our subsidiaries by way of dividends fees interest loans or otherwise. We are a holding company and our subsidiaries own all of our assets and conduct all of our operations. Accordingly our ability to make payments of interest and principal on the Senior Notes and commercial debt facility will be dependent on the generation of cash flow by our subsidiaries and their ability to make such cash available to us by dividend debt repayment or otherwise. Unless they are guarantors our subsidiaries will not have any obligation to pay amounts due on the notes or to make funds available for that purpose. Our subsidiaries may not be able to or may not be permitted to make distributions to enable us to make payments in respect of the Senior Notes or the commercial debt facility. Each subsidiary is a distinct legal entity and under certain circumstances legal and contractual restrictions may limit our ability to obtain cash from our subsidiaries. The indenture governing the Senior Notes limits the ability of our subsidiaries to incur consensual encumbrances or restrictions on their ability to pay dividends or make other intercompany payments to us with significant qualifications and exceptions. In addition the terms of the commercial debt facility limit the ability of the obligors thereunder including our material operating subsidiaries that hold interests in our assets located offshore Ghana and their intermediate parent companies other than Kosmos Energy 66 Holdings to provide cash to us through dividend debt repayment or intercompany lending. In the event that we do not receive distributions from our subsidiaries we may be unable to make required principal and interest payments on our indebtedness including the Senior Notes and commercial debt facility. We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult. We periodically evaluate acquisitions of prospects and licenses reserves and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of these assets or businesses requires an assessment of several factors including recoverable reserves future oil and natural gas prices and their appropriate differentials development and operating costs and potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain. In connection with these assessments we perform a review of the subject assets that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the assets to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We may not be entitled to contractual indemnification for environmental liabilities and could acquire assets on an as is basis. Significant acquisitions and other strategic transactions may involve other risks including diversion of our managements attention to evaluating negotiating and integrating significant acquisitions and strategic transactions the challenge and cost of integrating acquired operations information management and other technology systems and business cultures with those of ours while carrying on our ongoing business difficulty associated with coordinating geographically separate organizations and the challenge of attracting and retaining personnel associated with acquired operations. The process of integrating operations could cause an interruption of or loss of momentum in the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process or if any significant business activities are interrupted as a result of the integration process our business could suffer. If we fail to realize the anticipated benefits of a significant acquisition our results of operations may be adversely affected. The success of a significant acquisition will depend in part on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful it may not be possible to realize the full benefits we may expect in estimated proved reserves production volume cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an 67 acquisition may be offset by operating losses relating to changes in commodity prices increased interest expense associated with debt incurred or assumed in connection with the transaction adverse changes in oil and gas industry conditions or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations or an increase in operating or other costs or other difficulties including the assumption of environmental or other liabilities in connection with the acquisition. If we fail to realize the benefits we anticipate from an acquisition our results of operations may be adversely affected. Our bye-laws contain a provision renouncing our interest and expectancy in certain corporate opportunities which could adversely affect our business or future prospects. Our bye-laws provide that to the fullest extent permitted by applicable law we renounce any right interest or expectancy in or in being offered an opportunity to participate in any business opportunity that may be from time to time be presented to certain of our affiliates or any of their respective officers directors agents shareholders members partners affiliates and subsidiaries other than us and our subsidiaries or business opportunities that such parties participate in or desire to participate in even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so and no such person shall be liable to us for breach of any statutory fiduciary contractual or other duty as a director or otherwise by reason of the fact that such person pursues or acquires any such business opportunity directs any such business opportunity to another person or fails to present any such business opportunity or information regarding any such business opportunity to us unless in the case of any such person who is our director such person fails to present any business opportunity that is expressly offered to such person solely in his or her capacity as our director. As a result our directors and certain of our affiliates and their respective affiliates may become aware from time to time of certain business opportunities such as acquisition opportunities and may direct such opportunities to other businesses in which they or their affiliates have invested in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further such businesses may choose to compete with us for these opportunities. As a result our renouncing of our interest and expectancy in any business opportunity that may be from time to time presented to our directors and certain of our affiliates and their respective affiliates could adversely impact our business or future prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. We receive certain beneficial tax treatment as a result of being an exempted company incorporated pursuant to the laws of Bermuda. Changes in that treatment could have a material adverse effect on our net income our cash flow and our financial condition. We are an exempted company incorporated pursuant to the laws of Bermuda and operate through subsidiaries in a number of countries throughout the world. Consequently we are subject to changes in tax laws treaties or regulations or the interpretation or enforcement thereof in the United States Bermuda Ghana and other jurisdictions in which we or any of our subsidiaries operate or are resident. In the past legislation has been introduced in the Congress of the United States that would reform the U.S. tax laws as they apply to certain non-U.S. entities and operations including legislation that would treat a foreign corporation as a U.S. corporation for U.S. federal income tax purposes if substantially all of its senior management is located in the United States. If this or similar legislation is passed that changes our U.S. tax position it could have a material adverse effect on our net income our cash flow and our financial condition. 68 We may become subject to taxes in Bermuda after March 31 2035 which may have a material adverse effect on our results of operations. The Bermuda Minister of Finance under the Exempted Undertakings Tax Protection Act 1966 of Bermuda as amended has given us an assurance that if any legislation is enacted in Bermuda that would impose tax computed on profits or income or computed on any capital asset gain or appreciation or any tax in the nature of estate duty or inheritance tax then the imposition of any such tax will not be applicable to us or any of our operations shares debentures or other obligations until March 31 2035 except insofar as such tax applies to persons who ordinarily reside in Bermuda or to any taxes payable by us in respect of real property owned or leased by us in Bermuda. The impact of Bermudas letter of commitment to the Organization for Economic Cooperation and Development to eliminate harmful tax practices is uncertain and could adversely affect our tax status in Bermuda. The Organization for Economic Cooperation and Development OECD has published reports and launched a global initiative among member and non-member countries on measures to limit harmful tax competition. These measures are largely directed at counteracting the effects of tax havens and preferential tax regimes in countries around the world. According to the OECD Bermuda is a jurisdiction that has substantially implemented the internationally agreed tax standard and as such is listed on the OECD white list. However we are not able to predict whether any changes will be made to this classification or whether such changes will subject us to additional taxes. The adoption of financial reform legislation by the United States Congress in 2010 and its implementing regulations could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price and other risks associated with our business. We use derivative instruments to manage our commodity price and interest rate risk. The United States Congress adopted comprehensive financial reform legislation in 2010 that establishes federal oversight and regulation of the over-the-counter derivatives market and entities such as ours that participate in that market. The Dodd-Frank Act was signed into law by the President on July 21 2010. The Commodity Futures Trading Commission CFTC which has jurisdiction over derivatives instruments that are swaps has implemented many but not all of these provisions through regulations the SEC which regulates security-based swaps has proposed but not finalized most of its implementing regulations. Of particular importance to us the CFTC has the authority to under certain findings establish position limits for certain futures options on futures and swap contracts. Certain bona fide hedging transactions or positions would be exempt from these position limits. The CFTC has proposed rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain energy metal and agricultural physical commodities subject to exceptions for certain bona fide hedging transactions. It is not possible at this time to predict when the CFTC will finalize these regulations therefore the impact of those provisions on us is uncertain at this time. The CFTC has designated certain interest-rate swaps and index credit default swaps for mandatory clearing and exchange trading. The CFTC has not yet proposed rules designating any other classes of swaps including physical commodity swaps for mandatory clearing. The application of the mandatory clearing and trade execution requirements to other market participants such as swap dealers may change the cost and availability of the swaps that the Company uses for hedging. Derivatives dealers that we transact with will need to comply with new margin and segregation requirements for uncleared swaps and security-based swaps. While it is expected that our uncleared derivatives transactions will not directly be subject to those margin requirements due to the increased 69 costs to dealers for transacting uncleared derivatives in general our costs for these transactions may increase. The Dodd-Frank Act and its implementing regulations may also require the counterparties to our derivative instruments to register with the CFTC and become subject to substantial regulation or even spin off some of their derivatives activities to a separate entity which may not be as creditworthy as the current counterparty. These requirements and others could significantly increase the cost of derivatives contracts including through requirements to clear swaps and to post collateral each of which could adversely affect our available liquidity materially alter the terms of derivatives contracts reduce the availability of derivatives to protect against risks we encounter reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations our results of operations may become more volatile and our cash flows may be less predictable which could adversely affect our ability to plan for and fund capital expenditures. Our revenues could also be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. The European Union and other non-U.S. jurisdictions are also implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions we or our transactions may become subject to such regulations. At this time the impact of such regulations is not clear. Any of these consequences could have a material adverse effect on our consolidated financial position results of operations or cash flows. We may become a passive foreign investment company for U.S. federal income tax purposes which could create adverse tax consequences for U.S. investors. U.S. investors that hold stock in a passive foreign investment company PFIC are subject to special rules that can create adverse U.S. federal income tax consequences including imputed interest charges and recharacterization of certain gains and distributions. Based on management estimates and projections of future revenue we do not believe that we will be a PFIC for the current taxable year and we do not expect to become one in the foreseeable future. Because PFIC status is a factual determination that is made annually and thus is subject to change there can be no assurance that we will not be a PFIC for any taxable year. A cyber incident could result in information theft data corruption operational disruption andor financial loss. The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration development and production activities. For example software programs are used to interpret seismic data manage drilling rigs conduct reservoir modeling and reserves estimation and to process and record financial and operating data. We depend on digital technology including information systems and related infrastructure as well as cloud application and services to process and record financial and operating data communicate with our employees and business partners analyze seismic and drilling information estimate quantities of oil and gas reserves and for many other activities related to our business. Our business partners including vendors service providers co-venturers purchasers of our production and financial institutions are also dependent on digital technology. The complexity of the technologies needed to explore for and develop oil and gas in increasingly difficult physical environments such as deepwater and global competition for oil and gas resources make certain information more attractive to thieves. As dependence on digital technologies has increased cyber incidents including deliberate attacks or unintentional events have also increased. A cyber-attack could include gaining unauthorized access 70 to digital systems for purposes of misappropriating assets or sensitive information corrupting data or causing operational disruption or result in denial-of-service on websites. For example in 2012 a wave of network attacks impacted Saudi Arabias oil industry and breached financial institutions in the U.S. Certain countries are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies. Our technologies systems networks and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release gathering monitoring misuse loss or destruction of proprietary and other information or other disruption of our business operations. In addition certain cyber incidents such as surveillance may remain undetected for an extended period. A cyber incident involving our information systems and related infrastructure or that of our business partners could disrupt our business plans and negatively impact our operations. Although to date we have not experienced any significant cyber-attacks there can be no assurance that we will not be the target of cyber-attacks in the future or suffer such losses related to any cyber- incident. As cyber threats continue to evolve we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Outbreaks of disease in the geographies in which we operate may adversely affect our business operations and financial condition. Many of our operations are currently and will likely remain in the near future in developing countries which are susceptible to outbreaks of disease and may lack the resources to effectively contain such an outbreak quickly. Such outbreaks may impact our ability to explore for oil and gas develop or produce our license areas by limiting access to qualified personnel increasing costs associated with ensuring the safety and health of our personnel restricting transportation of personnel equipment supplies and oil and gas production to and from our areas of operation and diverting the time attention and resources of government agencies which are necessary to conduct our operations. In addition any losses we experience as a result of such outbreaks of disease which impact sales or delay production may not be covered by our insurance policies. An epidemic of the Ebola virus disease occured in parts of West Africa in 2014 and continued through 2015. A substantial number of deaths were reported by the World Health Organization WHO in West Africa and the WHO declared it a global health emergency. It is impossible to predict the effect and potential spread of new outbreaks of the Ebola virus in West Africa and surrounding areas. Should the Ebola virus continue to spread or should another outbreak occur including to the countries in which we operate or not be satisfactorily contained our exploration development and production plans for our operations could be delayed or interrupted after commencement. Any changes to these operations could significantly increase costs of operations. Our operations require contractors and personnel to travel to and from Africa as well as the unhindered transportation of equipment and oil and gas production in the case of our producing fields. Such operations also rely on infrastructure contractors and personnel in Africa. If travel bans are implemented or extended to the countries in which we operate including Ghana or contractors or personnel refuse to travel there we could be adversely affected. If services are obtained costs associated with those services could be significantly higher than planned which could have a material adverse effect on our business results of operations and future cash flow. In addition should the Ebola epidemic spread to Ghana access to the FPSO operating at the Jubilee Field could be restricted andor terminated. The FPSO is potentially able to operate for a short period of time without access to the mainland but if restrictions extended for a longer period we and the operator of the Jubilee Field would likely be required to cease production and other operations until such restrictions were lifted. 71 Risks Relating to Our Common Shares Our share price may be volatile and purchasers of our common shares could incur substantial losses. Our share price may be volatile. The stock market in general has experienced extreme volatility that has often been unrelated to the operating performance of particular companies. The market price for our common shares may be influenced by many factors including but not limited to the price of oil and natural gas the success of our exploration and development operations and the marketing of any oil and natural gas we produce operational incidents regulatory developments in Bermuda the United States and foreign countries where we operate the recruitment or departure of key personnel quarterly or annual variations in our financial results or those of companies that are perceived to be similar to us market conditions in the industries in which we compete and issuance of new or changed securities analysts reports or recommendations the failure of securities analysts to cover our common shares or changes in financial estimates by analysts the inability to meet the financial estimates of analysts who follow our common shares the issuance or sale of any additional securities of ours investor perception of our company and of the industry in which we compete and general economic political and market conditions. A substantial portion of our total issued and outstanding common shares may be sold into the market at any time. This could cause the market price of our common shares to drop significantly even if our business is doing well. All of the shares sold in our initial public offering are freely tradable without restrictions or further registration under the federal securities laws unless purchased by our affiliates as that term is defined in Rule 144 under the Securities Act of 1933 as amended the Securities Act. Substantially all of the remaining common shares are restricted securities as defined in Rule 144 under the Securities Act unless they have been sold pursuant to Rule 144 to date. Restricted securities may be sold in the U.S. public market only if registered or if they qualify for an exemption from registration including by reason of Rule 144 or Rule 701 under the Securities Act. All of our restricted shares are eligible for sale in the public market subject in certain circumstances to the volume manner of sale limitations with respect to shares held by our affiliates and other limitations under Rule 144. Additionally we have registered all our common shares that we may issue under our employee benefit plans. These shares can be freely sold in the public market upon issuance unless pursuant to their terms these share awards have transfer restrictions attached to them. Sales of a substantial number of our common shares or the perception in the market that the holders of a large number of shares intend to sell common shares could reduce the market price of our common shares. 72 The concentration of our share capital ownership among our largest shareholders and their affiliates will limit your ability to influence corporate matters. Our two largest shareholders collectively own approximately 55 of our issued and outstanding common shares. Consequently these shareholders have significant influence over all matters that require approval by our shareholders including the election of directors and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters and as a result actions may be taken that you may not view as beneficial. Holders of our common shares will be diluted if additional shares are issued. We may issue additional common shares preferred shares warrants rights units and debt securities for general corporate purposes including but not limited to repayment or refinancing of borrowings working capital capital expenditures investments and acquisitions. We continue to actively seek to expand our business through complementary or strategic acquisitions and we may issue additional common shares in connection with those acquisitions. We also issue restricted shares to our executive officers employees and independent directors as part of their compensation. If we issue additional common shares in the future it may have a dilutive effect on our current outstanding shareholders. We are a controlled company within the meaning of the NYSE rules and as a result qualify for and rely on exemptions from certain corporate governance requirements. Funds affiliated with Warburg Pincus LLC and The Blackstone Group L.P. respectively continue to control a majority of the voting power of our issued and outstanding common shares and we are a controlled company within the meaning of the NYSE corporate governance standards. Under the NYSE rules a company of which more than 50 of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE corporate governance requirements including the requirements that a majority of the board of directors consist of independent directors the nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the committees purpose and responsibilities the compensation committee be composed entirely of independent directors with a written charter addressing the committees purpose and responsibilities and there be an annual self-assessment evaluation of the nominating and corporate governance and compensation committees. We have elected to be treated as a controlled company and utilize these exemptions including the exemption for a board of directors composed of a majority of independent directors. In addition although we have adopted charters for our audit nominating and corporate governance and compensation committees and conduct annual self-assessments for these committees currently only our audit committee is composed entirely of independent directors. Accordingly you may not have the same protections afforded to shareholders of companies that are subject to all of the NYSE corporate governance requirements. We do not intend to pay dividends on our common shares and consequently your only opportunity to achieve a return on your investment is if the price of our shares appreciates. We do not plan to declare dividends on shares of our common shares in the foreseeable future. Additionally certain of our subsidiaries are currently restricted in their ability to pay dividends to us pursuant to the terms of our commercial debt facility unless they meet certain conditions financial and 73 otherwise. Consequently investors must rely on sales of their common shares after price appreciation which may never occur as the only way to realize a return on their investment. We are a Bermuda company and a significant portion of our assets are located outside the United States. As a result it may be difficult for shareholders to enforce civil liability provisions of the federal or state securities laws of the United States. We are a Bermuda exempted company. As a result the rights of holders of our common shares will be governed by Bermuda law and our memorandum of association and bye-laws. The rights of shareholders under Bermuda law may differ from the rights of shareholders of companies incorporated in other jurisdictions. Some of our directors are not residents of the United States and a substantial portion of our assets are located outside the United States. As a result it may be difficult for investors to effect service of process on that person in the United States or to enforce in the United States judgments obtained in U.S. courts against us or that person based on the civil liability provisions of the U.S. securities laws. It is doubtful whether courts in Bermuda will enforce judgments obtained in other jurisdictions including the United States against us or our directors or officers under the securities laws of those jurisdictions or entertain actions in Bermuda against us or our directors or officers under the securities laws of other jurisdictions. Bermuda law differs from the laws in effect in the United States and might afford less protection to shareholders. Our shareholders could have more difficulty protecting their interests than would shareholders of a corporation incorporated in a jurisdiction of the United States. As a Bermuda company we are governed by the Companies Act 1981 of Bermuda the Bermuda Companies Act. The Bermuda Companies Act differs in some material respects from laws generally applicable to U.S. corporations and shareholders including the provisions relating to interested directors mergers and acquisitions takeovers shareholder lawsuits and indemnification of directors. Set forth below is a summary of these provisions as well as modifications adopted pursuant to our bye-laws which differ in certain respects from provisions of Delaware corporate law. Because the following statements are summaries they do not discuss all aspects of Bermuda law that may be relevant to us and our shareholders. Interested Directors. Under Bermuda law and our bye-laws as long as a director discloses a direct or indirect interest in any contract or arrangement with us as required by law such director is entitled to vote in respect of any such contract or arrangement in which he or she is interested unless disqualified from doing so by the chairman of the meeting and such a contract or arrangement will not be voidable solely as a result of the interested directors participation in its approval. In addition the director will not be liable to us for any profit realized from the transaction. In contrast under Delaware law such a contract or arrangement is voidable unless it is approved by a majority of disinterested directors or by a vote of shareholders in each case if the material facts as to the interested directors relationship or interests are disclosed or are known to the disinterested directors or shareholders or such contract or arrangement is fair to the corporation as of the time it is approved or ratified. Additionally such interested director could be held liable for a transaction in which such director derived an improper personal benefit. Mergers and Similar Arrangements. The amalgamation of a Bermuda company with another company or corporation other than certain affiliated companies requires the amalgamation agreement to be approved by the companys board of directors and by its shareholders. Unless the companys bye-laws provide otherwise the approval of 75 of the shareholders voting at such meeting is required to approve the amalgamation agreement and the quorum for such meeting must be two persons holding or representing more than one-third of the issued shares of the company. Our bye-laws provide that an amalgamation other than with a wholly owned subsidiary per the Bermuda Companies Act that has been approved by the board must only be approved by shareholders owning a majority of the 74 issued and outstanding shares entitled to vote. Under Bermuda law in the event of an amalgamation of a Bermuda company with another company or corporation a shareholder of the Bermuda company who is not satisfied that fair value has been offered for such shareholders shares may within one month of notice of the shareholders meeting apply to the Supreme Court of Bermuda to appraise the fair value of those shares. Under Delaware law with certain exceptions a merger consolidation or sale of all or substantially all the assets of a corporation must be approved by the board of directors and a majority of the issued and outstanding shares entitled to vote thereon. Under Delaware law a shareholder of a corporation participating in certain major corporate transactions may under certain circumstances be entitled to appraisal rights pursuant to which such shareholder may receive cash in the amount of the fair value of the shares held by such shareholder as determined by a court in lieu of the consideration such shareholder would otherwise receive in the transaction. Shareholders Suit. Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts however would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal or would result in the violation of the companys memorandum of association or bye-laws. Furthermore consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of the companys shareholders than that which actually approved it. When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders one or more shareholders may apply to the Supreme Court of Bermuda which may make such order as it sees fit including an order regulating the conduct of the companys affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company. Our bye-laws contain a provision by virtue of which we and our shareholders waive any claim or right of action that they have both individually and on our behalf against any director or officer in relation to any action or failure to take action by such director or officer except in respect of any fraud or dishonesty of such director or officer. Class actions and derivative actions generally are available to shareholders under Delaware law for among other things breach of fiduciary duty corporate waste and actions not taken in accordance with applicable law. In such actions the court has discretion to permit the winning party to recover attorneys fees incurred in connection with such action. Indemnification of Directors. We may indemnify our directors and officers in their capacity as directors or officers for any loss arising or liability attaching to them by virtue of any rule of law in respect of any negligence default breach of duty or breach of trust of which a director or officer may be guilty in relation to the company other than in respect of his own fraud or dishonesty. Under Delaware law a corporation may indemnify a director or officer of the corporation against expenses including attorneys fees judgments fines and amounts paid in settlement actually and reasonably incurred in defense of an action suit or proceeding by reason of such position if such director or officer acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation and with respect to any criminal action or proceeding such director or officer had no reasonable cause to believe his or her conduct was unlawful. In addition we have entered into customary indemnification agreements with our directors. Item 1B. Unresolved Staff Comments Not applicable. 75 Item 2. Properties See Item 1. Business. We also have various operating leases for rental of office space office and field equipment and vehicles. See Note 15 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for the future minimum rental payments. Such information is incorporated herein by reference. Item 3. Legal Proceedings From time to time we may be involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the occurrence or outcome of these proceedings with certainty we do not believe that an adverse result in any pending legal or regulatory proceeding individually or in the aggregate would be material to our consolidated financial condition or cash flows however an unfavorable outcome could have a material adverse effect on our results of operations for a specific interim period or year. Item 4. Mine Safety Disclosures Not applicable. 76 PART II Item 5. Market for Registrants Common Equity Related Stockholder Matters and Issuer Purchases of Equity Securities Common Shares Trading Summary Our common shares are traded on the NYSE under the symbol KOS. The following table shows the quarterly high and low sale prices of our common shares. 2015 2014 High Low High Low First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.32 7.58 11.60 9.88 Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.03 7.94 11.27 10.00 Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.44 5.34 11.23 9.24 Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.00 4.62 10.41 6.96 As of February 16 2016 based on information from the Companys transfer agent Computershare Trust Company N.A. the number of holders of record of Kosmos common shares was 122. On February 16 2016 the last reported sale price of Kosmos common shares as reported on the NYSE was 3.94 per share. We have never paid any dividends on our common shares. At the present time we intend to retain all of our future earnings if any generated by our operations for the development and growth of our business. Additionally we are subject to Bermuda legal constraints that may affect our ability to pay dividends on our common shares and make other payments. Under the Bermuda Companies Act we may not declare or pay a dividend if there are reasonable grounds for believing that we are or would after the payment be unable to pay our liabilities as they become due or that the realizable value of our assets would thereafter be less than the aggregate of our liabilities issued share capital and share premium accounts. Certain of our subsidiaries are also currently restricted in their ability to pay dividends to us pursuant to the terms of the Senior Notes the Facility and the Corporate Revolver unless we meet certain conditions financial and otherwise. Any decision to pay dividends in the future is at the discretion of our board of directors and depends on our financial condition results of operations capital requirements and other factors that our board of directors deems relevant. Currently we do not anticipate paying any dividends in the foreseeable future. Issuer Purchases of Equity Securities Under the terms of our Long Term Incentive Plan LTIP we have issued shares of restricted shares and restricted share units to our employees. On the date that these restricted shares and restricted share units vest we provide such employees the option to withhold via a net exercise provision pursuant to our applicable restricted share award agreements and the LTIP the number of vested shares based on the closing price of our common shares on such vesting date equal to the minimum statutory tax liability owed by such grantee. The shares withheld from the grantees to settle their tax liability are reallocated to the number of shares available for issuance under the LTIP. The 77 31MAR201604392500 following table outlines the total number of shares withheld during fiscal year 2015 and the average price paid per share. Total Number Average of Shares Price Paid WithheldPurchased per Share In thousands January 1 2015January 31 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . February 1 2015February 28 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 8.77 March 1 2015March 31 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 8.98 April 1 2015April 30 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196 9.53 May 1 2015May 31 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1470 9.31 June 1 2015June 30 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 8.87 July 1 2015July 31 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . August 1 2015August 31 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . September 1 2015September 30 2015 . . . . . . . . . . . . . . . . . . . . . . . . . October 1 2015October 31 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 5.67 November 1 2015November 30 2015 . . . . . . . . . . . . . . . . . . . . . . . . . 2 6.86 December 1 2015December 31 2015 . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1701 9.32 Share Performance Graph The following Performance Graph and related information shall not be deemed soliciting material or to be filed with the SEC nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934 each as amended except to the extent that the Company specifically incorporates it by reference into such filings. The following graph illustrates changes over the period from May 11 2011 date our common shares commenced trading on the NYSE through December 31 2015 in cumulative total stockholder return on our common shares as measured against the cumulative total return of the SP 500 Index and the SIG Oil Exploration Production Index. The graph tracks the performance of a 100 investment in our common shares and in each index with the reinvestment of all dividends. 200 150 175 125 100 75 50 25 0 511 1211 1212 121512141213 Kosmos Energy Ltd. KOS SIG Oil Exploration Production Index EPXSP 500 SPX December 31 May 11 2011 2011 2012 2013 2014 2015 Kosmos Energy Ltd. KOS . . . . . . . . . . 100.00 68.11 68.61 62.11 46.61 28.89 SP 500 SPX . . . . . . . . . . . . . . . . . . 100.00 94.55 109.36 143.24 161.77 163.86 SIG Oil Exploration Production Index EPX . . . . . . . . . . . . . . . . . . . 100.00 84.33 78.53 99.03 71.71 40.71 78 Item 6. Selected Financial Data The following selected consolidated financial information set forth below as of and for the five years ended December 31 2015 should be read in conjunction with Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data. Consolidated Statements of Operations Information Years Ended December 31 2015 2014 2013 2012 20111 In thousands except per share data Revenues and other income Oil and gas revenue . . . . . . . . . . . . . . . . . . . . 446696 855877 851212 667951 666912 Gain on sale of assets . . . . . . . . . . . . . . . . . . . 24651 23769 Other income . . . . . . . . . . . . . . . . . . . . . . . . . 209 3092 941 3150 775 Total revenues and other income . . . . . . . . . . 471556 882738 852153 671101 667687 Costs and expenses Oil and gas production . . . . . . . . . . . . . . . . . . 105336 100122 96791 95109 83551 Exploration expenses . . . . . . . . . . . . . . . . . . . . 156203 93519 230314 100652 128753 General and administrative . . . . . . . . . . . . . . . 136809 135231 158421 157087 111235 Depletion and depreciation . . . . . . . . . . . . . . . 155966 198080 222544 185707 140469 Interest and other financing costs net . . . . . . . . 37209 45548 47590 65425 132492 Derivatives net . . . . . . . . . . . . . . . . . . . . . . . . 210649 281853 17027 31490 11777 Restructuring charges . . . . . . . . . . . . . . . . . . . 11742 Doubtful accounts expense . . . . . . . . . . . . . . . . 39782 Other expenses net . . . . . . . . . . . . . . . . . . . . . 5246 2081 3512 1475 149 Total costs and expenses . . . . . . . . . . . . . . . . 386120 304470 776199 636945 568644 Income before income taxes . . . . . . . . . . . . . . . . 85436 578268 75954 34156 99043 Income tax expense . . . . . . . . . . . . . . . . . . . . . 155272 298898 166998 101184 76686 Net income loss . . . . . . . . . . . . . . . . . . . . . . . . 69836 279370 91044 67028 22357 Accretion to redemption value of convertible preferred units . . . . . . . . . . . . . . . . . . . . . . . . 24442 Net income loss attributable to common shareholders . . . . . . . . . . . . . . . . . . . . . . . . . . 69836 279370 91044 67028 2085 Net income loss per share attributable to common shareholders the year ended December 31 2011 represents the period from May 16 2011 to December 31 20112 Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.18 0.73 0.24 0.18 0.09 Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.18 0.72 0.24 0.18 0.09 Weighted average number of shares used to compute net income loss per share the year ended December 31 2011 represents the period from May 16 2011 to December 31 20112 Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 382610 379195 376819 371847 368474 Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . 382610 386119 376819 371847 368607 1 Pursuant to the terms of our corporate reorganization that was completed simultaneously with the closing of the initial public offering all of the interests in Kosmos Energy Holdings were exchanged for newly issued common shares of Kosmos Energy Ltd. based on these interests relative rights as set forth in 79 Kosmos Energy Holdings then-current operating agreement. This included convertible preferred units of Kosmos Energy Holdings which were redeemed upon the consummation of the qualified public offering as defined in the operating agreement in effect prior to the initial public offering into common shares of Kosmos Energy Ltd. based on the pre-offering equity value of such interests. 2 For the year ended December 31 2011 we have presented net income loss per share attributable to common shareholders including weighted average number of shares used to compute net income loss per share attributable to common shareholders from the date of our corporate reorganization May 16 2011 to December 31 2011. Net income for the period from May 16 2011 through December 31 2011 was 36.1 million. Consolidated Balance Sheets Information December 31 201512 20141 20131 20121 20111 In thousands Cash and cash equivalents . . . . . . . . . 275004 554831 598108 515164 673092 Total current assets . . . . . . . . . . . . . . 734148 1010476 734961 750118 1112481 Total property and equipment net . . . 2322839 1784846 1522962 1525762 1377041 Total other assets . . . . . . . . . . . . . . . . 146063 131537 53742 48021 7565 Total assets . . . . . . . . . . . . . . . . . . . . 3203050 2926859 2311665 2323901 2497087 Total current liabilities . . . . . . . . . . . . 456741 448771 219324 190253 339607 Total long-term liabilities . . . . . . . . . . 1420796 1139129 1100006 1104742 1136754 Total shareholders equity . . . . . . . . . . 1325513 1338959 992335 1028906 1020726 Total liabilities and shareholders equity . . . . . . . . . . . . . . . . . . . . . . 3203050 2926859 2311665 2323901 2497087 1 Effective December 31 2015 the Company adopted new guidance on the presentation of debt issuance costs. This guidance was adopted retrospectively and all prior periods have been adjusted to reflect this change in accounting principle. 2 Effective December 31 2015 the Company adopted new guidance on the presentation of deferred taxes. The Company elected to adopt the accounting change using the prospective method. See Note 2 of Notes to the Consolidated Financial Statements. Consolidated Statements of Cash Flows Information December 31 2015 2014 2013 2012 2011 In thousands Net cash provided by used in Operating activities . . . . . . . . . . . . . . . . . 440779 443586 522404 371530 364909 Investing activities . . . . . . . . . . . . . . . . . . 800240 347679 324133 402662 385140 Financing activities . . . . . . . . . . . . . . . . . 79634 139184 115327 126796 592908 80 Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors including without limitation those set forth in Cautionary Statement Regarding Forward-Looking Statements and Item 1A. Risk Factors. The following discussion of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this annual report on Form 10-K. Overview Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margin. Our assets include existing production and development projects offshore Ghana large discoveries offshore Mauritania and Senegal as well as exploration licenses with significant hydrocarbon potential offshore Portugal Sao Tome and Principe Suriname Morocco and Western Sahara. Recent Developments Corporate During April 2015 we issued an additional 225.0 million of 7.875 Senior Secured Notes due 2021 Senior Notes and received net proceeds of 206.8 million after deducting discounts commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. In June 2015 we amended and restated the Corporate Revolver from a number of financial institutions increasing the borrowing capacity from 300.0 million to 400.0 million extending the maturity date to November 23 2018 and lowering the commitment fees on the undrawn portion of the total commitments to 30 per annum of the respective margin. Additionally a negative covenant was added that restricts our ability to incur additional indebtedness that would not be permitted by the indenture governing our 7.875 senior secured notes due 2021. In July 2015 we reduced the size of our revolving letter of credit facility agreement LC facility by 25.0 million to 75.0 million with additional commitments up to 50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. Rig Agreement In September 2015 Kosmos Energy Ventures KEV a subsidiary of Kosmos Energy Ltd. amended its Atwood Achiever rig agreement with Atwood Oceanics Inc. effective October 1 2015 to extend the contract end date by one year and reduce the rate to approximately 0.5 million per day. KEV is currently evaluating its option to revert to the original day rate of approximately 0.6 million per day and original agreement end date of November 2017. If KEV exercises the option KEV would be required to make a rate recovery payment equal to the difference between the original day rate and the amended day rate multiplied by the number of days from the amendment effective date to the date the option is exercised plus certain administrative costs. Ghana 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 thus reducing their development costs. The expansion of the Jubilee Unit becomes effective upon approval by Ghanas Ministry of Petroleum of the GJFFDP which was submitted to the government of Ghana in December 2015. The GJFFDP encompasses future development of the Jubilee 81 Field in addition to future development of the Mahogany and Teak discoveries which were declared commercial earlier in the year. We are currently in discussions with the government of Ghana concerning the GJFFDP. Upon approval of the GJFFDP by the Ministry of Petroleum 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 and the Mahogany and Teak areas will be excluded from any future Jubilee redeterminations. 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. 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 Ghanas Ministry of Petroleum. In April 2015 the Special Chamber of the International Tribunal of the Law of the Sea the ITLOS issued an order in response to the provisional measures sought by the Government of Cote dIvoire in its pending maritime boundary dispute with the Government of Ghana. ITLOS rejected the request that Ghana suspend all ongoing exploration and development operations in the disputed area in which the TEN development and Wawa Discovery are situated until ITLOS gives its decision on the maritime boundary dispute which is expected by late 2017. ITLOS did order Ghana to suspend new drilling in the disputed area. On June 11 2015 the Ghana Attorney General issued a letter to the DT Operator which confirmed the DT Block partners may i continue to drill wells that had been started but not completed prior to the ITLOS order and ii carry out completion work on wells that have already been drilled. The TEN development is currently estimated to be approximately 80 percent complete. We expect TEN development activities will continue as planned with first oil expected in the third quarter of 2016. With respect to the Wawa Discovery we plan to discuss with the Government of Ghana the effects of the ITLOS order on the proposed Wawa appraisal activities so that we can more clearly define our future plans and corresponding timeline. Under the terms of the petroleum contract we currently have until May 2016 to make a decision regarding a declaration of commerciality if we are unable to extend the appraisal period. Jubilee gas exports were temporarily halted in July due to an issue with the gas compression facilities on the Jubilee FPSO. The reduction in gas exports constrained Jubilee Field production to approximately 65000 barrels gross of oil per day. The gas compression facilities were repaired and we resumed full production in early August 2015. Mauritania In March 2015 we closed a farm-out agreement with Chevron covering the C8 C12 and C13 petroleum contracts offshore Mauritania. Under the terms of the farm-out agreement Chevron acquired a 30 non-operated working interest in each of the contract areas. As partial consideration for the farm-out Chevron paid a disproportionate share of the costs of one exploration well the Marsouin-1 exploration well as well as its proportionate share of certain previously incurred exploration costs. The final allocation resulted in sales proceeds of 28.7 million which exceeded our book basis in the assets resulting in a 24.7 million gain on the transaction. As a further component of the consideration for the farm-out Chevron was required to make an election by February 1 2016 to either farm-in to the Tortue-1 exploration well by paying a disproportionate share of the costs incurred in drilling of the well or alternatively elect to not farm-in to the Tortue-1 exploration well and pay a disproportionate share of the costs of a second contingent exploration or appraisal well in the contract areas subject to maximum expenditure caps. Chevron failed to make this mandatory election by the required date. Consequently pursuant to the terms of the farm-out agreement Chevron has withdrawn from our Mauritania blocks. Subsequently Chevron requested that we engage in discussions related to the possible reinstatement of Chevrons interests in our Mauritania blocks and such discussions are ongoing. However if no such agreement is reached in these discussions Chevrons 30 non-operated 82 participating interest will be reassigned to us subject to requisite government approvals and our participating interests in the Block C8 C12 and C13 petroleum contracts will be 90. In April 2015 we announced the Tortue-1 exploration well located in the Ahmeyim discovery area on Block C8 offshore Mauritania had made a significant play-opening gas discovery. Based on preliminary analysis of drilling results and intermediate logging the Tortue-1 exploration well has 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 well was drilled to a total depth of 5107 meters. In January 2016 we drilled the Guembeul-1 well in our Saint Louis Profond block offshore Senegal which confirmed the extension of the Ahmeyim discovery into Senegal. An appraisal program is currently being executed to delineate the Ahmeyim discovery. We are currently drilling the Ahmeyim-2 appraisal well in Mauritania to further delineate the Ahmeyim discovery. In November 2015 we announced the Marsouin-1 exploration well located in the northern part of Block C8 offshore Mauritania had made a second significant play-extending gas discovery building on our successful exploration program in the outboard Cretaceous petroleum system offshore Mauritania. The Marsouin-1 well is located approximately 60 kilometers north of the Ahmeyim discovery and was drilled to a total depth of 5153 meters in nearly 2400 meters 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. An appraisal program is currently being planned to delineate the Marsouin discovery. Senegal We obtained approximately 7000 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. The results of the these 3D seismic programs provided sufficient encouragement to begin an acquiring additional 4500 square kilometers of seismic data in November 2015 in the western portions of both blocks to fully evaluate the prospectivity. The survey is expected to be completed in February 2016. In June 2015 we entered the first renewal of the exploration period for the Cayar Offshore Profond and Saint Louis Profond Contract Areas which lasts for three years. The first renewal period includes a one well commitment in each block. After the required relinquishment of acreage to enter the first renewal the Cayar Offshore Profond and Saint Louis Profond Contract Areas comprise approximately 1.4 million acres and 1.6 million acres respectively. In January 2016 we announced the Guembeul-1 exploration well located in the northern part of the Saint Louis Offshore Profond license area in Senegal has made a significant gas discovery. Located approximately five kilometers south of the Tortue-1 exploration well in Mauritania in approximately 2700 meters of water the Guembeul-1 exploration well was drilled to a total depth of 5245 meters. 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. Importantly the Guembeul-1 exploration well has demonstrated reservoir continuity as well as static pressure communication with the Tortue-1 exploration well in the Lower Cenomanian. 83 Western Sahara 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 is 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 will be integrated with the ongoing geological evaluation to determine future exploration activity. Total well and other related costs of 86.8 million are included in exploration expenses in the accompanying consolidated statement of operations for the year ended December 31 2015. Portugal In March 2015 we closed a farm-in agreement with Repsol Exploracion S.A. Repsol to acquire a non-operated interest in the Camarao Ameijoa Mexilhao and Ostra blocks in the Peniche Basin offshore Portugal. As part of the farm-in agreement we reimbursed a portion of Repsols previously incurred exploration costs as well as partially carried Repsols share of the costs of a planned 3D seismic program. After giving effect to the farm-in agreement our participating interest is 31 in each of the blocks. In September 2015 we completed a 3D seismic survey of approximately 3200 square kilometers over the Camarao block offshore Portugal. Sao Tome and Principe In October 2015 we closed a sale and purchase agreement with ERHC Energy EEZ LDA whereby we acquired an 85 participating interest and operatorship in Block 11 offshore Sao Tome and Principe. The national petroleum agency Agencia Nacional Do Petroleo De Sao Tome E Principe ANP has a 15 carried interest. In November 2015 we closed a farm-in agreement with Galp Energia Sao Tome E Principe Unipessoal LDA Galp a wholly owned subsidiary of Petrogal S.A. to acquire a 45 non-operated participating interest in Block 6 offshore Sao Tome and Principe. In January 2016 we closed a farm-in agreement with Equator an affiliate of Oando for Block 5 offshore Sao Tome and Principe whereby we acquired a 65 participating interest and operatorship in the block. Certain governmental approvals and processes are still required to be completed before this acquisition is effective. Suriname In April 2015 we received an extension of the initial exploration phase for Block 45 offshore Suriname which now expires in September 2016. In December 2015 we received an extension of the initial exploration phase for Block 42 offshore Suriname which now expires in September 2018. 84 Results of Operations All of our results as presented in the table below represent operations from the Jubilee Field in Ghana. Certain operating results and statistics for the years ended December 31 2015 2014 and 2013 are included in the following table Years Ended December 31 2015 2014 2013 In thousands except per barrel data Sales volumes MBbl . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8538 8728 7778 Revenues Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 446696 855877 851212 Average sales price per Bbl . . . . . . . . . . . . . . . . . . 52.32 98.06 109.44 Costs Oil production excluding workovers . . . . . . . . . . 92994 79648 57608 Oil production workovers . . . . . . . . . . . . . . . . . 12342 20474 39183 Total oil production costs . . . . . . . . . . . . . . . . 105336 100122 96791 Depletion and depreciation . . . . . . . . . . . . . . . . 155966 198080 222544 Average cost per Bbl Oil production excluding workovers . . . . . . . . . . 10.89 9.13 7.41 Oil production workovers . . . . . . . . . . . . . . . . . 1.45 2.35 5.04 Total oil production costs . . . . . . . . . . . . . . . . 12.34 11.48 12.45 Depletion and depreciation . . . . . . . . . . . . . . . . 18.27 22.69 28.61 Oil production cost and depletion costs . . . . . . . 30.61 34.17 41.06 85 The discussion of the results of operations and the period-to-period comparisons presented below analyze our historical results. The following discussion may not be indicative of future results. Year Ended December 31 2015 vs. 2014 Years Ended December 31 Increase 2015 2014 Decrease In thousands Revenues and other income Oil and gas revenue . . . . . . . . . . . . . . . . . . . . 446696 855877 409181 Gain on sale of assets . . . . . . . . . . . . . . . . . . 24651 23769 882 Other income . . . . . . . . . . . . . . . . . . . . . . . . 209 3092 2883 Total revenues and other income . . . . . . . . . 471556 882738 411182 Costs and expenses Oil and gas production . . . . . . . . . . . . . . . . . 105336 100122 5214 Exploration expenses . . . . . . . . . . . . . . . . . . . 156203 93519 62684 General and administrative . . . . . . . . . . . . . . 136809 135231 1578 Depletion and depreciation . . . . . . . . . . . . . . 155966 198080 42114 Interest and other financing costs net . . . . . . 37209 45548 8339 Derivatives net . . . . . . . . . . . . . . . . . . . . . . . 210649 281853 71204 Restructuring charges . . . . . . . . . . . . . . . . . . 11742 11742 Other expenses net . . . . . . . . . . . . . . . . . . . . 5246 2081 3165 Total costs and expenses . . . . . . . . . . . . . . . 386120 304470 81650 Income before income taxes . . . . . . . . . . . . . . . 85436 578268 492832 Income tax expense . . . . . . . . . . . . . . . . . . . . 155272 298898 143626 Net income loss . . . . . . . . . . . . . . . . . . . . . . . 69836 279370 349206 Oil and gas revenue. Oil and gas revenue decreased by 409.2 million during the year ended December 31 2015 as compared to the year ended December 31 2014 as a result of a lower realized price per barrel and a slight decrease in sales volumes. We lifted and sold 8538 MBbl at an average realized price per barrel of 52.32 in 2015 and 8728 MBbl at an average realized price per barrel of 98.06 in 2014. Oil and gas production. Oil and gas production costs increased by 5.2 million during the year ended December 31 2015 as compared to the year ended December 31 2014 primarily as a result of an increase in routine operating expenses including 2.8 million related to repairs to the gas compressor and costs to remove the damaged water injection riser partially mitigated by a reduction in well workover costs. Our workover costs are related to performing workovers on our wells which are performed on an as needed basis. We expect the amount of costs associated with workovers to fluctuate based on the activity level during each year. Exploration expenses. Exploration expenses increased by 62.7 million during the year ended December 31 2015 as compared to the year ended December 31 2014. The increase is primarily a result of 86.8 million of unsuccessful well costs for the Western Sahara CB-1 exploration well in 2015 partially mitigated by a decrease in seismic costs of 28.6 million. Depletion and depreciation. Depletion and depreciation decreased 42.1 million during the year ended December 31 2015 as compared with the year ended December 31 2014 primarily as a result of a lower depletion rate in 2015 as a result of an increase in our proved reserves associated with the Jubilee Field. 86 Interest and other financing costs net. Interest expense decreased by 8.3 million during the year ended December 31 2015 as compared to the year ended December 31 2014 primarily as a result of higher gross interest costs driven by a larger debt balance offset by higher capitalized interest during the year ended December 31 2015 as compared to the year ended December 31 2014. Derivatives net. During the years ended December 31 2015 and 2014 we recorded a gain of 210.6 million and 281.9 million respectively on our outstanding hedge positions. The gains recorded were a result of decreases in the forward oil price curve during the respective periods. Restructuring charges. During the year ended December 31 2015 we had no restructuring charges however during the year ended December 31 2014 we recognized 11.7 million in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization which includes 5.0 million of non-cash expense related to awards granted under our LTIP. Income tax expense. The Companys effective tax rates for the years ended December 31 2015 and 2014 were 182 and 52 respectively. The effective tax rates for the periods presented were impacted by losses primarily related to exploration expenses incurred in jurisdictions in which we are not subject to taxes and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such expenses or losses. Income tax expense decreased by 143.6 million during the year ended December 31 2015 as compared with the year ended December 31 2014 primarily as a result of lower revenue in Ghana. Year Ended December 31 2014 vs. 2013 Years Ended December 31 Increase 2014 2013 Decrease In thousands Revenues and other income Oil and gas revenue . . . . . . . . . . . . . . . . . . . . 855877 851212 4665 Gain on sale of assets . . . . . . . . . . . . . . . . . . . 23769 23769 Other income . . . . . . . . . . . . . . . . . . . . . . . . . 3092 941 2151 Total revenues and other income . . . . . . . . . 882738 852153 30585 Costs and expenses Oil and gas production . . . . . . . . . . . . . . . . . . 100122 96791 3331 Exploration expenses . . . . . . . . . . . . . . . . . . . 93519 230314 136795 General and administrative . . . . . . . . . . . . . . . 135231 158421 23190 Depletion and depreciation . . . . . . . . . . . . . . . 198080 222544 24464 Interest and other financing costs net . . . . . . . 45548 47590 2042 Derivatives net . . . . . . . . . . . . . . . . . . . . . . . 281853 17027 298880 Restructuring charges . . . . . . . . . . . . . . . . . . . 11742 11742 Other expenses net . . . . . . . . . . . . . . . . . . . . 2081 3512 1431 Total costs and expenses . . . . . . . . . . . . . . . 304470 776199 471729 Income before income taxes . . . . . . . . . . . . . . . . 578268 75954 502314 Income tax expense . . . . . . . . . . . . . . . . . . . . 298898 166998 131900 Net income loss . . . . . . . . . . . . . . . . . . . . . . . . 279370 91044 370414 Oil and gas revenue. Oil and gas revenue increased by 4.7 million during the year ended December 31 2014 as compared to the year ended December 31 2013 primarily as a result of an increase in sales volumes nine liftings in 2014 compared to eight in 2013 partially offset by a lower 87 realized price per barrel. We lifted and sold 8728 MBbl at an average realized price per barrel of 98.06 in 2014 and 7778 MBbl at an average realized price per barrel of 109.44 in 2013. Gain on sale of assets. During the year ended December 31 2014 we closed three farm-out agreements with BP. As part of the transaction we received proceeds in excess of our book basis resulting in a gain of 23.8 million. Oil and gas production. Oil and gas production costs increased by 3.3 million during the year ended December 31 2014 as compared to the year ended December 31 2013 primarily as a result of an increase in routine operating expenses offset by a reduction in well workover costs and non-routine operating costs. Our workover costs are related to performing workovers on our wells which are performed on an as needed basis. We expect the amount of costs associated with workovers to fluctuate based on the activity level during each year. Exploration expenses. Exploration expenses decreased by 136.8 million during the year ended December 31 2014 as compared to the year ended December 31 2013. The decrease is primarily a result of 105.8 million of unsuccessful well and other related costs primarily related to the Cameroon Sipo-1 exploration well the Ghana Sapele-1 exploration well and the Ghana Akasa-2A appraisal well and 110.4 million for seismic costs primarily for Mauritania Ireland Morocco and new business activities incurred during the year ended December 31 2013 compared to 81.2 million for seismic costs for Senegal Morocco including Western Sahara Mauritania Ireland Suriname and new business during the year ended December 31 2014. General and administrative. General and administrative costs decreased by 23.2 million during the year ended December 31 2014 as compared to the year ended December 31 2013. The decrease from prior year is related to an increase in capitalized general and administrative costs and general and administrative costs incurred for the benefit of and allocated to exploration expense and a decrease in professional fees and occupancy and general expenses partially offset by an increase in compensation and benefits. Depletion and depreciation. Depletion and depreciation decreased 24.5 million during the year ended December 31 2014 as compared with the year ended December 31 2013 primarily as a result of a lower depletion rate in 2014 as a result of an increase in our proved reserves associated with the Jubilee Field. Interest and other financing costs net. Interest expense decreased by 2.0 million during the year ended December 31 2014 as compared to the year ended December 31 2013 primarily as a result of a write-down of the deferred interest reduction in interest expense as a result of refinancing our commercial debt facility effective in March 2014 and a lower average outstanding debt balance during the year ended December 31 2014 as compared to the year ended December 31 2013. Derivatives net. During the years ended December 31 2014 and 2013 we recorded a gain of 281.9 million and a loss of 17.0 million respectively on our outstanding hedge positions. The gain and loss recorded were a result of changes in the forward curve of oil prices during the respective periods. Restructuring charges. During the year ended December 31 2014 we recognized 11.7 million in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization which includes 5.0 million of non-cash expense related to awards granted under our LTIP. 88 Income tax expense. The Companys effective tax rates for the years ended December 31 2014 and 2013 were 51.7 and 219.9 respectively. The effective tax rates for the periods presented are impacted by losses primarily related to exploration expenses incurred in jurisdictions in which we are not subject to taxes and therefore do not generate any income tax benefits and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such losses. Income tax expense increased 131.9 million during the years ended December 31 2014 as compared with December 31 2013 primarily as a result of deferred taxes related to the significant mark-to-market gain on derivatives. Liquidity and Capital Resources We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to exploring for and developing oil and natural gas resources along the Atlantic Margin. We have historically met our funding requirements through cash flows generated from our operating activities and obtained additional funding from issuances of equity and debt. In relation to cash flow generated from our operating activities if we are unable to continuously export associated natural gas in large quantities from the Jubilee Field and the potential production restraints caused thereby then the Companys cash flows from operations will be adversely affected. In prior years certain near wellbore productivity issues were identified impacting several Phase 1 production wells. We have also experienced mechanical issues in the Jubilee Field including failures of our water injection facilities and gas compressor on the FPSO. This equipment downtime negatively impacted past oil production. The Jubilee Unit partners identified a means of successfully mitigating the near wellbore productivity issues with ongoing acid stimulation treatments and we are in the process of correcting the current mechanical issues experienced in the Jubilee Field. Following a February 2016 inspection of the turret area of the FPSO by SOFEC Inc. SOFEC the original turret manufacturer a potential issue was identified with the turret bearing. As a precautionary measure additional operating procedures to monitor the turret bearing and reduce the degree of rotation of the vessel are being put in place. SOFEC will now undertake further offshore examinations and Tullow operator of the Jubilee Unit will work with SOFEC to determine what further measures will be required. Oil production and gas export is continuing as normal. While we are presently in a strong financial position the decline in oil prices experienced since 2014 if prolonged or if further deterioration of pricing continues could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements as well as impact the borrowing base available under the Facility or the related debt covenants. Commodity prices are volatile and future prices cannot be accurately predicted. We maintain a hedging program to partially mitigate the price volatility. Our investment decisions are based on longer-term commodity prices based on the long-term nature of our projects and development plans. Current commodity prices our hedging program and our current liquidity position support our capital program for 2016. As such our 2016 capital budget is based on our development plans for Ghana and our exploration and appraisal program for 2016. 89 Sources and Uses of Cash The following table presents the sources and uses of our cash and cash equivalents for the years ended December 31 2015 2014 and 2013 Years Ended December 31 2015 2014 2013 In thousands Sources of cash and cash equivalents Net cash provided by operating activities . . . . . 440779 443586 522404 Net proceeds from issuance of senior secured notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 206774 294000 Borrowings under long-term debt . . . . . . . . . . 100000 Proceeds on sale of assets . . . . . . . . . . . . . . . . 28692 58315 Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . 20924 776245 816825 522404 Uses of cash and cash equivalents Oil and gas assets . . . . . . . . . . . . . . . . . . . . . . 823642 424535 317413 Other property . . . . . . . . . . . . . . . . . . . . . . . . 1483 2383 4970 Payments on long-term debt . . . . . . . . . . . . . . 200000 400000 100000 Purchase of treasury stock . . . . . . . . . . . . . . . . 18110 11096 13101 Deferred financing costs . . . . . . . . . . . . . . . . . 9030 22088 2226 Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . 3807 1750 1056072 860102 439460 Increase decrease in cash and cash equivalents . 279827 43277 82944 Net cash provided by operating activities. Net cash provided by operating activities in 2015 was 440.8 million compared with net cash provided by operating activities of 443.6 million in 2014 and 522.4 million in 2013 respectively. The decrease in cash provided by operating activities in the year ended December 31 2015 when compared to the same period in 2014 was primarily as a result of a decrease in results from operations driven by lower realized revenue per barrel sold mitigated by a positive change in working capital items. The increase in cash provided by operating activities in 2014 when compared to 2013 was primarily as a result of an increase in oil and gas revenues offset by a negative change in working capital items. The following table presents our liquidity and financial position as of December 31 2015 December 31 2015 In thousands Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 275004 Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35858 Senior Notes at par . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 525000 Drawings under the Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 400000 Net debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 614138 Availability under the Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1100000 Availability under the Corporate Revolver . . . . . . . . . . . . . . . . . . . 400000 Available borrowings plus cash and cash equivalents . . . . . . . . . . . 1775004 90 Capital Expenditures and Investments We expect to incur capital costs as we complete the TEN development and fund asset integrity projects at Jubilee execute exploration and appraisal activities in our Senegal and Mauritania license areas and purchase and analyze seismic perform new ventures and manage our rig activities. We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells we plan to drill our participating interests in our prospects including disproportionate payment amounts the costs involved in developing or participating in the development of a prospect the timing of third-party projects our ability to utilize our available drilling rig capacity the availability of suitable equipment and qualified personnel and our cash flows from operations. These assumptions are inherently subject to significant business political economic regulatory environmental and competitive uncertainties contingencies and risks all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if market conditions deteriorate or one or more of our assumptions proves to be incorrect or if we choose to expand our acquisition exploration appraisal development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could result in dilution to our shareholders. The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations. 2016 Capital Program We estimate we will spend approximately 650 million of capital for the year ending December 31 2016. This capital expenditure budget consists of approximately 200 million for developmental related expenditures offshore Ghana focused on the delivery of the TEN project and Jubilee asset integrity approximately 250 million in Mauritania and Senegal related to the appraisal of the Ahmeyim discovery drilling of one oil prospect in Senegal and the acquisition of additional seismic and approximately 200 million related to seismic acquisition new ventures and rig costs for the Atwood Achiever. This positions us to achieve our objectives and invest counter-cyclically while maintaining a strong balance sheet. The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our drilling results. Given the current environment and status of ongoing prospect development we plan to suspend drilling activities after we complete the drilling of the Ahmeyim-2 appraisal well and one oil prospect in Senegal. Our future financial condition and liquidity will be impacted by among other factors our level of production of oil and the prices we receive from the sale of oil our ability to effectively hedge future production volumes the success of our exploration and appraisal drilling program the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered the speed with which we can bring such discoveries to production our partners alignment with respect to capital plans and the actual cost of exploration appraisal and development of our oil and natural gas assets. 91 Significant Sources of Capital Facility In March 2014 the Company amended and restated the Facility with a total commitment of 1.5 billion from a number of financial institutions. The Facility supports our oil and gas exploration appraisal and development programs and corporate activities. As part of the debt refinancing in March 2014 the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt and existing unamortized debt issuance costs attributable to those participants were expensed. As a result we recorded a 2.9 million loss on the extinguishment of debt for the year ended December 31 2014. As of December 31 2015 we have 37.5 million of unamortized issuance costs related to the Facility which will be amortized over the remaining term of the Facility including certain costs related to the amendment. As of December 31 2015 borrowings under the Facility totaled 400.0 million and the undrawn availability under the Facility was 1.1 billion. Interest is the aggregate of the applicable margin 3.25 to 4.50 depending on the length of time that has passed from the date the Facility was entered into LIBOR and mandatory cost if any as defined in the Facility. Interest is payable on the last day of each interest period and if the interest period is longer than six months on the dates falling at six-month intervals after the first day of the interest period. We pay commitment fees on the undrawn and unavailable portion of the total commitments if any. Commitment fees are equal to 40 per annum of the then-applicable respective margin when a commitment is available for utilization and equal to 20 per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835Interest which requires interest expense to be recognized using the effective interest method. As part of the March 2014 amendment the Facilitys estimated effective interest rate was changed and accordingly we adjusted our estimate of deferred interest previously recorded during prior years by 4.5 million which was recorded as a reduction to interest expense for the year ended December 31 2014. The Facility provides a revolving-credit and letter of credit facility. The availability period for the revolving-credit facility as amended in March 2014 expires on March 31 2018 however the Facility has a revolving-credit sublimit which will be the lesser of 500.0 million and the total available facility at that time that will be available for drawing until the date falling one month prior to the final maturity date. The letter of credit sublimit expires on the final maturity date. The available facility amount is subject to borrowing base constraints and beginning on March 31 2018 outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31 2021. As of December 31 2015 we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the Facility. The amount of funds available to be borrowed under the Facility also known as the borrowing base amount is determined each year on March 31 and September 30. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets reserves andor resources in Ghana. If an event of default exists under the Facility the lenders can accelerate the maturity and exercise other rights and remedies including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. The Facility contains customary cross default provisions. We were in compliance with the financial covenants contained in the Facility as of September 30 2015 the most recent assessment date which requires the maintenance of the field life cover ratio as defined in the glossary not less than 1.30x and 92 the loan life cover ratio as defined in the glossary not less than 1.10x and the debt cover ratio as defined in the glossary not more than 3.5x and the interest cover ratio as defined in the glossary not less than 2.25x. Corporate Revolver In November 2012 we secured a Corporate Revolver from a number of financial institutions which as amended in June 2015 has an availability of 400.0 million. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration appraisal and development programs. As of December 31 2015 there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was 400.0 million. Interest is the aggregate of the applicable margin 6.0 LIBOR and mandatory cost if any as defined in the Corporate Revolver. Interest is payable on the last day of each interest period and if the interest period is longer than six months on the dates falling at six-month intervals after the first day of the interest period. We pay commitment fees on the undrawn portion of the total commitments. Commitment fees as amended in June 2015 for the lenders are equal to 30 per annum of the respective margin when a commitment is available for utilization. The Corporate Revolver as amended in June 2015 expires on November 23 2018. The available amount is not subject to borrowing base constraints. We have the right to cancel all the undrawn commitments under the Corporate Revolver. We are required to repay certain amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default exists under the Corporate Revolver the lenders can accelerate the maturity and exercise other rights and remedies including the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us. The Corporate Revolver contains customary cross default provisions. We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30 2015 the most recent assessment date which requires the maintenance of the debt cover ratio as defined in the glossary not more than 3.5x and the interest cover ratio as defined in the glossary not less than 2.25x. The U.S. and many foreign economies continue to experience uncertainty driven by varying macroeconomic conditions. Although some of these economies have shown signs of improvement macroeconomic recovery remains uneven. Uncertainty in the macroeconomic environment and associated global economic conditions have resulted in extreme volatility in credit equity and foreign currency markets including the European sovereign debt markets and volatility in various other markets. If any of the financial institutions within our Facility or Corporate Revolver are unable to perform on their commitments our liquidity could be impacted. We actively monitor all of the financial institutions participating in our Facility and Corporate Revolver. None of the financial institutions have indicated to us that they may be unable to perform on their commitments. In addition we periodically review our banking and financing relationships considering the stability of the institutions and other aspects of the relationships. Based on our monitoring activities we currently believe our banks will be able to perform on their commitments. Revolving Letter of Credit Facility In July 2013 we entered into a revolving letter of credit facility agreement LC Facility. The size of the LC Facility is 75.0 million as amended in July 2015 with additional commitments up to 50.0 million being available if the existing lender increases its commitments or if commitments from 93 new financial institutions are added. The LC Facility provides that we shall maintain cash collateral in an amount equal to at least 75 of all outstanding letters of credit under the LC Facility provided that during the period of any breach of certain financial covenants the required cash collateral amount shall increase to 100. The fees associated with outstanding letters of credit issued will be 0.5 per annum. The LC Facility has an availability period which expires on June 1 2016. We may voluntarily cancel any commitments available under the LC Facility at any time. As of December 31 2015 there were nine letters of credit totaling 15.3 million under the LC Facility. The LC Facility contains customary cross default provisions. 7.875 Senior Secured Notes due 2021 During August 2014 the Company issued 300.0 million of Senior Notes and received net proceeds of approximately 292.5 million after deducting discounts commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. During April 2015 we issued an additional 225.0 million Senior Notes and received net proceeds of 206.8 million after deducting discounts commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional 225.0 million of Senior Notes have identical terms to the initial 300.0 million Senior Notes other than the date of issue the initial price the first interest payment date and the first date from which interest accrued. The Senior Notes mature on August 1 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1 2015 for the initial 300.0 million Senior Notes and August 1 2015 for the additional 225.0 million Senior Notes. The Senior Notes are secured subject to certain exceptions and permitted liens by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver and in certain circumstances the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries the Guarantees. Redemption and Repurchase. At any time prior to August 1 2017 and subject to certain conditions the Company may on any one or more occasions redeem up to 35 of the aggregate principal amount of Senior Notes issued under the indenture dated August 1 2014 related to the Senior Notes the Indenture at a redemption price of 107.875 plus accrued and unpaid interest with the cash proceeds of certain eligible equity offerings. Additionally at any time prior to August 1 2017 the Company may on any one or more occasions redeem all or a part of the Senior Notes at a redemption price equal to 100 plus any accrued and unpaid interest and a make-whole premium. On or after August 1 2017 the Company may redeem all or a part of the Senior Notes at the redemption prices expressed as percentages of principal amount set forth below plus accrued and unpaid interest Year Percentage On or after August 1 2017 but before August 1 2018 . . . . . . . . . . . . . . . 103.9 On or after August 1 2018 but before August 1 2019 . . . . . . . . . . . . . . . 102.0 On or after August 1 2019 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . 100.0 We may also redeem the Senior Notes in whole but not in part at any time if changes in tax laws impose certain withholding taxes on amounts payable on the Senior Notes at a price equal to the principal amount of the Senior Notes plus accrued interest and additional amounts if any as may be necessary so that the net amount received by each holder after any withholding or deduction on 94 payments of the Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted. Upon the occurrence of a change of control triggering event as defined under the Indenture the Company will be required to make an offer to repurchase the Senior Notes at a repurchase price equal to 101 of the principal amount plus accrued and unpaid interest to but excluding the date of repurchase. If we sell assets under certain circumstances outlined in the Indenture we will be required to use the net proceeds to make an offer to purchase the Senior Notes at an offer price in cash in an amount equal to 100 of the principal amount of the Senior Notes plus accrued and unpaid interest to but excluding the repurchase date. Covenants. The Indenture restricts our ability and the ability of our restricted subsidiaries to among other things incur or guarantee additional indebtedness create liens pay dividends or make distributions in respect of capital stock purchase or redeem capital stock make investments or certain other restricted payments sell assets enter into agreements that restrict the ability of our subsidiaries to make dividends or other payments to us enter into transactions with affiliates or effect certain consolidations mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the Senior Notes are assigned an investment grade rating by both Standard Poors Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing. Collateral. The Senior Notes are secured subject to certain exceptions and permitted liens by a first ranking fixed equitable charge on all currently outstanding shares additional shares dividends or other distributions paid in respect of such shares or any other property derived from such shares in each case held by us in relation to the Companys direct subsidiary Kosmos Energy Holdings pursuant to the terms of the Charge over Shares of Kosmos Energy Holdings dated November 23 2012 as amended and restated on March 14 2014 between the Company and BNP Paribas as Security and Intercreditor Agent. The Senior Notes share pari passu in the benefit of such equitable charge based on the respective amounts of the obligations under the Indenture and the amount of obligations under the Corporate Revolver. The Guarantees are not secured. Contractual Obligations The following table summarizes by period the payments due for our estimated contractual obligations as of December 31 2015 Payments Due By Year5 Total 2016 2017 2018 2019 2020 Thereafter In thousands Principal debt repayments1 . . . . . . . . . . . 925000 185714 739286 Interest payments on long-term debt2 . . . . 409052 78838 80731 73824 65740 64962 44957 Operating leases3 . . . . . . . . . . . . . . . . . . 12970 3230 3286 3323 3131 Atwood Achiever drilling rig contract4 . . . 518862 181379 180883 156600 1 Includes the scheduled principal maturities for the 525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the estimated future available borrowing base as of December 31 2015. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of December 31 2015 there were no borrowings under the Corporate Revolver. 2 Based on outstanding borrowings as noted in 1 above and the LIBOR yield curves at the reporting date and commitment fees related to the Facility and Corporate Revolver and interest on the Senior Notes. 95 3 Primarily relates to corporate office and foreign office leases. 4 Commitments calculated using the amended day rate of 0.5 million effective October 1 2015 excluding applicable taxes. KEV is currently evaluating its option to revert to the original day rate of approximately 0.6 million per day and original agreement end date of November 2017. If KEV exercises the option KEV would be required to make a rate recovery payment equal to the difference between the original day rate and the amended day rate multiplied by the number of days from the amendment effective date to the date the option is exercised plus certain administrative costs. 5 Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities including well commitments in our petroleum contracts. We currently have a commitment to drill one exploration well in Morocco and Senegal. In Morocco our partner is obligated to fund our share of the cost of the exploration well subject to a maximum spend of 120.0 million. Additionally we have 3D seismic requirements in Sao Tome and Morocco of 2750 square kilometers and 1200 square kilometers respectively. The following table presents maturities by expected debt maturity dates the weighted average interest rates expected to be paid on the Facility given current contractual terms and market conditions and the debts estimated fair value. Weighted-average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not take into account amortization of deferred financing costs. Liability Fair Value atYears Ending December 31 December 31 2016 2017 2018 2019 2020 Thereafter 2015 In thousands except percentages Fixed rate debt Senior Notes . . . . . . . . . . . . . . . . . 525000 423612 Fixed interest rate . . . . . . . . . . . . . 7.88 7.88 7.88 7.88 7.88 7.88 Variable rate debt Facility1 . . . . . . . . . . . . . . . . . . . 185714 214286 400000 Weighted average interest rate2 . . . 3.98 4.59 5.41 5.72 6.50 6.74 Interest rate swaps Notional debt amount3 . . . . . . . . . 12500 90 Average fixed rate payable . . . . . . 2.27 Variable rate receivable4 . . . . . . 0.83 Capped interest rate swaps Notional debt amount . . . . . . . . . . . 200000 200000 200000 406 Cap . . . . . . . . . . . . . . . . . . . . . 3.00 3.00 3.00 Average fixed rate payable5 . . . . 1.23 1.23 1.23 Variable rate receivable4 . . . . . . 0.69 1.27 1.70 1 The amounts included in the table represent principal maturities only. The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of December 31 2015. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of December 31 2015 there were no borrowings under the Corporate Revolver. 2 Based on outstanding borrowings as noted in 1 above and the LIBOR yield curves plus applicable margin at the reporting date. Excludes commitment fees related to the Facility and Corporate Revolver. 3 Represents weighted average notional contract amounts of interest rate derivatives. In the final year of maturity represents notional amount from January - June. 4 Based on implied forward rates in the yield curve at the reporting date. 5 We expect to pay the fixed rate if 1-month LIBOR is below the cap and pay the market rate less the spread between the cap and the fixed rate if LIBOR is above the cap net of the capped interest rate swaps. 96 Off-Balance Sheet Arrangements We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31 2015 our material off-balance sheet arrangements and transactions include operating leases and undrawn letters of credit. There are no other transactions arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect Kosmos liquidity or availability of or requirements for capital resources. Critical Accounting Policies This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets liabilities revenues and expenses as well as the disclosure of contingent assets and liabilities as of the date the financial statements are available to be issued. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates. Our significant accounting policies are detailed in Item 8. Financial Statements and Supplementary DataNote 2Accounting Policies. We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management. Revenue Recognition. We use the sales method of accounting for oil and gas revenues. Under this method we recognize revenues on the volumes sold based on the provisional sales prices. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31 2015 and 2014 we had no oil and gas imbalances recorded in our consolidated financial statements. Our oil and gas revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative which is not designated as a hedge for accounting purposes is marked to market through oil and gas revenue each period until the final settlement occurs which generally is limited to the month after the sale occurs. Exploration and Development Costs. We follow the successful efforts method of accounting for our oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs including geological and geophysical costs and costs of carrying unproved properties are charged to expense as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes the applicable costs are expensed. Costs incurred to drill and equip development wells including unsuccessful development wells are capitalized. Costs incurred to operate and maintain wells and equipment and to lift crude oil and natural gas to the surface are expensed. Receivables. Our receivables consist of joint interest billings oil sales and other receivables. For our oil sales receivable we require a letter of credit to be posted to secure the outstanding receivable. Receivables from joint interest owners are stated at amounts due net of any allowances for doubtful accounts. We determine our allowance by considering the length of time past due future net revenues of the debtors ownership interest in oil and natural gas properties we operate and the owners ability to pay its obligation among other things. 97 Income Taxes. We account for income taxes as required by the ASC 740Income Taxes ASC 740. We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal state and international tax returns are generally not prepared or filed before the consolidated financial statements are prepared therefore we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes tax credits and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further we must assess the likelihood that we will be able to realize or utilize our deferred tax assets. If realization is not more likely than not we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover which would result in no benefit for the deferred tax amounts. As of December 31 2015 and 2014 we have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. If our estimates and judgments regarding our ability to realize our deferred tax assets change the benefits associated with those deferred tax assets may increase or decrease in the period our estimates and judgments change. On a quarterly basis management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances if necessary. ASC 740 provides a more-likely-than-not standard in evaluating whether a valuation allowance is necessary after weighing all of the available evidence. When evaluating the need for a valuation allowance we consider all available positive and negative evidence including the following the status of our operations in the particular taxing jurisdiction including whether we have commenced production from a commercial discovery whether a commercial discovery has resulted in significant proved reserves that have been independently verified the amounts and history of taxable income or losses in a particular jurisdiction projections of future income including the sensitivity of such projections to changes in production volumes and prices the existence or lack thereof of statutory limitations on the period that net operating losses may be carried forward in a jurisdiction and the creation and timing of future income associated with the turnaround of deferred tax liabilities in excess of deferred tax assets. Derivative Instruments and Hedging Activities. We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of three-way collars put options call options and swaps. We also use interest rate derivative contracts to mitigate our exposure to interest rate fluctuations related to our long-term debt. Our derivative financial instruments are recorded on the balance sheet as either assets or a liabilities measured at fair value. We do not apply hedge accounting to our oil derivative contracts. Effective June 1 2010 we discontinued hedge accounting on our interest rate swap contracts and accordingly the changes in the fair value of the instruments are recognized in earnings in the period of change. The effective portions of the discontinued hedges as of May 31 2010 were included in accumulated other comprehensive income or loss AOCI in the equity section of the accompanying consolidated balance sheets and were transferred to earnings when the hedged transactions settled. Estimates of Proved Oil and Natural Gas Reserves. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude 98 oil natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the SEC and the FASB. The accuracy of these reserve estimates is a function of the engineering and geological interpretation of available data estimates of the amount and timing of future operating cost production taxes development cost and workover cost the accuracy of various mandated economic assumptions and the judgments of the persons preparing the estimates. Asset Retirement Obligations. We account for asset retirement obligations as required by the ASC 410Asset Retirement and Environmental Obligations. Under these standards the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long-lived asset with an existing asset retirement obligation is acquired a liability for that obligation shall be recognized at the assets acquisition date as if that obligation were incurred on that date. In addition a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long-lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion and depreciation in the consolidated statement of operations. Estimating the future restoration and removal costs requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Additionally asset removal technologies and costs are constantly changing as are regulatory political environmental safety and public relations considerations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts inflation factors credit adjusted discount rates timing of settlement and changes in the legal regulatory environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations a corresponding adjustment is made to the oil and gas property balance. Impairment of Long-Lived Assets. We review our long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. ASC 360 Property Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long-lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to us are recorded at the lower of carrying amount or fair value less cost to sell. We believe the assumptions used in our undiscounted cash flow analysis to test for impairment are appropriate and result in a reasonable estimate of future cash flows. The undiscounted cash flows from the analysis exceeded the carrying amount of our long-lived assets. The most significant assumptions are the pricing and production estimates used in undiscounted cash flow analysis. In order to evaluate 99 the sensitivity of the assumptions we assumed a hypothetical reduction in our production profile and lower pricing during the early years which still showed no impairment. If we experience further declines in oil pricing increases in our estimated future expenditures or a decrease in our estimated production profile our long-lived assets could be at risk for impairment. New Accounting Pronouncements In February 2015 the FASB issued ASU 2015-02 Consolidation Topic 810Amendments to the Consolidation Analysis. ASU 2015-02 modifies existing consolidation guidance related to limited partnerships and similar legal entities eliminates the presumption that a general partner should consolidate a limited partnership affects the consolidation analysis of reporting entities that are involved with Variable Interest Entities particularly those that have fee arrangements and related party relationships and provides a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. This guidance is effective for public companies for fiscal years beginning after December 15 2015 with early adoption permitted. The adoption of this standard is not expected to have a material impact on the Companys consolidated financial statements. In April 2015 the FASB issued ASU 2015-03 InterestImputation of Interest Subtopic 835-30Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 modifies existing guidance related to the presentation of debt issuance costs which are currently capitalized and presented on the balance sheet as an asset. ASU 2015-03 requires these costs to be presented as a direct deduction from the face amount of the related debt. In August 2015 the FASB issued ASU 2015-15 InterestImputation of Interest Subtopic 835-30Presentation and Subsequent Measurement of Debt Issuance Costs Associated with the Line-of-Credit Arrangements. ASU 2015-15 clarifies the guidance regarding line-of-credit arrangements with regards to the recently issued ASU 2015-03 to incorporate statements made by the SEC Staff during their June 18 2015 Emerging Issues Task Force meeting. The SEC Staff has clarified they would not object to an entity deferring and presenting debt issue costs as an asset and subsequently amortizing the deferred debt issue costs ratably over the term of the line-of-credit arrangement regardless of whether there are any outstanding borrowings on the line-of credit arrangement. This guidance is effective for public companies for fiscal years beginning after December 15 2015 with early adoption permitted. The Company early adopted ASU 2015-03 and ASU 2015-15 as of December 31 2015 and applied retrospectively for all periods presented. The adoption of this standard resulted in 39.3 million and 45.9 million of net deferred financing costs as of December 31 2015 and 2014 respectively being reclassified as a direct reduction of long-term debt on the balance sheet. In July 2015 the FASB issued ASU 2015-11 Inventory Topic 330Simplifying the Measurement of Inventory. ASU 2015-11 changes the measurement principle for entities that do not measure inventory using the last-in first-out LIFO or retail inventory method from the lower of cost or market to lower of cost and net realizable value. The ASU also eliminates the requirement for these entities to consider replacement cost or net realizable value less an approximately normal profit margin when measuring inventory. The ASU is effective for annual periods beginning after December 15 2016 and interim periods within those annual periods. The adoption of this standard is not expected to have a material impact on the Companys consolidated financial statements. In August 2015 the FASB issued ASU 2015-14 Revenue from Contracts with Customers Topic 606Deferral of the Effective Date. ASU 2015-14 defers the effective date of ASU 2014-09 by one year to annual reporting periods beginning after December 15 2017 with early adoption permitted for periods beginning after December 15 2016. The adoption of this standard is not expected to have a material impact on the Companys consolidated financial statements. 100 In November 2015 the FASB issued ASU 2015-17 Income Taxes Topic 740Balance Sheet Classification of Deferred Taxes. ASU 2015-17 eliminates the requirement to classify deferred tax assets and liabilities as current or long-term based on how the related assets or liabilities are classified. All deferred taxes are now required to be classified as long-term including any associated valuation allowances. This guidance is effective for public companies for fiscal years beginning after December 15 2016 with early adoption permitted on either a prospective or retrospective basis. The Company has early adopted this guidance as of December 31 2015 on a prospective basis and prior periods presented have not been retrospectively adjusted. Item 7A. Qualitative and Quantitative Disclosures About Market Risk The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term market risks as it relates to our currently anticipated transactions refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage ongoing market risk exposures. We enter into market-risk sensitive instruments for purposes other than to speculate. We manage market and counterparty credit risk in accordance with our policies. In accordance with these policies and guidelines our management determines the appropriate timing and extent of derivative transactions. See Item 8. Financial Statements and Supplementary DataNote 2 Accounting Policies Note 9Derivative Financial Information and Note 10Fair Value Measurements for a description of the accounting procedures we follow relative to our derivative financial instruments. The following table reconciles the changes that occurred in fair values of our open derivative contracts during the year ended December 31 2015 Derivative Contracts Assets Liabilities Commodities Interest Rates Total In thousands Fair value of contracts outstanding as of December 31 2014 . . . . . . . . . . . . . . . . . . 252485 789 251696 Changes in contract fair value . . . . . . . . . . . . 210652 462 210190 Contract maturities . . . . . . . . . . . . . . . . . . . . 225496 755 224741 Fair value of contracts outstanding as of December 31 2015 . . . . . . . . . . . . . . . . . . 237641 496 237145 Commodity Price Risk The Companys revenues earnings cash flows capital investments and ultimately future rate of growth are highly dependent on the prices we receive for our crude oil which have historically been very volatile. Our oil sales are indexed against Dated Brent crude. Oil prices in 2015 ranged between 35.64 and 66.65 during the year. In June 2014 Dated Brent crude peaked above 115 per barrel and as recently as January 2016 had fallen below 30 per barrel. Commodity Derivative Instruments We enter into various oil derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future oil production. These contracts currently consist of three-way collars put options call options and swaps. In regards to our obligations under our various commodity 101 derivative instruments if our production does not exceed our existing hedged positions our exposure to our commodity derivative instruments would increase. Commodity Price Sensitivity The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of December 31 2015 Weighted Average Dated Brent Price per Bbl Asset Liability Deferred Fair Value at Premium December 31 Term Type of Contract MBbl Payable Swap Put Floor Ceiling Call 20151 2016 JanuaryDecember . . Purchased puts 2000 3.41 85.00 81335 JanuaryDecember . . Three-way collars 2000 85.00 110.00 135.00 88074 JanuaryDecember . . Swaps with puts 2000 75.00 60.00 28595 2017 JanuaryDecember . . Swap with putscalls 2000 2.13 72.50 55.00 90.00 23157 JanuaryDecember . . Swap with puts 2000 64.95 50.00 17988 JanuaryDecember . . Sold calls2 2000 85.00 1176 2018 JanuaryDecember . . Three-way collars 913 2.37 45.00 60.00 75.00 2688 2019 JanuaryDecember . . Sold calls2 913 80.00 3020 1 Fair values are based on the average forward Dated Brent oil prices on December 31 2015 which by year are 201640.85 201747.70 201851.88 and 201953.27. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on February 16 2016 market quotes by year are 201634.56 201740.57 201844.25 and 201945.65. 2 Represents call option contracts sold to counterparties to enhance other derivative positions. In February 2016 we entered into three-way collar contracts for 2.0 MMBbl from January 2017 through December 2017 with a floor price of 45.00 per barrel a ceiling price of 60 per barrel and a sold put price of 30.00 per barrel. In addition we sold call contracts for 2.0 MMBbl from January 2018 through December 2018 with a strike price of 65.00 per barrel. The contracts are indexed to Dated Brent prices and have a weighted average deferred premium payable of 1.68 per barrel. At December 31 2015 our open commodity derivative instruments were in a net asset position of 237.6 million. As of December 31 2015 a hypothetical 10 price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately 32.0 million. Similarly a hypothetical 10 price decrease would increase future pre-tax earnings by approximately 27.5 million. Interest Rate Derivative Instruments See Item 7. Managements Discussion and Analysis of Financial Condition and Results of OperationsContractual Obligations for specific information regarding the terms of our interest rate derivative instruments that are sensitive to changes in interest rates. Interest Rate Sensitivity At December 31 2015 we had floating rate indebtedness outstanding under the Facility of 400.0 million of which 187.5 million bore interest at floating rates after consideration of our fixed rate interest rate hedges. The interest rate on this indebtedness as of December 31 2015 was approximately 3.7. If LIBOR increased 10 at this level of floating rate debt we would pay an additional 0.1 million in interest expense per year on the Facility. We paid commitment fees on the 102 1.1 billion of undrawn availability under the Facility and on the 400.0 million of undrawn availability under the Corporate Revolver during 2015 which are not subject to changes in interest rates. As of December 31 2015 the fair market value of our interest rate swaps was a net liability of approximately 0.5 million. If LIBOR increased by 10 we estimate it would have a negligible impact on the fair market value of our interest rate swaps. 103 Item 8. Financial Statements and Supplementary Data INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page Consolidated Financial Statements of Kosmos Energy Ltd. Reports of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . 105 Consolidated Balance Sheets as of December 31 2015 and 2014 . . . . . . . . . . . . . . . . . . . . . . . 107 Consolidated Statements of Operations for the years ended December 31 2015 2014 and 2013 108 Consolidated Statements of Comprehensive Income Loss for the years ended December 31 2015 2014 and 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Consolidated Statements of Shareholders Equity for the years ended December 31 2015 2014 and 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110 Consolidated Statements of Cash Flows for the years ended December 31 2015 2014 and 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112 Supplemental Oil and Gas Data Unaudited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 143 Supplemental Quarterly Financial Information Unaudited . . . . . . . . . . . . . . . . . . . . . . . . . . 148 104 Report of Independent Registered Public Accounting Firm The Board of Directors and Shareholders Kosmos Energy Ltd. We have audited the accompanying consolidated balance sheets of Kosmos Energy Ltd. as of December 31 2015 and 2014 and the related consolidated statements of operations comprehensive income loss shareholders equity and cash flows for each of the three years in the period ended December 31 2015. Our audits also included the financial statement schedules included at Item 15a. These financial statements and schedules are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining on a test basis evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion the financial statements referred to above present fairly in all material respects the consolidated financial position of Kosmos Energy Ltd. at December 31 2015 and 2014 and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31 2015 in conformity with U.S. generally accepted accounting principles. Also in our opinion the related financial statement schedules when considered in relation to the basic financial statements taken as a whole present fairly in all material respects the financial information set forth therein. As discussed in Note 2 to the consolidated financial statements Kosmos Energy Ltd. adopted FASB ASU 2015-03 Simplifying the Presentation of Debt Issuance Costs and FASB ASU 2015-17 Balance Sheet Classification of Deferred Taxes. We also have audited in accordance with the standards of the Public Company Accounting Oversight Board United States Kosmos Energy Ltd.s internal control over financial reporting as of December 31 2015 based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission 2013 framework and our report dated February 22 2016 expressed an unqualified opinion thereon. s Ernst Young LLP Dallas Texas February 22 2016 105 Report of Independent Registered Public Accounting Firm The Board of Directors and Shareholders Kosmos Energy Ltd. We have audited Kosmos Energy Ltd.s internal control over financial reporting as of December 31 2015 based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission 2013 framework the COSO criteria. Kosmos Energy Ltd.s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Managements Annual Report on Internal Control over Financial Reporting appearing in Item 9A. Our responsibility is to express an opinion on the companys internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting assessing the risk that a material weakness exists testing and evaluating the design and operating effectiveness of internal control based on the assessed risk and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that 1 pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company 2 provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company and 3 provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition use or disposition of the companys assets that could have a material effect on the financial statements. Because of its inherent limitations internal control over financial reporting may not prevent or detect misstatements. Also projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. In our opinion Kosmos Energy Ltd. maintained in all material respects effective internal control over financial reporting as of December 31 2015 based on the COSO criteria. We also have audited in accordance with the standards of the Public Company Accounting Oversight Board United States the consolidated balance sheets of Kosmos Energy Ltd. as of December 31 2015 and 2014 and the related consolidated statements of operations comprehensive income loss shareholders equity and cash flows for each of the three years in the period ended December 31 2015 of Kosmos Energy Ltd. and our report dated February 22 2016 expressed an unqualified opinion thereon. s Ernst Young LLP Dallas Texas February 22 2016 106 KOSMOS ENERGY LTD. CONSOLIDATED BALANCE SHEETS In thousands except share data December 31 2015 2014 Assets Current assets Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 275004 554831 Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28533 15926 Receivables Joint interest billings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67200 60592 Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35950 61731 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34882 41221 Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85173 55354 Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24766 25278 Deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32268 Derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182640 163275 Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 734148 1010476 Property and equipment Oil and gas properties net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2314226 1773186 Other property net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8613 11660 Property and equipment net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2322839 1784846 Other assets Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7325 16125 Long-term receivablesjoint interest billings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37687 14174 Deferred financing costs net of accumulated amortization of 8475 and 6404 at December 31 2015 and December 31 2014 respectively . . . . . . . . . . . . . . . . . . . . . 7986 2846 Long-term deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33209 9182 Derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59856 89210 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3203050 2926859 Liabilities and shareholders equity Current liabilities Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 295689 184400 Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159897 201967 Deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61683 Derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1155 721 Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 456741 448771 Long-term liabilities Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 860878 748362 Derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4196 68 Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43938 44023 Deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 502189 337961 Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9595 8715 Total long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1420796 1139129 Shareholders equity Preference shares 0.01 par value 200000000 authorized shares zero issued at December 31 2015 and December 31 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Common shares 0.01 par value 2000000000 authorized shares 393902643 and 392443048 issued at December 31 2015 and 2014 respectively . . . . . . . . . . . . . . . . . . 3939 3924 Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1933189 1860190 Accumulated deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 564686 494850 Accumulated other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 767 Treasury stock at cost 8812054 and 5555088 shares at December 31 2015 and 2014 respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46929 31072 Total shareholders equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1325513 1338959 Total liabilities and shareholders equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3203050 2926859 See accompanying notes. 107 KOSMOS ENERGY LTD. CONSOLIDATED STATEMENTS OF OPERATIONS In thousands except per share data Years Ended December 31 2015 2014 2013 Revenues and other income Oil and gas revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 446696 855877 851212 Gain on sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24651 23769 Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 209 3092 941 Total revenues and other income . . . . . . . . . . . . . . . . . . . . . . . 471556 882738 852153 Costs and expenses Oil and gas production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105336 100122 96791 Exploration expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156203 93519 230314 General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136809 135231 158421 Depletion and depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155966 198080 222544 Interest and other financing costs net . . . . . . . . . . . . . . . . . . . . 37209 45548 47590 Derivatives net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 210649 281853 17027 Restructuring charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11742 Other expenses net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5246 2081 3512 Total costs and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 386120 304470 776199 Income before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85436 578268 75954 Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155272 298898 166998 Net income loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69836 279370 91044 Net income loss per share Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.18 0.73 0.24 Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.18 0.72 0.24 Weighted average number of shares used to compute net income loss per share Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 382610 379195 376819 Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 382610 386119 376819 See accompanying notes. 108 KOSMOS ENERGY LTD. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME LOSS In thousands Years Ended December 31 2015 2014 2013 Net income loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69836 279370 91044 Other comprehensive loss Reclassification adjustments for derivative gains included in net income loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 767 1391 1527 Other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 767 1391 1527 Comprehensive income loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70603 277979 92571 See accompanying notes. 109 KOSMOS ENERGY LTD. CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY In thousands Accumulated Additional OtherCommon Shares Paid-in Accumulated Comprehensive Treasury Shares Amount Capital Deficit Income Stock Total Balance as of December 31 2012 . . . . . . . . . . . 391424 3914 1712880 683176 3685 8397 1028906 Equity-based compensation . . . . . . . . . . . . . 69101 69101 Derivatives net . . . . . . . . . . . . . . . . . . . . . 1527 1527 Restricted stock awards and units . . . . . . . . . 550 6 6 Restricted stock forfeitures . . . . . . . . . . . . . 6 6 Purchase of treasury stock . . . . . . . . . . . . . . 446 12655 13101 Net loss . . . . . . . . . . . . . . . . . . . . . . . . . 91044 91044 Balance as of December 31 2013 . . . . . . . . . . . 391974 3920 1781535 774220 2158 21058 992335 Equity-based compensation . . . . . . . . . . . . . 79741 79741 Derivatives net . . . . . . . . . . . . . . . . . . . . . 1391 1391 Restricted stock awards and units . . . . . . . . . 469 4 4 Restricted stock forfeitures . . . . . . . . . . . . . 2 2 Purchase of treasury stock . . . . . . . . . . . . . . 1084 10012 11096 Net income . . . . . . . . . . . . . . . . . . . . . . . 279370 279370 Balance as of December 31 2014 . . . . . . . . . . . 392443 3924 1860190 494850 767 31072 1338959 Equity-based compensation . . . . . . . . . . . . . 75267 75267 Derivatives net . . . . . . . . . . . . . . . . . . . . . 767 767 Restricted stock awards and units . . . . . . . . . 1460 15 15 Restricted stock forfeitures . . . . . . . . . . . . . 16 16 Purchase of treasury stock . . . . . . . . . . . . . . 2269 15841 18110 Net loss . . . . . . . . . . . . . . . . . . . . . . . . . 69836 69836 Balance as of December 31 2015 . . . . . . . . . . . 393903 3939 1933189 564686 46929 1325513 See accompanying notes. 110 KOSMOS ENERGY LTD. CONSOLIDATED STATEMENTS OF CASH FLOWS In thousands Years Ended December 31 2015 2014 2013 Operating activities Net income loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69836 279370 91044 Adjustments to reconcile net income loss to net cash provided by operating activities Depletion depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . 166290 208628 233598 Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110786 216409 82380 Unsuccessful well costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94910 1105 107565 Change in fair value of derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . 210957 271298 23093 Cash settlements on derivatives including 225.5 million 18.4 million and 22.3 million on commodity hedges during 2015 2014 and 2013 224741 4460 33411 Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75057 79541 69026 Gain on sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24651 23769 Loss on extinguishment of debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165 2898 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7875 3875 4916 Changes in assets and liabilities Increase decrease in receivables . . . . . . . . . . . . . . . . . . . . . . . . . . 2209 156192 111677 Increase in inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29855 8100 16763 Increase decrease in prepaid expenses and other . . . . . . . . . . . . . . 512 1732 16540 Increase decrease in accounts payable . . . . . . . . . . . . . . . . . . . . . . 111289 90228 34683 Increase decrease in accrued liabilities . . . . . . . . . . . . . . . . . . . . . 17756 22449 82590 Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . 440779 443586 522404 Investing activities Oil and gas assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 823642 424535 317413 Other property . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1483 2383 4970 Proceeds on sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28692 58315 Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3807 20924 1750 Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 800240 347679 324133 Financing activities Borrowings under long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100000 Payments on long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200000 400000 100000 Net proceeds from issuance of senior secured notes . . . . . . . . . . . . . . . . . . 206774 294000 Purchase of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18110 11096 13101 Deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9030 22088 2226 Net cash provided by used in financing activities . . . . . . . . . . . . . . . . . . . 79634 139184 115327 Net increase decrease in cash and cash equivalents . . . . . . . . . . . . . . . . . 279827 43277 82944 Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . . . 554831 598108 515164 Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . . . . 275004 554831 598108 Supplemental cash flow information Cash paid for Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33315 23182 36313 Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35857 108068 68437 See accompanying notes. 111 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements 1. Organization Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company Kosmos Energy Ltd.s management operations are conducted through a wholly owned subsidiary Kosmos Energy LLC. The terms Kosmos the Company we us our ours and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries unless the context indicates otherwise. Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margin. Our assets include existing production and development projects offshore Ghana large discoveries offshore Mauritania and Senegal as well as exploration licenses with significant hydrocarbon potential offshore Portugal Sao Tome and Principe Suriname Morocco and Western Sahara. Kosmos is listed on the New York Stock Exchange and is traded under the ticker symbol KOS. We have one reportable segment which is the exploration and production of oil and natural gas. Substantially all of our long-lived assets and product sales are related to production located offshore Ghana. 2. Accounting Policies Principles of Consolidation The accompanying consolidated financial statements include the accounts of Kosmos Energy Ltd. and its wholly owned subsidiaries. All intercompany transactions have been eliminated. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets liabilities revenues and expenses and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates. Reclassifications Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no material impact on our reported net income current assets total assets current liabilities total liabilities or shareholders equity except as disclosed related to the adoption of recent accounting pronouncements. Cash and Cash Equivalents Cash and cash equivalents includes demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. Restricted Cash In accordance with our commercial debt facility the Facility we are required to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.875 Senior Secured Notes due 2021 Senior Notes plus the Corporate Revolver or 112 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 2. Accounting Policies Continued the Facility whichever is greater. As of December 31 2015 and 2014 we had 24.4 million and 15.9 million respectively in current restricted cash to meet this requirement. In addition in accordance with certain of our petroleum contracts we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations andor entering into the next phase of the petroleum contract the requirement to post letters of credit will be satisfied and the cash collateral will be released. However additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of December 31 2015 and 2014 we had 4.1 million and zero respectively of short-term restricted cash and 7.3 million and 16.1 million respectively of long-term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts. Receivables Our receivables consist of joint interest billings oil sales and other receivables. For our oil sales receivable we require a letter of credit to be posted to secure the outstanding receivable. Receivables from joint interest owners are stated at amounts due net of any allowances for doubtful accounts. We determine our allowance by considering the length of time past due future net revenues of the debtors ownership interest in oil and natural gas properties we operate and the owners ability to pay its obligation among other things. We did not have any allowance for doubtful accounts as of December 31 2015 and 2014. Inventories Inventories consisted of 84.4 million and 55.3 million of materials and supplies and 0.8 million and 0.1 million of hydrocarbons as of December 31 2015 and 2014 respectively. The Companys materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost using the weighted average cost method or market. Hydrocarbon inventory is carried at the lower of cost using the weighted average cost method or market. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs. Exploration and Development Costs The Company follows the successful efforts method of accounting for its oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs including geological and geophysical costs and costs of carrying unproved properties are expensed as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes the applicable costs are expensed and recorded in exploration expense on the consolidated statement of operations. Costs incurred to drill and equip development wells including unsuccessful development wells are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed as oil and gas production expense. 113 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 2. Accounting Policies Continued The Company evaluates unproved property periodically for impairment. The impairment assessment considers results of exploration activities commodity price outlooks planned future sales or expiration of all or a portion of such projects. If the quantity of potential future reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project the Company will recognize an impairment loss at that time. Depletion Depreciation and Amortization Proved properties and support equipment and facilities are depleted using the unit-of-production method based on estimated proved oil and natural gas reserves. Capitalized exploratory drilling costs that result in a discovery of proved reserves and development costs are amortized using the unit-of-production method based on estimated proved developed oil and natural gas reserves for the related field. Depreciation and amortization of other property is computed using the straight-line method over the assets estimated useful lives not to exceed the lease term for leasehold improvements ranging from one to eight years. Years Depreciated Leasehold improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 to 8 Office furniture fixtures and computer equipment . . . . . . . . . . . . . . . . . 3 to 7 Vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Amortization of deferred financing costs is computed using the straight-line method over the life of the related debt. Capitalized Interest Interest costs from external borrowings are capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is depleted on the unit-of-production method in the same manner as the underlying assets. Asset Retirement Obligations The Company accounts for asset retirement obligations as required by ASC 410Asset Retirement and Environmental Obligations. Under these standards the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long-lived asset with an existing asset retirement obligation is acquired a liability for that obligation is recognized at the assets acquisition date. In addition a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long-lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion and depreciation in the consolidated statement of operations. 114 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 2. Accounting Policies Continued Impairment of Long-lived Assets The Company reviews its long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable or at least annually. ASC 360Property Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long-lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell. We believe the assumptions used in our undiscounted cash flow analysis to test for impairment are appropriate and result in a reasonable estimate of future cash flows. The undiscounted cash flows from the analysis exceeded the carrying amount of our long-lived assets. The most significant assumptions are the pricing and production estimates used in undiscounted cash flow analysis. In order to evaluate the sensitivity of the assumptions we assumed a hypothetical reduction in our production profile and lower pricing during the early years which still showed no impairment. If we experience further declines in oil pricing increases in our estimated future expenditures or a decrease in our estimated production profile our long-lived assets could be at risk for impairment. Derivative Instruments and Hedging Activities We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of three-way collars put options call options and swaps. We also use interest rate derivative contracts to mitigate our exposure to interest rate fluctuations related to our long-term debt. Our derivative financial instruments are recorded on the balance sheet as either assets or liabilities and are measured at fair value. We do not apply hedge accounting to our oil derivative contracts. Effective June 1 2010 we discontinued hedge accounting on our interest rate swap contracts. Therefore from that date forward the changes in the fair value of the instruments are recognized in earnings during the period of change. The effective portions of the discontinued hedges as of May 31 2010 were included in accumulated other comprehensive income or loss AOCI in the equity section of the accompanying consolidated balance sheets and were transferred to earnings when the hedged transactions settled. As of December 31 2015 all instruments previously designated as hedges have settled and there is no balance remaining in AOCI. See Note 9Derivative Financial Instruments. Estimates of Proved Oil and Natural Gas Reserves Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the Securities and 115 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 2. Accounting Policies Continued Exchange Commission SEC and the Financial Accounting Standards Board FASB. The accuracy of these reserve estimates is a function of the engineering and geological interpretation of available data estimates of the amount and timing of future operating cost production taxes development cost and workover cost the accuracy of various mandated economic assumptions and the judgments of the persons preparing the estimates. Revenue Recognition We use the sales method of accounting for oil and gas revenues. Under this method we recognize revenues on the volumes sold based on the provisional sales prices. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31 2015 and 2014 we had no oil and gas imbalances recorded in our consolidated financial statements. Our oil and gas revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative which is not designated as a hedge is marked to market through oil and gas revenue each period until the final settlement occurs which generally is limited to the month after the sale. Equity-based Compensation For equity-based compensation awards compensation expense is recognized in the Companys financial statements over the awards vesting periods based on their grant date fair value. The Company utilizes i the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards and restricted stock units and ii a Monte Carlo simulation to determine the fair value of restricted stock awards and restricted stock units with a combination of market and service vesting criteria. Restructuring Charges The Company accounts for restructuring charges in accordance with ASC 420-Exit or Disposal Cost Obligations. Under these standards the costs associated with restructuring charges are recorded during the period in which the liability is incurred. During the year ended December 31 2014 we recognized 11.7 million in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization which includes 5.0 million of accelerated non-cash expense related to awards previously granted under our Long-Term Incentive Plan the LTIP. Treasury Stock We record treasury stock purchases at cost. The majority of our treasury stock purchases are from our employees that surrendered shares to the Company to satisfy their minimum statutory tax 116 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 2. Accounting Policies Continued withholding requirements and were not part of a formal stock repurchase plan. The remainder of our treasury stock is forfeited restricted stock awards granted under our long-term incentive plan. Income Taxes The Company accounts for income taxes as required by ASC 740Income Taxes. Under this method deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances if necessary. We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. Accordingly we measure tax benefits from such positions based on the most likely outcome to be realized. Foreign Currency Translation The U.S. dollar is the functional currency for all of the Companys material foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are not significant and as such the effect of exchange rate changes is not material to any reporting period. Concentration of Credit Risk Our revenue can be materially affected by current economic conditions and the price of oil. However based on the current demand for crude oil and the fact that alternative purchasers are readily available we believe that the loss of our marketing agent andor any of the purchasers identified by our marketing agent would not have a long-term material adverse effect on our financial position or results of operations. Recent Accounting Standards In February 2015 the FASB issued ASU 2015-02 Consolidation Topic 810Amendments to the Consolidation Analysis. ASU 2015-02 modifies existing consolidation guidance related to limited partnerships and similar legal entities eliminates the presumption that a general partner should consolidate a limited partnership affects the consolidation analysis of reporting entities that are involved with Variable Interest Entities particularly those that have fee arrangements and related party relationships and provides a scope exception from consolidation guidance for reporting entities with interests in legal entities that are required to comply with or operate in accordance with requirements that are similar to those in Rule 2a-7 of the Investment Company Act of 1940 for registered money market funds. This guidance is effective for public companies for fiscal years beginning after December 15 2015 with early adoption permitted. The adoption of this standard is not expected to have a material impact on the Companys consolidated financial statements. 117 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 2. Accounting Policies Continued In April 2015 the FASB issued ASU 2015-03 InterestImputation of Interest Subtopic 835-30Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 modifies existing guidance related to the presentation of debt issuance costs which are currently capitalized and presented on the balance sheet as an asset. ASU 2015-03 requires these costs to be presented as a direct deduction from the face amount of the related debt. In August 2015 the FASB issued ASU 2015-15 InterestImputation of Interest Subtopic 835-30Presentation and Subsequent Measurement of Debt Issuance Costs Associated with the Line-of-Credit Arrangements. ASU 2015-15 clarifies the guidance regarding line-of-credit arrangements with regards to the recently issued ASU 2015-03 to incorporate statements made by the SEC Staff during their June 18 2015 Emerging Issues Task Force meeting. The SEC Staff has clarified they would not object to an entity deferring and presenting debt issue costs as an asset and subsequently amortizing the deferred debt issue costs ratably over the term of the line-of-credit arrangement regardless of whether there are any outstanding borrowings on the line-of credit arrangement. This guidance is effective for public companies for fiscal years beginning after December 15 2015 with early adoption permitted. The Company early adopted ASU 2015-03 and ASU 2015-15 as of December 31 2015 and applied retrospectively for all periods presented. The adoption of this standard resulted in 39.3 million and 45.9 million of net deferred financing costs as of December 31 2015 and 2014 respectively being reclassified as a direct reduction of long-term debt on the balance sheet. In July 2015 the FASB issued ASU 2015-11 Inventory Topic 330Simplifying the Measurement of Inventory. ASU 2015-11 changes the measurement principle for entities that do not measure inventory using the last-in first-out LIFO or retail inventory method from the lower of cost or market to lower of cost and net realizable value. The ASU also eliminates the requirement for these entities to consider replacement cost or net realizable value less an approximately normal profit margin when measuring inventory. The ASU is effective for annual periods beginning after December 15 2016 and interim periods within those annual periods. The adoption of this standard is not expected to have a material impact on the Companys consolidated financial statements. In August 2015 the FASB issued ASU 2015-14 Revenue from Contracts with Customers Topic 606Deferral of the Effective Date. ASU 2015-14 defers the effective date of ASU 2014-09 by one year to annual reporting periods beginning after December 15 2017 with early adoption permitted for periods beginning after December 15 2016. The adoption of this standard is not expected to have a material impact on the Companys consolidated financial statements. In November 2015 the FASB issued ASU 2015-17 Income Taxes Topic 740Balance Sheet Classification of Deferred Taxes. ASU 2015-17 eliminates the requirement to classify deferred tax assets and liabilities as current or long-term based on how the related assets or liabilities are classified. All deferred taxes are now required to be classified as long-term including any associated valuation allowances. This guidance is effective for public companies for fiscal years beginning after December 15 2016 with early adoption permitted on either a prospective or retrospective basis. The Company has early adopted this guidance as of December 31 2015 on a prospective basis and prior periods presented have not been retrospectively adjusted. Had we elected to adopt retrospectively the December 31 2014 balance sheet would have reflected 41.5 million and 399.6 million in long-term deferred tax assets and long-term deferred tax liabilities respectively and zero for current deferred tax assets and current deferred tax liabilities. 118 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 3. Acquisitions and Divestitures In the first quarter of 2014 we closed three farm-out agreements with BP Exploration Morocco Limited a wholly owned subsidiary of BP plc BP covering our three blocks in the Agadir Basin offshore Morocco. Under the terms of the agreements BP acquired a non-operating interest in each of the Essaouira Offshore Foum Assaka Offshore and Tarhazoute Offshore blocks. BP is obligated to fund Kosmos share of the cost of one exploration well in each of the three blocks subject to a maximum spend of 120.0 million per well and pay its proportionate share of any well costs above the maximum spend which included the FA-1 exploration well drilled during 2014. In the event a second exploration well is drilled in any block BP will pay 150 of its share of costs subject to a maximum spend of 120.0 million per well. The sales proceeds of the farm-outs were 56.9 million. After giving effect to these farm-outs our participating interests are 30.0 29.9 and 30.0 in the Essaouira Offshore Foum Assaka Offshore and Tarhazoute Offshore blocks respectively and we remain the operator. The proceeds on the sale of the interests exceeded our book basis in the assets resulting in a 23.8 million gain on the transaction. In the first quarter of 2014 we closed a farm-out agreement with Capricorn Exploration and Development Company Limited a wholly owned subsidiary of Cairn Energy PLC Cairn covering the Cap Boujdour Offshore block offshore Western Sahara. Under the terms of the agreement Cairn acquired a 20 non-operated interest in the exploration permits comprising the Cap Boujdour Offshore block. Under the terms of the agreement Cairn paid 150 of its share of costs of a 3D seismic survey capped at 25.0 million and the CB-1 exploration well capped at 100.0 million. Additionally Cairn paid 12.3 million towards our future costs. Cairn paid 1.5 million for their share of costs incurred from the effective date of the farm-out agreement through the closing date which was recorded as a reduction in our basis. After giving effect to the farm-out our participating interest in the Cap Boujdour Offshore block is 55.0 and we remain the operator. In August 2014 we entered into a farm-in agreement with Timis Corporation Limited Timis whereby we acquired a 60 participating interest and operatorship covering the Cayar Offshore Profond and Saint Louis Offshore Profond blocks offshore Senegal. As part of the agreement we carried the full costs of a 3D seismic program. Additionally we carried the full costs of the Guembeul-1 exploration well and will fund Timis share of the costs of a second contingent exploration well in either contract area subject to a maximum gross cost per well of 120.0 million should Kosmos elect to drill such well. We also retain the option to increase our equity to 65 in exchange for carrying the full cost of a third contingent exploration or appraisal well subject to a maximum gross cost of 120.0 million. In March 2015 we closed a farm-in agreement with Repsol Exploracion S.A. Repsol acquiring a non-operated interest in the Camarao Ameijoa Mexilhao and Ostra blocks in the Peniche Basin offshore Portugal. As part of the agreement we reimbursed a portion of Repsols previously incurred exploration costs as well as partially carried Repsols share of the costs of a planned 3D seismic program. After giving effect to the farm-in agreement our participating interest is 31 in each of the blocks. In March 2015 we closed a farm-out agreement with Chevron Corporation Chevron covering the C8 C12 and C13 petroleum contracts offshore Mauritania. Under the terms of the farm-out agreement Chevron acquired a 30 non-operated working interest in each of the contract areas. As partial consideration for the farm-out Chevron paid a disproportionate share of the costs of one exploration well the Marsouin-1 exploration well as well as its proportionate share of certain 119 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 3. Acquisitions and Divestitures Continued previously incurred exploration costs. The final allocation resulted in sales proceeds of 28.7 million which exceeded our book basis in the assets resulting in a 24.7 million gain on the transaction. As a further component of the consideration for the farm-out Chevron was required to make an election by February 1 2016 to either farm-in to the Tortue-1 exploration well by paying a disproportionate share of the costs incurred in drilling of the well or alternatively elect to not farm-in to the Tortue-1 exploration well and pay a disproportionate share of the costs of a second contingent exploration or appraisal well in the contract areas subject to maximum expenditure caps. Chevron failed to make this mandatory election by the required date. Consequently pursuant to the terms of the farm-out agreement Chevron has withdrawn from our Mauritania blocks. Subsequently Chevron requested that we engage in discussions related to the possible reinstatement of Chevrons interests in our Mauritania blocks and such discussions are ongoing. However if no such agreement is reached in these discussions Chevrons 30 non-operated participating interest will be reassigned to us subject to requisite government approvals and our participating interests in the Block C8 C12 and C13 petroleum contracts will be 90. In September 2015 we notified the government of Ireland and our partners that we are withdrawing from all of our blocks offshore Ireland. These blocks were acquired during 2013. In October 2015 we closed a sale and purchase agreement with ERHC Energy EEZ LDA whereby we acquired an 85 participating interest and operatorship in Block 11 offshore Sao Tome and Principe. The National Petroleum Agency Agencia Nacional Do Petroleo De Sao Tome E Prncipe ANP has a 15 carried interest. In November 2015 we closed a farm-in agreement with Galp Energia Sao Tome E Principe Unipessoal LDA Galp a wholly owned subsidiary of Petrogal S.A. to acquire a 45 non-operated participating interest in Block 6 offshore Sao Tome and Principe. In January 2016 we closed a farm-in agreement with Equator an affiliate of Oando for Block 5 offshore Sao Tome and Principe whereby we acquired a 65 participating interest and operatorship in the block. Certain governmental approvals and processes are still required to be completed before this acquisition is effective. 4. Joint Interest Billings The Companys joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur. In 2014 the Ghana National Petroleum Corporation GNPC notified us and our block partners that it would exercise its right for the contractor group to pay its 5 share of the Tweneboa Enyenra and Ntomme TEN development costs. The block partners will be reimbursed for such costs plus interest out of a portion of GNPCs TEN production revenues under the terms of the Deepwater Tano DT petroleum contract. As of December 31 2015 and 2014 the joint interest billing receivables due from GNPC for the TEN development costs were 35.3 million and 14.2 million respectively which were classified as long-term on the consolidated balance sheets. 120 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 5. Property and Equipment Property and equipment is stated at cost and consisted of the following December 31 2015 2014 In thousands Oil and gas properties Proved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1337215 1156868 Unproved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . 593510 363717 Support equipment and facilities . . . . . . . . . . . . . . . . . . 1241943 968722 Total oil and gas properties . . . . . . . . . . . . . . . . . . . . 3172668 2489307 Accumulated depletion . . . . . . . . . . . . . . . . . . . . . . . . . 858442 716121 Oil and gas properties net . . . . . . . . . . . . . . . . . . . . . . . . 2314226 1773186 Other property . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34807 33718 Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . 26194 22058 Other property net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8613 11660 Property and equipment net . . . . . . . . . . . . . . . . . . . . . . . 2322839 1784846 We recorded depletion expense of 146.6 million 188.3 million and 213.7 million for the years ended December 31 2015 2014 and 2013 respectively. 6. Suspended Well Costs The Company capitalizes exploratory well costs as unproved properties within oil and gas properties until a determination is made that the well has either found proved reserves or is impaired. If proved reserves are found the capitalized exploratory well costs are reclassified to proved properties. Well costs are charged to exploration expense if the exploratory well is determined to be impaired. The following table reflects the Companys capitalized exploratory well costs on completed wells as of and during the years ended December 31 2015 2014 and 2013. The table excludes 70.3 million 1.1 million and 78.5 million in costs that were capitalized and subsequently expensed during the same year for the years ended December 31 2015 2014 and 2013 respectively. During 2014 the exploratory well costs associated with the TEN development were reclassified to proved property. Years Ended December 31 2015 2014 2013 In thousands Beginning balance . . . . . . . . . . . . . . . . . . . . . . . . 226714 376166 372492 Additions to capitalized exploratory well costs pending the determination of proved reserves . . 223542 71039 32804 Reclassification due to determination of proved reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 220491 Capitalized exploratory well costs charged to expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23375 29130 Ending balance . . . . . . . . . . . . . . . . . . . . . . . . . . 426881 226714 376166 121 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 6. Suspended Well Costs Continued The following table provides aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling Years Ended December 31 2015 2014 2013 In thousands except well counts Exploratory well costs capitalized for a period of one year or less . . . . . . . . . . . . . . . . . . . . . . . . . 199486 16814 11426 Exploratory well costs capitalized for a period of one to two years . . . . . . . . . . . . . . . . . . . . . . . . 17702 40865 229140 Exploratory well costs capitalized for a period of three to six years . . . . . . . . . . . . . . . . . . . . . . . . 209693 169035 135600 Ending balance . . . . . . . . . . . . . . . . . . . . . . . . . . . 426881 226714 376166 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year . . . . . . . . . . . . . . . . . . . . . . . . . . 3 5 8 As of December 31 2015 the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to Mahogany Teak formerly Teak-1 and Teak-2 and Akasa discoveries in the West Cape Three Points WCTP Block and the Wawa discovery in the DT Block which are all in Ghana. Mahogany and Teak DiscoveriesIn November 2015 we signed the Jubilee Field Unit Expansion Agreement with our partners to allow for the development of the Mahogany and Teak discoveries through the Jubilee FPSO and infrastructure. The expansion of the Jubilee Unit becomes effective upon approval by Ghanas Ministry of Petroleum of the Greater Jubilee Full Field Development Plan GJFFDP which was submitted to the government of Ghana in December 2015. The GJFFDP encompasses future development of the Jubilee Field in addition to future development of the Mahogany and Teak discoveries which were declared commercial during 2015. We are currently in discussions with the government of Ghana concerning the GJFFDP. Upon approval of the GJFFDP by the Ministry of Petroleum the Jubilee Unit will be expanded to include the Mahogany and Teak discoveries and revenues and expenses associated with these discoveries will be at the Jubilee Unit interests. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow after approval of the GJFFDP by Ghanas Ministry of Petroleum. Akasa DiscoveryWe are currently in discussions with the government of Ghana regarding additional technical studies and evaluation that we want to conduct before we are able to make a determination regarding commerciality of the discovery. If we determine the discovery to be commercial a declaration of commerciality would be provided and a PoD would be prepared and submitted to Ghanas Ministry of Petroleum as required under the WCTP petroleum contract. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow after approval of the GJFFDP by Ghanas Ministry of Petroleum. 122 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 6. Suspended Well Costs Continued Wawa DiscoveryIn April 2015 the Special Chamber of the International Tribunal of the Law of the Sea ITLOS issued an order in response to the provisional measures sought by the government of Cote dIvoire in its pending maritime boundary dispute with the government of Ghana. ITLOS rejected the request that Ghana suspend all ongoing exploration and development operations in the disputed area in which the Wawa Discovery is situated until ITLOS gives its decision on the maritime boundary dispute which is expected by late 2017. ITLOS did order Ghana to suspend new drilling in the disputed area. We plan to discuss with the government of Ghana the effects of the ITLOS order on the proposed Wawa appraisal activities so that we can more clearly define our future plans and corresponding timeline. In the meantime we continue to reprocess seismic data and have acquired a high resolution seismic survey over the discovery area. Following additional evaluation and potential appraisal activities a decision regarding commerciality of the Wawa discovery will be made by the DT Block partners. Under the petroleum contract we currently have until May 2016 to make a decision regarding a declaration of commerciality. Within nine months of a declaration of commerciality a PoD would be prepared and submitted to Ghanas Ministry of Petroleum as required under the DT petroleum contract. 7. Accrued Liabilities Accrued liabilities consisted of the following December 31 2015 2014 In thousands Accrued liabilities Exploration development and production . . . . . . . . . . . . . . 111064 139393 General and administrative expenses . . . . . . . . . . . . . . . . . . 24839 21926 Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17512 10271 Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3418 9233 Taxes other than income . . . . . . . . . . . . . . . . . . . . . . . . . . 3064 20315 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 829 159897 201967 8. Debt Debt consisted of the following December 31 2015 2014 In thousands Outstanding debt principal balances Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 400000 500000 Senior Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 525000 300000 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 925000 800000 Unamortized issuance costs and discounts . . . . . . . . . . . . . . . 64122 51638 Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 860878 748362 123 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 8. Debt Continued Facility In March 2014 the Company amended and restated the Facility with a total commitment of 1.5 billion from a number of financial institutions. The Facility supports our oil and gas exploration appraisal and development programs and corporate activities. As part of the debt refinancing in March 2014 the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt and existing unamortized debt issuance costs attributable to those participants were expensed. As a result we recorded a 2.9 million loss on the extinguishment of debt. As of December 31 2015 we have 37.5 million of unamortized issuance costs related to the Facility which will be amortized over the remaining term of the Facility including certain costs related to the amendment. As of December 31 2015 borrowings under the Facility totaled 400.0 million and the undrawn availability under the Facility was 1.1 billion. Interest is the aggregate of the applicable margin 3.25 to 4.50 depending on the length of time that has passed from the date the Facility was entered into LIBOR and mandatory cost if any as defined in the Facility. Interest is payable on the last day of each interest period and if the interest period is longer than six months on the dates falling at six-month intervals after the first day of the interest period. We pay commitment fees on the undrawn and unavailable portion of the total commitments if any. Commitment fees are equal to 40 per annum of the then-applicable respective margin when a commitment is available for utilization and equal to 20 per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835Interest which requires interest expense to be recognized using the effective interest method. We determined the effective interest rate based on the estimated level of borrowings under the Facility. As part of the March 2014 amendment the Facilitys estimated effective interest rate was changed and accordingly we adjusted our estimate of deferred interest previously recorded during prior years by 4.5 million which was recorded as a reduction to interest expense for the year ended December 31 2014. The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving- credit facility as amended in March 2014 expires on March 31 2018 however the Facility has a revolving-credit sublimit which will be the lesser of 500.0 million and the total available facility at that time that will be available for drawing until the date falling one month prior to the final maturity date. The letter of credit sublimit expires on the final maturity date. The available facility amount is subject to borrowing base constraints and beginning on March 31 2018 outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31 2021. As of December 31 2015 we had no letters of credit issued under the Facility. Kosmos has the right to cancel all the undrawn commitments under the Facility. The amount of funds available to be borrowed under the Facility also known as the borrowing base amount is determined each year on March 31 and September 30. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets reserves andor resources in Ghana. If an event of default exists under the Facility the lenders can accelerate the maturity and exercise other rights and remedies including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. The Facility contains customary cross default provisions. 124 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 8. Debt Continued We were in compliance with the financial covenants contained in the Facility as of the September 30 2015 the most recent assessment date. Corporate Revolver In November 2012 we secured a Corporate Revolver from a number of financial institutions which as amended in June 2015 has an availability of 400.0 million. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration appraisal and development programs. As of December 31 2015 we have 8.0 million of net deferred financing costs related to the Corporate Revolver which will be amortized over the remaining term which as amended expires in November 2018. As of December 31 2015 there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was 400.0 million. Interest is the aggregate of the applicable margin 6.0 LIBOR and mandatory cost if any as defined in the Corporate Revolver. Interest is payable on the last day of each interest period and if the interest period is longer than six months on the dates falling at six-month intervals after the first day of the interest period. We pay commitment fees on the undrawn portion of the total commitments. Commitment fees as amended in June 2015 for the lenders are equal to 30 per annum of the respective margin when a commitment is available for utilization. The Corporate Revolver as amended in June 2015 expires on November 23 2018. The available amount is not subject to borrowing base constraints. Kosmos has the right to cancel all the undrawn commitments under the Corporate Revolver. The Company is required to repay certain amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default exists under the Corporate Revolver the lenders can accelerate the maturity and exercise other rights and remedies including the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us. We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30 2015 the most recent assessment date. The Corporate Revolver contains customary cross default provisions. Revolving Letter of Credit Facility In July 2013 we entered into a revolving letter of credit facility agreement LC Facility. The size of the LC Facility is 75.0 million as amended in July 2015 with additional commitments up to 50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. The LC Facility provides that we maintain cash collateral in an amount equal to at least 75 of all outstanding letters of credit under the LC Facility provided that during the period of any breach of certain financial covenants the required cash collateral amount shall increase to 100. The fees associated with outstanding letters of credit issued will be 0.5 per annum. The LC Facility has an availability period which expires on June 1 2016. We may voluntarily cancel any commitments available under the LC Facility at any time. As of December 31 2015 there were nine outstanding letters of credit totaling 15.3 million under the LC Facility. The LC Facility contains customary cross default provisions. 125 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 8. Debt Continued 7.875 Senior Secured Notes due 2021 During August 2014 the Company issued 300.0 million of Senior Notes and received net proceeds of approximately 292.5 million after deducting discounts commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. During April 2015 we issued an additional 225.0 million of Senior Notes and received net proceeds of 206.8 million after deducting discounts commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional 225.0 million of Senior Notes have identical terms to the initial 300.0 million Senior Notes other than the date of issue the initial price the first interest payment date and the first date from which interest accrued. The Senior Notes mature on August 1 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1 2015 for the initial 300.0 million Senior Notes and August 1 2015 for the additional 225.0 million Senior Notes. The Senior Notes are secured subject to certain exceptions and permitted liens by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver and in certain circumstances the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries the Guarantees. Redemption and Repurchase. At any time prior to August 1 2017 and subject to certain conditions the Company may on any one or more occasions redeem up to 35 of the aggregate principal amount of Senior Notes issued under the indenture dated August 1 2014 related to the Senior Notes the Indenture at a redemption price of 107.875 plus accrued and unpaid interest with the cash proceeds of certain eligible equity offerings. Additionally at any time prior to August 1 2017 the Company may on any one or more occasions redeem all or a part of the Senior Notes at a redemption price equal to 100 plus any accrued and unpaid interest and a make-whole premium. On or after August 1 2017 the Company may redeem all or a part of the Senior Notes at the redemption prices expressed as percentages of principal amount set forth below plus accrued and unpaid interest Year Percentage On or after August 1 2017 but before August 1 2018 . . . . . . . . . . . . . . . 103.9 On or after August 1 2018 but before August 1 2019 . . . . . . . . . . . . . . . 102.0 On or after August 1 2019 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . 100.0 We may also redeem the Senior Notes in whole but not in part at any time if changes in tax laws impose certain withholding taxes on amounts payable on the Senior Notes at a price equal to the principal amount of the Senior Notes plus accrued interest and additional amounts if any as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted. Upon the occurrence of a change of control triggering event as defined under the Indenture the Company will be required to make an offer to repurchase the Senior Notes at a repurchase price equal 126 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 8. Debt Continued to 101 of the principal amount plus accrued and unpaid interest to but excluding the date of repurchase. If we sell assets under certain circumstances outlined in the Indenture we will be required to use the net proceeds to make an offer to purchase the Senior Notes at an offer price in cash in an amount equal to 100 of the principal amount of the Senior Notes plus accrued and unpaid interest to but excluding the repurchase date. Covenants. The Indenture restricts our ability and the ability of our restricted subsidiaries to among other things incur or guarantee additional indebtedness create liens pay dividends or make distributions in respect of capital stock purchase or redeem capital stock make investments or certain other restricted payments sell assets enter into agreements that restrict the ability of our subsidiaries to make dividends or other payments to us enter into transactions with affiliates or effect certain consolidations mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the Senior Notes are assigned an investment grade rating by both Standard Poors Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing. Collateral. The Senior Notes are secured subject to certain exceptions and permitted liens by a first ranking fixed equitable charge on all currently outstanding shares additional shares dividends or other distributions paid in respect of such shares or any other property derived from such shares in each case held by us in relation to the Companys direct subsidiary Kosmos Energy Holdings pursuant to the terms of the Charge over Shares of Kosmos Energy Holdings dated November 23 2012 as amended and restated on March 14 2014 between the Company and BNP Paribas as Security and Intercreditor Agent. The Senior Notes share pari passu in the benefit of such equitable charge based on the respective amounts of the obligations under the Indenture and the amount of obligations under the Corporate Revolver. The Guarantees are not secured. At December 31 2015 the estimated repayments of debt during the five years and thereafter are as follows Payments Due by Year 2016 2017 2018 2019 2020 Thereafter In thousands Principal debt repayments1 . . . . . 185714 739286 1 Includes the scheduled principal maturities for the 525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the estimated future available borrowing base as of December 31 2015. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of December 31 2015 there were no borrowings under the Corporate Revolver. 127 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 8. Debt Continued Interest and other financing costs net Interest and other financing costs net incurred during the period comprised of the following Years Ended December 31 2015 2014 2013 In thousands Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . 74897 57876 49317 Amortizationdeferred financing costs . . . . . . . . . . 10324 10548 11054 Loss on extinguishment of debt . . . . . . . . . . . . . . . 165 2898 Capitalized interest . . . . . . . . . . . . . . . . . . . . . . . . 52392 20577 13074 Deferred interest . . . . . . . . . . . . . . . . . . . . . . . . . . 1770 3562 1658 Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . 844 529 275 Other net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3289 1106 1090 Interest and other financing costs net . . . . . . . . . 37209 45548 47590 9. Derivative Financial Instruments We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes. We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of nonperformance risk in the fair value measurement of our derivative contracts as required by ASC 820Fair Value Measurements and Disclosures. 128 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 9. Derivative Financial Instruments Continued Oil Derivative Contracts The following table sets forth the volumes in barrels underlying the Companys outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of December 31 2015. Weighted Average Dated Brent Price per Bbl Net Deferred Premium Term Type of Contract MBbl Payable Swap Put Floor Ceiling Call 2016 JanuaryDecember . . . . Purchased puts 2000 3.41 85.00 JanuaryDecember . . . . Three-way collars 2000 85.00 110.00 135.00 JanuaryDecember . . . . Swaps with puts 2000 75.00 60.00 2017 JanuaryDecember . . . . Swap with putscalls 2000 2.13 72.50 55.00 90.00 JanuaryDecember . . . . Swap with puts 2000 64.95 50.00 JanuaryDecember . . . . Sold calls1 2000 85.00 2018 JanuaryDecember . . . . Three-way collars 913 2.37 45.00 60.00 75.00 2019 JanuaryDecember . . . . Sold calls1 913 80.00 1 Represents call option contracts sold to counterparties to enhance other derivative positions. In February 2016 we entered into three-way collar contracts for 2.0 MMBbl from January 2017 through December 2017 with a floor price of 45.00 per barrel a ceiling price of 60 per barrel and a sold put price of 30.00 per barrel. In addition we sold call contracts for 2.0 MMBbl from January 2018 through December 2018 with a strike price of 65.00 per barrel. The contracts are indexed to Dated Brent prices and have a weighted average deferred premium payable of 1.68 per barrel. Interest Rate Derivative Contracts The following table summarizes our open interest rate swaps whereby we pay a fixed rate of interest and the counterparty pays a variable LIBOR-based rate and our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap and pay the market rate less the spread between the cap sold call and the fixed rate of interest if LIBOR is above the cap as of December 31 2015 Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call In thousands January 2016June 2016 . . . . . . . . Swap 6-month LIBOR 12500 2.27 January 2016December 2018 . . . . Capped swap 1-month LIBOR 200000 1.23 3.00 129 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 9. Derivative Financial Instruments Continued Effective June 1 2010 we discontinued hedge accounting on all interest rate derivative instruments. Therefore from that date forward changes in the fair value of the instruments have been recognized in earnings during the period of change. The effective portions of the discontinued hedges as of May 31 2010 were included in AOCI in the equity section of the accompanying consolidated balance sheets and were transferred to earnings when the hedged transaction settled. As of December 31 2015 all instruments previously designated as hedges have settled and there is no balance remaining in AOCI. See Note 10Fair Value Measurements for additional information regarding the Companys derivative instruments. The following tables disclose the Companys derivative instruments as of December 31 2015 and 2014 and gainloss from derivatives during the years ended December 31 2015 2014 and 2013 Estimated Fair Value Asset Liability December 31 Type of Contract Balance Sheet Location 2015 2014 In thousands Derivatives not designated as hedging instruments Derivative assets Commodity1 . . . . . . . . . . . . . . . . . . . . Derivatives assetscurrent 182640 163275 Commodity2 . . . . . . . . . . . . . . . . . . . . Derivatives assetslong-term 59197 89210 Interest rate . . . . . . . . . . . . . . . . . . . . . Derivatives assetslong-term 659 Derivative liabilities Interest rate . . . . . . . . . . . . . . . . . . . . . Derivatives liabilitiescurrent 1155 721 Commodity . . . . . . . . . . . . . . . . . . . . . . Derivatives liabilitieslong-term 4196 Interest rate . . . . . . . . . . . . . . . . . . . . . Derivatives liabilitieslong-term 68 Total derivatives not designated as hedging instruments . . . . . . . . . . . . 237145 251696 1 Includes net deferred premiums payable of 6.2 million and 1.8 million related to commodity derivative contracts as of December 31 2015 and 2014 respectively. 2 Includes net deferred premiums payable of 6.9 million related to commodity derivative contracts as of December 31 2015 and 2014. 130 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 9. Derivative Financial Instruments Continued Amount of GainLoss Years Ended December 31 Type of Contract Location of GainLoss 2015 2014 2013 In thousands Derivatives in cash flow hedging relationships Interest rate1 . . . . . . . . . . . . . . . . . . . . . . Interest expense 767 1391 1527 Total derivatives in cash flow hedging relationships . . . . . . . . . . . . . . . . . . . . . 767 1391 1527 Derivatives not designated as hedging instruments Commodity2 . . . . . . . . . . . . . . . . . . . . . . Oil and gas revenue 3 11661 7156 Commodity . . . . . . . . . . . . . . . . . . . . . . . . . Derivatives net 210649 281853 17027 Interest rate . . . . . . . . . . . . . . . . . . . . . . . . Interest expense 462 285 437 Total derivatives not designated as hedging instruments . . . . . . . . . . . . . . . . . . . . . 210190 269907 24620 1 Amounts were reclassified from AOCI into earnings upon settlement. 2 Amounts represent the change in fair value of our provisional oil sales contracts. Offsetting of Derivative Assets and Derivative Liabilities Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of December 31 2015 and 2014 there was not an event of default and therefore the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets. Additionally if an event of default occurred the offsetting amounts would be immaterial as of December 31 2015 and 2014. 10. Fair Value Measurements In accordance with ASC 820Fair Value Measurements and Disclosures fair value measurements are based upon inputs that market participants use in pricing an asset or liability which are classified into two categories observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources whereas unobservable inputs reflect a companys own market assumptions which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy Level 1quoted prices for identical assets or liabilities in active markets. Level 2quoted prices for similar assets or liabilities in active markets quoted prices for identical or similar assets or liabilities in markets that are not active inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means. 131 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 10. Fair Value Measurements Continued Level 3unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following tables present the Companys assets and liabilities that are measured at fair value on a recurring basis as of December 31 2015 and 2014 for each fair value hierarchy level Fair Value Measurements Using Quoted Prices in Active Markets for Significant Other Significant Identical Assets Observable Inputs Unobservable Inputs Level 1 Level 2 Level 3 Total In thousands December 31 2015 Assets Commodity derivatives . . . . . . . . . 241837 241837 Interest rate derivatives . . . . . . . . . 659 659 Liabilities Commodity derivatives . . . . . . . . . 4196 4196 Interest rate derivatives . . . . . . . . . 1155 1155 Total . . . . . . . . . . . . . . . . . . . . . 237145 237145 December 31 2014 Assets Commodity derivatives . . . . . . . . . 252485 252485 Liabilities Interest rate derivatives . . . . . . . . . 789 789 Total . . . . . . . . . . . . . . . . . . . . . 251696 251696 The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings oil sales and other receivables and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables if any after any allowances for doubtful accounts approximate fair value. The estimates of fair value of these items are based on Level 2 inputs. Commodity Derivatives Our commodity derivatives represent crude oil three-way collars put options call options and swaps for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to our oil derivatives are based on i the contracted notional volumes ii independent active futures price quotes for Dated Brent iii a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap CDS market and iv an independently sourced estimate of volatility for Dated Brent. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 9Derivative Financial Instruments for additional information regarding the Companys derivative instruments. 132 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 10. Fair Value Measurements Continued Provisional Oil Sales The value attributable to the provisional oil sales derivative is based on i the sales volumes and ii the difference in the independent active futures price quotes for Dated Brent over the term of the pricing period designated in the sales contract and the spot price on the lifting date. Interest Rate Derivatives We have interest rate swaps whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate. We also have capped interest rate swaps whereby the Company pays a fixed rate of interest if LIBOR is below the cap and pays the market rate less the spread between the cap and the fixed rate of interest if LIBOR is above the cap. The values attributable to the Companys interest rate derivative contracts are based on i the contracted notional amounts ii LIBOR yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR yield curves and iii a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market. Debt The following table presents the carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets December 31 2015 December 31 2014 Carrying Fair Carrying Fair Value Value Value Value In thousands Long-term debt . . . . . . . . . . . . . . . . . . 900186 823612 794269 755000 The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods. The carrying value of long-term debt represents the principal amounts outstanding and does not include any unamortized issuance costs. The fair value of our Senior Notes is based on quoted market prices which results in a Level 1 fair value measurement. 11. Asset Retirement Obligations The following table summarizes the changes in the Companys asset retirement obligations December 31 2015 2014 In thousands Asset retirement obligations Beginning asset retirement obligations . . . . . . . . . . . . . . . . . . 44023 39596 Liabilities incurred during period . . . . . . . . . . . . . . . . . . . . . . 3818 Revisions in estimated retirement obligations . . . . . . . . . . . . . 9023 Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5120 4427 Ending asset retirement obligations . . . . . . . . . . . . . . . . . . . . 43938 44023 133 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 11. Asset Retirement Obligations Continued The Ghanaian legal and regulatory regime regarding oil field abandonment and other environmental matters is evolving. Currently no Ghanaian environmental regulations expressly require that companies abandon or remove offshore assets. Under the Environmental Permit for the Jubilee Field a decommissioning plan will be prepared and submitted to the Ghana Environmental Protection Agency. ASC 410Asset Retirement and Environmental Obligations requires the Company to recognize this liability in the period in which the liability was incurred. We have recorded an asset retirement obligation for fields that have commenced production. Additional asset retirement obligations will be recorded in the period in which wells within such producing fields are commissioned. 12. Equity-based Compensation Restricted Stock Awards and Restricted Stock Units Prior to our corporate reorganization Kosmos Energy Holdings issued common units designated as profit units with a threshold value ranging from 0.85 to 90 to employees management and directors. Profit units were equity awards that were measured on the grant date and expensed over a vesting period of four years. Founding management and directors vested 20 as of the date of issuance and an additional 20 on the anniversary date for each of the next four years. Profit units issued to employees vested 50 on the second and fourth anniversaries of the issuance date. As part of the corporate reorganization in May 2011 vested profit units were exchanged for 31.7 million common shares of Kosmos Energy Ltd. unvested profit units were exchanged for 10.0 million restricted stock awards and the 90 profit units were cancelled. Based on the terms and conditions of the corporate reorganization the exchange of profit units for common shares of Kosmos Energy Ltd. resulted in no incremental compensation costs. In April 2011 the Board of Directors approved the LTIP which provides for the granting of incentive awards in the form of stock options stock appreciation rights restricted stock awards restricted stock units among other award types. In January 2015 the board of directors approved an amendment to the plan to add 15.0 million shares to the plan which was approved at the Annual General Meeting in June 2015. The LTIP provides for the issuance of 39.5 million shares pursuant to awards under the plan in addition to the 10.0 million restricted stock awards exchanged for unvested profit units. As of December 31 2015 the Company had approximately 11.8 million shares that remain available for issuance under the LTIP. We record compensation expense equal to the fair value of share-based payments over the vesting periods of the LTIP awards. We recorded compensation expense from awards granted under our LTIP of 75.1 million 74.5 million and 69.0 million during the years ended December 31 2015 2014 and 2013 respectively. During the year ended December 31 2014 an additional 5.0 million of equity- based compensation was recorded as restructuring charges. The total tax benefit for the years ended December 31 2015 2014 and 2013 was 25.7 million 25.7 million and 23.5 million respectively. We expensed a tax shortfall related to equity-based compensation of 18.6 million 6.5 million and 7.0 million for the years ended December 31 2015 2014 and 2013 respectively. The fair value of awards vested during 2015 2014 and 2013 was approximately 52.2 million 37.0 million and 41.1 million respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service vesting criteria under the LTIP. Substantially all of these awards vest over three or four year periods. Restricted stock awards are issued and included in the number of 134 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 12. Equity-based Compensation Continued outstanding shares upon the date of grant and if such awards are forfeited they become treasury stock. Upon vesting restricted stock units become issued and outstanding stock. The following table reflects the outstanding restricted stock awards as of December 31 2015 Weighted- Market Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Awards Fair Value Awards Fair Value In thousands In thousands Outstanding at December 31 2012 . . . . 9898 16.92 3534 12.93 Granted . . . . . . . . . . . . . . . . . . . . . . 351 10.73 Forfeited . . . . . . . . . . . . . . . . . . . . . 462 16.51 96 12.35 Vested . . . . . . . . . . . . . . . . . . . . . . . 3403 17.18 Outstanding at December 31 2013 . . . . 6384 16.48 3438 12.95 Granted . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . 122 15.20 77 10.74 Vested . . . . . . . . . . . . . . . . . . . . . . . 3022 16.02 Outstanding at December 31 2014 . . . . 3240 16.95 3361 13.00 Granted . . . . . . . . . . . . . . . . . . . . . . 660 8.64 Forfeited . . . . . . . . . . . . . . . . . . . . . 2 12.84 1554 13.29 Vested . . . . . . . . . . . . . . . . . . . . . . . 3088 17.21 1546 13.30 Outstanding at December 31 2015 . . . . 810 9.20 261 9.44 The following table reflects the outstanding restricted stock units as of December 31 2015 Weighted- Market Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Units Fair Value Units Fair Value In thousands In thousands Outstanding at December 31 2012 . . . . 1023 10.59 825 15.81 Granted . . . . . . . . . . . . . . . . . . . . . . 1591 10.79 1105 15.44 Forfeited . . . . . . . . . . . . . . . . . . . . . 133 10.51 72 15.74 Vested . . . . . . . . . . . . . . . . . . . . . . . 243 10.59 Outstanding at December 31 2013 . . . . 2238 10.74 1858 15.59 Granted . . . . . . . . . . . . . . . . . . . . . . 2113 10.80 1572 15.71 Forfeited . . . . . . . . . . . . . . . . . . . . . 412 10.90 184 15.48 Vested . . . . . . . . . . . . . . . . . . . . . . . 572 10.74 Outstanding at December 31 2014 . . . . 3367 10.76 3246 15.66 Granted . . . . . . . . . . . . . . . . . . . . . . 1539 8.37 3544 12.96 Forfeited . . . . . . . . . . . . . . . . . . . . . 254 10.14 212 14.48 Vested . . . . . . . . . . . . . . . . . . . . . . . 1060 10.71 Outstanding at December 31 2015 . . . . 3592 9.79 6578 14.24 135 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 12. Equity-based Compensation Continued As of December 31 2015 total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is 51.3 million over a weighted average period of 1.8 years. For restricted stock awards and restricted stock units with a combination of market and service vesting criteria the number of common shares to be issued is determined by comparing the Companys total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 100 of the awards granted for restricted stock awards and up to 200 of the awards granted for restricted stock units. The grant date fair value of these awards ranged from 6.70 to 13.57 per award for restricted stock awards and 12.96 to 15.81 per award for restricted stock units. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 41.3 to 56.7 for restricted stock awards and 44.0 to 54.0 for restricted stock units. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.5 to 1.1 for restricted stock awards and 0.5 to 1.2 for restricted stock units. For profit units that were exchanged for restricted stock awards the significant assumptions used to calculate the fair values of the profit units granted as calculated using a binomial tree were as follows no dividend yield expected volatility ranging from approximately 25 to 66 risk-free interest rate ranging from 1.3 to 5.1 expected life ranging from 1.2 to 8.1 years and projected turnover rates ranging from 7.0 to 27.0 for employees and none for management. For profit units granted immediately prior to our initial public offering we utilized the midpoint of the range of the estimated offering price or 17.00 per share. In January 2016 we granted 1.7 million service vesting restricted stock units and 1.3 million market and service vesting restricted stock units to our employees under our long-term incentive plan. We expect to recognize approximately 10.6 million of non-cash compensation expense related to these grants over the next three years. 13. Income Taxes Kosmos Energy Ltd. is a Bermuda company that is not subject to taxation at the corporate level. We provide for income taxes based on the laws and rates in effect in the countries in which our operations are conducted. The relationship between our pre-tax income or loss from continuing operations and our income tax expense or benefit varies from period to period as a result of various factors which include changes in total pre-tax income or loss the jurisdictions in which our income is earned and the tax laws in those jurisdictions. 136 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 13. Income Taxes Continued The components of income before income taxes were as follows Years Ended December 31 2015 2014 2013 In thousands Bermuda . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62372 31787 26492 United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10652 15684 11872 Foreignother . . . . . . . . . . . . . . . . . . . . . . . . . . . 137156 594371 90574 Income before income taxes . . . . . . . . . . . . . . . . . 85436 578268 75954 The components of the provision for income taxes attributable to our income before income taxes consist of the following Years Ended December 31 2015 2014 2013 In thousands Current Bermuda . . . . . . . . . . . . . . . . . . . . . . . . . . . . . United States . . . . . . . . . . . . . . . . . . . . . . . . . . 15199 27167 14182 Foreignother . . . . . . . . . . . . . . . . . . . . . . . . . 29287 55322 70436 Total current . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44486 82489 84618 Deferred Bermuda . . . . . . . . . . . . . . . . . . . . . . . . . . . . . United States . . . . . . . . . . . . . . . . . . . . . . . . . . 8241 14403 2665 Foreignother . . . . . . . . . . . . . . . . . . . . . . . . . 102545 230812 85045 Total deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . 110786 216409 82380 Income tax expense . . . . . . . . . . . . . . . . . . . . . . . 155272 298898 166998 137 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 13. Income Taxes Continued Our reconciliation of income tax expense computed by applying our Bermuda statutory rate and the reported effective tax rate on income from continuing operations is as follows Years Ended December 31 2015 2014 2013 In thousands Tax at Bermuda statutory rate . . . . . . . . . . . . . . Foreign income taxed at different rates . . . . . . . . 94184 266993 127301 Change in valuation allowance1 . . . . . . . . . . . . 40600 16401 4065 Non-deductible and other items1 . . . . . . . . . . . 1885 8957 36664 Tax shortfall on equity-based compensation . . . . . 18603 6547 7098 Total tax expense . . . . . . . . . . . . . . . . . . . . . . . . . 155272 298898 166998 Effective tax rate2 . . . . . . . . . . . . . . . . . . . . . . . 182 52 220 1 We took all actions required to voluntarily relinquish the Ndian River Block and Fako Block in Cameroon therefore the deferred tax asset and its corresponding valuation allowance were written off in 2013. As of December 31 2012 we had a 40.1 million deferred tax asset and related valuation allowance which were written off during 2013. The write off of the deferred tax asset and the related valuation allowance does not have an impact on the income tax expense. 2 The effective tax rate during the years ended December 31 2015 2014 and 2013 was also impacted by losses of 153.5 million 159.9 million and 178.8 million respectively incurred in jurisdictions in which we are not subject to taxes and therefore do not generate any income tax benefits. As of December 31 2013 our Ghana operations were in a net deferred tax liability position. The Ghana net operating loss carryforward existing as of December 2012 was utilized during 2013. The effective tax rate for the United States is approximately 220 81 and 97 for the years ended December 31 2015 2014 and 2013 respectively. The effective tax rate in the United States is impacted by the effect of tax shortfalls related to equity-based compensation. The effective tax rate for Ghana is approximately 35 36 and 36 for the years ended December 31 2015 2014 and 2013 respectively. Our other foreign jurisdictions have a 0 effective tax rate because they reside in countries with a 0 statutory rate or we have experienced losses in those countries and have a full valuation allowance reserved against the corresponding net deferred tax assets. As discussed above in Note 2Accounting Policies we elected the prospective early adoption of ASU 2015-17 which requires all deferred taxes to be classified as long-term including any associated valuation allowances. Had we elected to adopt retrospectively the December 31 2014 balance sheet would have reflected 41.5 million and 399.6 million in long-term deferred tax assets and long-term deferred tax liabilities respectively and zero for current deferred tax assets and current deferred tax liabilities. Deferred tax assets and liabilities which are computed on the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. In assessing the realizability 138 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 13. Income Taxes Continued of deferred tax assets management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows December 31 2015 2014 In thousands Deferred tax assets Foreign capitalized operating expenses . . . . . . . . . . . . . . . 101823 60401 Foreign net operating losses . . . . . . . . . . . . . . . . . . . . . . . 14719 15548 Equity compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26095 36711 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22656 20657 Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . 165293 133317 Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116541 75941 Total deferred tax assets net . . . . . . . . . . . . . . . . . . . . . . . . 48752 57376 Deferred tax liabilities Depletion depreciation and amortization related to property and equipment . . . . . . . . . . . . . . . . . . . . . . . . 425183 322895 Unrealized derivative gains . . . . . . . . . . . . . . . . . . . . . . . 92549 92675 Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . 517732 415570 Net deferred tax asset liability . . . . . . . . . . . . . . . . . . . . . 468980 358194 The Company has recorded a full valuation allowance against the net deferred tax assets in Ireland Mauritania Morocco Portugal Senegal and Suriname. The net change in the valuation allowance of 40.6 million is due to additional losses generated in these countries. The Company has entered into various petroleum contracts in Morocco. These petroleum contracts provide for a tax holiday at a 0 tax rate for a period of 10 years beginning on the date of first production if any. The Company currently has recorded deferred tax assets of 57.6 million recorded at the Moroccan statutory rate of 30 which has a full valuation allowance. We will re-evaluate our deferred tax position upon entering the tax holiday period and at such time may reduce the statutory rate applied to the deferred tax assets in Morocco to the extent those deferred tax assets are realized within the tax holiday period. The Company has foreign net operating loss carryforwards of 53.6 million. Of these losses we expect 9.4 million 35.5 million 1.5 million 0.6 million and 0.5 million to expire in 2015 2016 2019 2021 and 2022 respectively and 6.1 million do not expire. All of these losses currently have offsetting valuation allowances. A subsidiary of the Company files a U.S. federal income tax return and a Texas margin tax return. In addition to the United States the Company files income tax returns in the countries in which the Company operates. The Company is open to U.S. federal income tax examinations for tax years 2012 through 2015 and to Texas margin tax examinations for the tax years 2010 through 2015. In addition 139 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 13. Income Taxes Continued the Company is open to income tax examinations for years 2011 through 2015 in its significant other foreign jurisdictions primarily Ghana. As of December 31 2015 the Company had no material uncertain tax positions. The Companys policy is to recognize potential interest and penalties related to income tax matters in income tax expense. 14. Net Income Loss Per Share In the calculation of basic net income per share participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income if any. We calculate basic net income per share under the two-class method. Diluted net income loss per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. The computation of diluted net income loss per share reflects the potential dilution that could occur if all outstanding awards under our LTIP were converted into common shares or resulted in the issuance of common shares that would then share in the earnings of the Company. During periods in which the Company realizes a loss from continuing operations securities would not be dilutive to net loss per share and conversion into common shares is assumed not to occur. Basic net income loss per share is computed as i net income loss ii less income allocable to participating securities iii divided by weighted average basic shares outstanding. The Companys diluted net income loss per share is computed as i basic net income loss ii plus diluted adjustments to income allocable to participating securities iii divided by weighted average diluted shares outstanding. Years Ended December 31 2015 2014 2013 In thousands except per share data Numerator Net income loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69836 279370 91044 Basic income allocable to participating securities1 . . . . . . . . . . . . . 3286 Basic net income loss allocable to common shareholders . . . . . . . . 69836 276084 91044 Diluted adjustments to income allocable to participating securities1 58 Diluted net income loss allocable to common shareholders . . . . . . . 69836 276142 91044 Denominator Weighted average number of shares outstanding Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 382610 379195 376819 Restricted stock awards and units12 . . . . . . . . . . . . . . . . . . . . . . 6924 Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 382610 386119 376819 Net income loss per share Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.18 0.73 0.24 Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.18 0.72 0.24 1 Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities 140 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 14. Net Income Loss Per Share Continued represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and therefore are excluded from the basic net income loss per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and therefore are excluded from the basic net income loss per common share calculation in periods we are in a net loss position. 2 For the years ended December 31 2015 2014 and 2013 we excluded 11.2 million 4.4 million and 13.9 million outstanding restricted stock awards and restricted stock units respectively from the computations of diluted net income per share because the effect would have been anti-dilutive. 15. Commitments and Contingencies From time to time we are involved in litigation regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty management believes none of these matters either individually or in the aggregate would have a material effect upon the Companys financial position however an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year. The Jubilee Field in Ghana covers an area within both the WCTP and DT petroleum contract areas. Consistent with the Ghanaian Petroleum Law the WCTP and DT petroleum contracts and as required by Ghanas Ministry of Petroleum it was agreed the Jubilee Field would be unitized for optimal resource recovery. Kosmos and its partners executed a comprehensive unitization and unit operating agreement the Jubilee UUOA to unitize the Jubilee Field and govern each partys respective rights and duties in the Jubilee Unit which was effective July 16 2009. Pursuant to the terms of the Jubilee UUOA the tract participations are subject to a process of redetermination. The initial redetermination process was completed on October 14 2011. As a result of the initial redetermination process our Unit Interest is 24.1. These consolidated financial statements are based on these re determined tract participations. Our unit interest may change in the future should another redetermination occur. The Company leases facilities under various operating leases that expire through 2019 including our office space. Rent expense under these agreements was 4.7 million 4.6 million and 4.1 million for the years ended December 31 2015 2014 and 2013 respectively. We currently have a commitment to drill one exploration well in Morocco and Senegal. In Morocco our partner is obligated to fund our share of the cost of the exploration well subject to a maximum spend of 120.0 million. Additionally we have 3D seismic requirements in Sao Tome and Morocco of 2750 square kilometers and 1200 square kilometers respectively. In June 2013 Kosmos Energy Ventures KEV a subsidiary of Kosmos Energy Ltd. signed a long term rig agreement with a subsidiary of Atwood Oceanics Inc. for the new build 6th generation drillship Atwood Achiever. KEV took delivery of the Atwood Achiever in September 2014. The rig agreement originally covered an initial period of three years at a day rate of approximately 0.6 million with an option to extend the agreement for an additional three year term. In September 2015 KEV amended the rig agreement effective October 1 2015 to extend the contract end date by one year and reduce the rate to approximately 0.5 million per day. KEV is currently evaluating its option to revert 141 KOSMOS ENERGY LTD. Notes to Consolidated Financial Statements Continued 15. Commitments and Contingencies Continued to the original day rate of approximately 0.6 million per day and original agreement end date of November 2017. If KEV exercises the option KEV would be required to make a rate recovery payment equal to the difference between the original day rate and the amended day rate multiplied by the number of days from the amendment effective date to the date the option is exercised plus certain administrative costs.. In November 2015 we entered into a line of credit agreement with one of our block partners whereby our partner may draw up to 30 million on the line of credit to pay their portion of costs under the petroleum agreement. Interest accrues on drawn balances at 7.875. The agreement matures on December 31 2017 or earlier if certain conditions are met. As of December 31 2015 there were no amounts outstanding under the agreement. Future minimum rental commitments under these leases at December 31 2015 are as follows Payments Due By Year1 Total 2016 2017 2018 2019 2020 Thereafter In thousands Operating leases2 . . . . . . . . . 12970 3230 3286 3323 3131 Atwood Achiever drilling rig contract3 . . . . . . . . . . . . . . 518862 181379 180883 156600 1 Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities including well commitments in our petroleum contracts. 2 Primarily relates to corporate office and foreign office leases. 3 Commitments calculated using the amended day rate of 0.5 million effective October 1 2015 excluding applicable taxes. 142 KOSMOS ENERGY LTD. Supplemental Oil and Gas Data Unaudited Net proved oil and gas reserve estimates presented were prepared by Ryder Scott Company L.P. RSC for the years ended December 31 2015 and 2014 and Netherland Sewell Associates Inc. NSAI for the year ended December 31 2013. RSC and NSAI are independent petroleum engineers located in Houston Texas and Dallas Texas respectively. RSC and NSAI have prepared the reserve estimates presented herein and meet the requirements regarding qualifications independence objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity accuracy and timeliness of data furnished to independent reserve engineers for their reserves estimation process. Net Proved Developed and Undeveloped Reserves The following table is a summary of net proved developed and undeveloped oil and gas reserves to Kosmos interest in the Jubilee Field and TEN development in Ghana. Oil Gas Total MMBbl Bcf MMBoe Net proved developed and undeveloped reserves at December 31 20121 . . . . . . . . . . . . . . . . . . . . . . 42 9 43 Extensions and discoveries . . . . . . . . . . . . . . . . . . . Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 1 8 Revision in estimate2 . . . . . . . . . . . . . . . . . . . . . 11 3 12 Purchases of minerals-in-place . . . . . . . . . . . . . . . . Net proved developed and undeveloped reserves at December 31 20131 . . . . . . . . . . . . . . . . . . . . . . 45 11 47 Extensions and discoveries3 . . . . . . . . . . . . . . . . . 26 6 27 Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 1 9 Revision in estimate4 . . . . . . . . . . . . . . . . . . . . . 11 2 10 Purchases of minerals-in-place . . . . . . . . . . . . . . . . Net proved developed and undeveloped reserves at December 31 20141 . . . . . . . . . . . . . . . . . . . . . . 73 14 75 Extensions and discoveries . . . . . . . . . . . . . . . . . . . Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 1 9 Revision in estimate5 . . . . . . . . . . . . . . . . . . . . . 10 1 10 Purchases of minerals-in-place . . . . . . . . . . . . . . . . Net proved developed and undeveloped reserves at December 31 20151 . . . . . . . . . . . . . . . . . . . . . . 74 14 76 Proved developed reserves1 December 31 2013 . . . . . . . . . . . . . . . . . . . . . . . . 36 10 38 December 31 2014 . . . . . . . . . . . . . . . . . . . . . . . . 43 9 45 December 31 2015 . . . . . . . . . . . . . . . . . . . . . . . . 50 10 52 Proved undeveloped reserves1 December 31 2013 . . . . . . . . . . . . . . . . . . . . . . . . 9 1 9 December 31 2014 . . . . . . . . . . . . . . . . . . . . . . . . 30 6 31 December 31 2015 . . . . . . . . . . . . . . . . . . . . . . . . 24 4 25 1 The sum of proved developed reserves and proved undeveloped reserves may not add to net proved developed and undeveloped reserves as a result of rounding. 143 2 The increase in proved reserves is a result of a 2.5 MMBbl increase associated with improved reservoir properties substantiated by drilling results and an 8.5 MMBbl increase associated with improved reservoir performance. 3 Discoveries are related to the TEN development being moved from unproved to proved during 2014. 4 The increase in proved reserves is a result of a 3 MMBbl increase associated with in-fill drilling results and an 8 MMBbl increase associated with field performance. 5 The increase in proved reserves is a result of a 2 MMBbl increase associated with in-fill drilling results and a 10 MMBbl increase associated with field performance for Jubilee partially offset by 2 MMBbl of negative revisions to the TEN development due to decreased pricing. Net proved reserves were calculated utilizing the twelve month unweighted arithmetic average of the first-day-of-the-month oil price for each month for Brent crude in the period January through December 2015. The average 2015 Brent crude price of 54.13 per barrel is adjusted for crude handling transportation fees quality and a regional price differential. Based on the crude quality these adjustments are estimated to be 0.41 per barrel for Jubilee therefore the adjusted oil price is 53.72 per barrel for Jubilee. TEN was not adjusted as it does not currently have any production to estimate a differential. This oil price is held constant throughout the lives of the properties. There is no gas price used because gas reserves are consumed in operations as fuel. Proved oil and gas reserves are defined by the SEC Rule 4.10a of Regulation S-X as those quantities of oil and gas which by analysis of geoscience and engineering data can be estimated with reasonable certainty to be commercially recovered under current economic conditions operating methods and government regulations. Inherent uncertainties exist in estimating proved reserve quantities projecting future production rates and timing of development expenditures. Capitalized Costs Related to Oil and Gas Activities The following table presents aggregate capitalized costs related to oil and gas activities Ghana Other1 Total In thousands As of December 31 2015 Unproved properties . . . . . . . . . . . . . . . . . . 264460 329050 593510 Proved properties . . . . . . . . . . . . . . . . . . . . . 2579158 2579158 2843618 329050 3172668 Accumulated depletion . . . . . . . . . . . . . . . . . . 858442 858442 Net capitalized costs . . . . . . . . . . . . . . . . . . . . 1985176 329050 2314226 As of December 31 2014 Unproved properties . . . . . . . . . . . . . . . . . . 252051 111666 363717 Proved properties . . . . . . . . . . . . . . . . . . . . . 2125590 2125590 2377641 111666 2489307 Accumulated depletion . . . . . . . . . . . . . . . . . . 716121 716121 Net capitalized costs . . . . . . . . . . . . . . . . . . . . 1661520 111666 1773186 1 Includes Africa excluding Ghana Europe and South America. 144 Costs Incurred in Oil and Gas Activities The following table reflects total costs incurred both capitalized and expensed for oil and gas property acquisition exploration and development activities for the year. Ghana Other1 Total In thousands Year ended December 31 2015 Property acquisition Unproved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6250 6250 Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exploration2 . . . . . . . . . . . . . . . . . . . . . . . . . . . 12441 367196 379637 Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . 462066 462066 Total costs incurred . . . . . . . . . . . . . . . . . . . . . . . 474507 373446 847953 Year ended December 31 2014 Property acquisition Unproved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exploration3 . . . . . . . . . . . . . . . . . . . . . . . . . . . 62813 167381 230194 Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . 316738 316738 Total costs incurred . . . . . . . . . . . . . . . . . . . . . . . 379551 167381 546932 Year ended December 31 2013 Property acquisition Unproved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13787 13787 Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61071 183213 244284 Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183635 183635 Total costs incurred . . . . . . . . . . . . . . . . . . . . . . . 244706 197000 441706 1 Includes Africa excluding Ghana Europe and South America. 2 Does not include reimbursement of costs associated with exploration expenses incurred in prior years which resulted in a 24.7 million gain on sale in 2015. 3 Does not include reimbursement of costs associated with exploration expenses incurred in prior years which resulted in a 23.8 million gain on sale in 2014. Standardized Measure for Discounted Future Net Cash Flows The following table provides projected future net cash flows based on the twelve month unweighted arithmetic average of the first-day-of-the-month oil price for Brent crude in the period January through December 2015. The average 2015 Brent crude price of 54.13 per barrel is adjusted for crude handling transportation fees quality and a regional price differential. Based on the crude quality these adjustments are estimated to be 0.41 per barrel for the Jubilee Field therefore the adjusted oil price is 53.72 per barrel for Jubilee. TEN was not adjusted as it does not currently have any production to estimate a differential. Because prices used in the calculation are average prices for that year the standardized measure could vary significantly from year to year based on market conditions that occur. The projection should not be interpreted as representing the current value to Kosmos. Material revisions to estimates of proved reserves may occur in the future development and production of the 145 reserves may not occur in the periods assumed actual prices realized are expected to vary significantly from those used and actual costs may vary. Kosmos investment and operating decisions are not based on the information presented but on a wide range of reserve estimates that include probable as well as proved reserves and on a wide range of different price and cost assumptions. The standardized measure is intended to provide a better means to compare the value of Kosmos proved reserves at a given time with those of other oil producing companies than is provided by comparing raw proved reserve quantities. Ghana In millions At December 31 2015 Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3998 Future production costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1362 Future development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 679 Future Ghanaian tax expenses1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 411 Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1546 10 annual discount for estimated timing of cash flows . . . . . . . . . . . . 377 Standardized measure of discounted future net cash flows . . . . . . . . . . . 1169 At December 31 2014 Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7412 Future production costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1466 Future development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1051 Future Ghanaian tax expenses1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1543 Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3352 10 annual discount for estimated timing of cash flows . . . . . . . . . . . . 969 Standardized measure of discounted future net cash flows . . . . . . . . . . . 2383 At December 31 2013 Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4921 Future production costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 617 Future development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 300 Future Ghanaian tax expenses1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1168 Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2836 10 annual discount for estimated timing of cash flows . . . . . . . . . . . . 599 Standardized measure of discounted future net cash flows . . . . . . . . . . . 2237 1 The Company is a tax exempted company incorporated pursuant to the laws of Bermuda. The Company has not been and does not expect to be subject to future income tax expense related to its proved oil and gas reserves levied at a corporate parent level. Accordingly the Companys Standardized Measure for the years ended December 31 2015 2014 and 2013 respectively only reflect the effects of future tax expense levied at an asset level in the Companys case future Ghanaian tax expense. 146 Changes in the Standardized Measure for Discounted Cash Flows Ghana In millions Balance at December 31 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2072 Sales and Transfers 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 754 Net changes in prices and costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95 Previously estimated development costs incurred during the period . . . . 123 Net changes in development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 Revisions of previous quantity estimates . . . . . . . . . . . . . . . . . . . . . . . . 804 Changes in production timing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Net changes in Ghanaian tax expenses1 . . . . . . . . . . . . . . . . . . . . . . . 32 Accretion of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 289 Changes in timing and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182 Balance at December 31 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2237 Sales and Transfers 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 756 Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 451 Net changes in prices and costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 291 Previously estimated development costs incurred during the period . . . . 115 Net changes in development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151 Revisions of previous quantity estimates . . . . . . . . . . . . . . . . . . . . . . . . 690 Net changes in Ghanaian tax expenses1 . . . . . . . . . . . . . . . . . . . . . . . 44 Accretion of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 306 Changes in timing and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174 Balance at December 31 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2383 Sales and Transfers 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 341 Net changes in prices and costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2842 Previously estimated development costs incurred during the period . . . . 417 Net changes in development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Revisions of previous quantity estimates . . . . . . . . . . . . . . . . . . . . . . . . 375 Net changes in Ghanaian tax expenses1 . . . . . . . . . . . . . . . . . . . . . . . 802 Accretion of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 341 Changes in timing and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Balance at December 31 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1169 1 The Company is a tax exempted company incorporated pursuant to the laws of Bermuda. The Company has not been and does not expect to be subject to future income tax expense related to its proved oil and gas reserves levied at a corporate parent level. Accordingly the Companys Standardized Measure for the years ended December 31 2015 2014 and 2013 respectively only reflect the effects of future tax expense levied at an asset level in the Companys case future Ghanaian tax expense. 147 KOSMOS ENERGY LTD. Supplemental Quarterly Financial Information Unaudited Quarter Ended March 31 June 30 September 30 December 31 In thousands except per share data 2015 Revenues and other income . . . . . . . . . . . . . . . . . . . 132557 121813 95318 121868 Costs and expenses . . . . . . . . . . . . . . . . . . . . . . . . . 185767 171615 27165 55903 Net income loss . . . . . . . . . . . . . . . . . . . . . . . . . . 78909 75192 60265 24000 Net income loss per share Basic1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.21 0.20 0.16 0.06 Diluted1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.21 0.20 0.15 0.06 2014 Revenues and other income . . . . . . . . . . . . . . . . . . . 237061 329166 138367 178144 Costs and expenses . . . . . . . . . . . . . . . . . . . . . . . . . 111309 191875 80776 79490 Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74969 56507 19123 128771 Net income per share Basic1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.20 0.15 0.05 0.34 Diluted1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.19 0.15 0.05 0.33 1 The sum of the quarterly earnings per share information may not add to the annual earnings per share information as a result of rounding. 148 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures Evaluation of Disclosure Controls and Procedures As of the end of the period covered by this report an evaluation of the effectiveness of the design and operation of the Companys disclosure controls and procedures as defined in Rule 13a-15e under the Securities Exchange Act of 1934 as amended the Exchange Act was performed under the supervision and with the participation of the Companys management including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate complete and timely. However a control system no matter how well conceived and operated can provide only reasonable not absolute assurance that the objectives of the control system are met. The design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be considered relative to their costs. Consequently no evaluation of controls can provide absolute assurance that all control issues and instances of fraud if any within our company have been detected. Based upon this evaluation our Chief Executive Officer and our Chief Financial Officer concluded that the Companys disclosure controls and procedures were effective as of December 31 2015 in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded processed summarized and reported within the time periods specified in the SECs rules and forms including that such information is accumulated and communicated to the Companys management including our Chief Executive Officer and our Chief Financial Officer to allow timely decisions regarding required disclosure. Evaluation of Changes in Internal Control over Financial Reporting There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that materially affected or are reasonably likely to materially affect our internal control over financial reporting. Managements Annual Report on Internal Control over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control has been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. All internal control systems have inherent limitations including the possibility of human error and the possible circumvention of or overriding of controls. The design of an internal control system is also based in part upon assumptions and judgments made by management. As a result even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared. Also projections of any evaluation of effectiveness to future periods are subject to the risk that internal control may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of management including our Chief Executive Officer and our Chief Financial Officer we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this report based on the framework in Internal ControlIntegrated Framework 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment our Chief Executive Officer and 149 our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Ernst Young LLP the independent registered public accounting firm that audited our consolidated financial statements included in this annual report on Form 10-K has issued an attestation report on the effectiveness of internal control over financial reporting as of December 31 2015 which is included in Item 8. Financial Statements and Supplementary Data. Item 9B. Other Information Disclosures Required Pursuant to Section 13r of the Securities Exchange Act of 1934 Under the Iran Threat Reduction and Syria Human Rights Act of 2012 which added Section 13r of the Exchange Act we are required to include certain disclosures in our periodic reports if we or any of our affiliates as defined in Rule 12b-2 under the Exchange Act knowingly engaged in certain specified activities during the period covered by the report. Because the Securities and Exchange Commission SEC defines the term affiliate broadly it includes any entity controlled by us as well as any person or entity that controls us or is under common control with us control is also construed broadly by the SEC. We are not presently aware that we and our consolidated subsidiaries have knowingly engaged in any transaction or dealing reportable under Section 13r of the Exchange Act during the fiscal quarter ended December 31 2015. In addition except as described below at the time of filing this annual report on Form 10-K we are not aware of any such reportable transactions or dealings by companies that may be considered our affiliates as to whether they have knowingly engaged in any such reportable transactions or dealings during such period. Upon the filing of periodic reports by such other companies for the fiscal quarter or fiscal year ended December 31 2015 as the case may be additional reportable transactions may be disclosed by such companies. As of December 31 2015 funds affiliated with The Blackstone Group Blackstone held approximately 25 of our outstanding common shares and funds affiliated with Warburg Pincus Warburg Pincus held approximately 31 of our outstanding common shares. We are also a party to a shareholders agreement with Blackstone and Warburg Pincus pursuant to which among other things Blackstone and Warburg Pincus each currently has the right to designate three members of our board of directors. Accordingly each of Blackstone and Warburg Pincus may be deemed an affiliate of us both currently and during the fiscal quarter ended December 31 2015. Disclosure relating to Warburg Pincus and its affiliates Warburg Pincus informed us of i the information reproduced below the SAMIH Disclosure regarding Santander Asset Management Investment Holdings Limited SAMIH and ii the information reproduced below the Endurance Disclosure regarding the Endurance International Group Endurance. Each of SAMIH and EIG are companies that may be considered affiliates of Warburg Pincus. Because we SAMIH and Endurance may be deemed to be controlled by Warburg Pincus we may be considered an affiliate of each of SAMIH and Endurance respectively for the purposes of Section 13r of the Exchange Act. SAMIH Disclosure Quarter ended December 31 2015 Santander UK plc Santander UK holds frozen savings accounts and one current account for two customers resident in the United Kingdom U.K. who are currently designated by the 150 United States U.S. for terrorism. The accounts held by each customer were blocked after the customers designation and have remained blocked and dormant throughout 2015. Revenue generated by Santander UK on these accounts is negligible. An Iranian national resident in the U.K. who is currently designated by the U.S. under the Iranian Financial Sanctions Regulations and the Weapons of Mass Destruction Proliferators Sanctions Regulations NPWMD holds a mortgage with Santander UK that was issued prior to any such designation. No further drawdown has been made or would be allowed under this mortgage although Santander UK continues to receive repayment installments. In 2015 total revenue in connection with the mortgage was approximately 3876 while net profits were negligible relative to the overall profits of Santander UK. Santander UK does not intend to enter into any new relationships with this customer and any disbursements will only be made in accordance with applicable sanctions. The same Iranian national also holds two investment accounts with Santander ISA Managers Limited. The funds within both accounts are invested in the same portfolio fund. The accounts have remained frozen during 2015. The investment returns are being automatically reinvested and no disbursements have been made to the customer. Total revenue for the Santander group in connection with the investment accounts was approximately 188 while net profits in 2015 were negligible relative to the overall profits of Banco Santander S.A. During the third quarter of 2015 two additional Santander UK customers were designated. First a UK national designated by the U.S. under the Specially Designated Global Terrorist SDGT sanctions program who is on the U.S. Specially Designated National SDN list. This customer holds a bank account which generated revenue of approximately 180 during the third and fourth quarter of 2015. The account is blocked. Net profits in the third and fourth quarter of 2015 were negligible relative to the overall profits of Santander. Second a UK national also designated by the U.S. under the SDGT sanctions program who is on the U.S. SDN list held a bank account. No transactions were made in the third and fourth quarter of 2015 and the account is blocked and in arrears. In addition during the fourth quarter of 2015 Santander UK has identified one additional customer. A UK national designated by the U.S. under the SDGT sanctions program who is on the U.S. SDN list held a bank account which generated negligible revenue during the fourth quarter of 2015. The account was closed during the fourth quarter of 2015. Net profits in the fourth quarter of 2015 were negligible relative to the overall profits of Banco Santander S.A. The SAMIH Disclosure relates solely to activities conducted by SAMIH and do not relate to any activities conducted by us. We have no involvement in or control over the activities of SAMIH any of its predecessor companies or any of its subsidiaries. Other than as described above we have no knowledge of the activities of SAMIH with respect to transactions with Iran and we have not participated in the preparation of the SAMIH Disclosure. We have not independently verified the SAMIH Disclosure are not representing to the accuracy or completeness of the SAMIH Disclosure and undertake no obligation to correct or update the SAMIH Disclosure. Endurance Disclosure Quarter ended December 31 2015 On December 2 2015 Endurance terminated a subscriber account the Subscriber Account that Endurance believes to be associated with Issam Shammout and Sky Blue Bird Aviation Shammout identified by the Office of Foreign Assets Control OFAC as a Specially Designated National SDN on May 21 2015 pursuant to 31 C.F.R. Part 594. The Subscriber Account was inadvertently migrated to Endurances servers following its acquisition of the assets of Arvixe LLC Arvixe on October 31 2014. Pursuant to the terms of the asset purchase 151 agreement between Endurance and Arvixe any customer accounts prohibited by OFAC were expressly excluded from the acquisition. Accordingly Endurance does not believe it took legal ownership of the Subscriber Account and no revenue was collected by Endurance in connection with the Subscriber Account since the date on which Shammout was added to the SDN list. Nonetheless upon identifying that the Subscriber Account had been migrated to its servers Endurance promptly suspended all services and terminated the Subscriber Account. Endurance reported the Subscriber Account to OFAC as potentially the property of a SDN subject to blocking pursuant to Executive Order 13224. As of January 25 2016 Endurance has not received any correspondence from OFAC regarding this matter. The Endurance Disclosure relates solely to activities conducted by Endurance and do not relate to any activities conducted by us. We have no involvement in or control over the activities of Endurance any of its predecessor companies or any of its subsidiaries. Other than as described above we have no knowledge of the activities of Endurance with respect to transactions with Iran and we have not participated in the preparation of the Endurance Disclosure. We have not independently verified the Endurance Disclosure are not representing to the accuracy or completeness of the Endurance Disclosure and undertake no obligation to correct or update the Endurance Disclosure. Disclosure relating to Blackstone and its affiliates Blackstone informed us of i the information reproduced below the Travelport Disclosure regarding Travelport Limited Travelport and ii the information produced below the Hilton Disclosure regarding Hilton Worldwide Holdings Inc. Hilton. Each of Travelport and Hilton are companies that may be considered affiliates of Blackstone. Because both we Travelport and Hilton may be deemed to be controlled by Blackstone we may be considered an affiliate of each of Travelport and Hilton respectively for the purposes of Section 13r of the Exchange Act. Travelport Disclosure Quarter ended September 30 2015 As part of our global business in the travel industry we provide certain passenger travel related Travel Commerce Platform and Technology Services to Iran Air. We also provide certain Technology Services to Iran Air Tours. All of these services are either exempt from applicable sanctions prohibitions pursuant to a statutory exemption permitting transactions ordinarily incident to travel or to the extent not otherwise exempt specifically licensed by the U.S. Office of Foreign Assets Control. Subject to any changes in the exemptlicensed status of such activities we intend to continue these business activities which are directly related to and promote the arrangement of travel for individuals. The gross revenue and net profit attributable to these activities in the quarter ended September 30 2015 were approximately 133000 and 94000 respectively. The Travelport Disclosure relates solely to activities conducted by Travelport and do not relate to any activities conducted by us. We have no involvement in or control over the activities of Travelport any of its predecessor companies or any of its subsidiaries. Other than as described above we have no knowledge of the activities of Travelport with respect to transactions with Iran and we have not participated in the preparation of the Travelport Disclosure. We have not independently verified the Travelport Disclosure are not representing to the accuracy or completeness of the Travelport Disclosure and undertake no obligation to correct or update the Travelport Disclosure. 152 Hilton Disclosure Quarter ended September 30 2015 During the fiscal quarter ended September 30 2015 an Iranian governmental delegation stayed at the Transcorp Hilton Abuja for one night. The stays were booked and paid for by the government of Nigeria. The hotel received revenues of approximately 5320 from these dealings. Net profit to Hilton from these dealings was approximately 495. Hilton believes that the hotel stays were exempt from the Iranian Transactions and Sanctions Regulations 31 C.F.R. Part 560 pursuant to the International Emergency Economic Powers Act IEEPA and under 31 C.F.R. Section 560.210 d. The Transcorp Hilton Abuja intends to continue engaging in future similar transactions to the extent they remain permissible under applicable laws and regulations. The Hilton Disclosure relates solely to activities conducted by Hilton and do not relate to any activities conducted by us. We have no involvement in or control over the activities of Hilton any of its predecessor companies or any of its subsidiaries. Other than as described above we have no knowledge of the activities of Hilton with respect to transactions with Iran and we have not participated in the preparation of the Hilton Disclosure. We have not independently verified the Hilton Disclosure are not representing to the accuracy or completeness of the Hilton Disclosure and undertake no obligation to correct or update the Hilton Disclosure. 153 PART III Item 10. Directors Executive Officers and Corporate Governance The information required by this item is incorporated herein by reference to the 2015 Proxy Statement which will be filed with the SEC not later than 120 days subsequent to December 31 2015. Item 11. Executive Compensation The information required by this item is incorporated herein by reference to the 2015 Proxy Statement which will be filed with the SEC not later than 120 days subsequent to December 31 2015. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters The information required by this item is incorporated herein by reference to the 2015 Proxy Statement which will be filed with the SEC not later than 120 days subsequent to December 31 2015. Item 13. Certain Relationships and Related Transactions and Director Independence The information required by this item is incorporated herein by reference to the 2015 Proxy Statement which will be filed with the SEC not later than 120 days subsequent to December 31 2015. Item 14. Principal Accounting Fees and Services The information required by this item is incorporated herein by reference to the 2015 Proxy Statement which will be filed with the SEC not later than 120 days subsequent to December 31 2015. 154 PART IV Item 15. Exhibits Financial Statement Schedules a The following documents are filed as part of this report 1 Financial statements The financial statements filed as part of the Annual Report on Form 10-K are listed in the accompanying index to consolidated financial statements in Item 8 Financial Statements and Supplementary Data. 2 Financial statement schedules Schedule ICondensed Parent Company Financial Statements Under the terms of agreements governing the indebtedness of subsidiaries of Kosmos Energy Ltd. for 2015 2014 and 2013 collectively KEL the Parent Company such subsidiaries are restricted from making dividend payments loans or advances to KEL. Schedule I of Article 5-04 of Regulation S-X requires the condensed financial information of the Parent Company to be filed when the restricted net assets of consolidated subsidiaries exceed 25 percent of consolidated net assets as of the end of the most recently completed fiscal year. The following condensed parent-only financial statements of KEL have been prepared in accordance with Rule 12-04 Schedule I of Regulation S-X and included herein. The Parent Companys 100 investment in its subsidiaries has been recorded using the equity basis of accounting in the accompanying condensed parent-only financial statements. The condensed financial statements should be read in conjunction with the consolidated financial statements of Kosmos Energy Ltd. and subsidiaries and notes thereto. The terms Kosmos the Company and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries unless the context indicates otherwise. Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no impact on our reported net income current assets total assets current liabilities total liabilities or shareholders equity. 155 KOSMOS ENERGY LTD. CONDENSED PARENT COMPANY BALANCE SHEETS In thousands except share data December 31 2015 2014 Assets Current assets Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74683 165894 Receivables from subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154 Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 469 435 Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75152 166483 Investment in subsidiaries at equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1759419 1474105 Deferred financing costs net of accumulated amortization of 8475 and 6404 respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7986 2846 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1842557 1643434 Liabilities and shareholders equity Current liabilities Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Accounts payable to subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1070 Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17629 11523 Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18710 11523 Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 498334 292952 Shareholders equity Preference shares 0.01 par value 200000000 authorized shares zero issued at December 31 2015 and December 31 2014 . . . . . . . . . . . . . . . Common shares 0.01 par value 2000000000 authorized shares 393902643 and 392443048 issued at December 31 2015 and 2014 respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3939 3924 Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1933189 1860190 Accumulated deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 564686 494850 Accumulated other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . 767 Treasury stock at cost 8812054 and 5555088 shares at December 31 2015 and 2014 respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46929 31072 Total shareholders equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1325513 1338959 Total liabilities and shareholders equity . . . . . . . . . . . . . . . . . . . . . . . . . . . 1842557 1643434 156 KOSMOS ENERGY LTD. CONDENSED PARENT COMPANY STATEMENTS OF OPERATIONS In thousands Years Ended December 31 2015 2014 2013 Revenues and other income Oil and gas revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total revenues and other income . . . . . . . . . . . . . . . . . . . . . . . . Costs and expenses General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85103 88789 84306 General and administrative recoveriesrelated party . . . . . . . . . . . 72543 78880 67865 Interest and other financing costs net . . . . . . . . . . . . . . . . . . . . . 49572 20559 9997 Other expenses net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 240 1319 54 Equity in earnings losses of subsidiaries . . . . . . . . . . . . . . . . . . . 7464 311157 64552 Total costs and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69836 279370 91044 Income loss before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . 69836 279370 91044 Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69836 279370 91044 157 KOSMOS ENERGY LTD. CONDENSED PARENT COMPANY STATEMENTS OF CASH FLOWS In thousands Years Ended December 31 2015 2014 2013 Operating activities Net income loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69836 279370 91044 Adjustments to reconcile net income loss to net cash provided by operating activities Equity in earnings losses of subsidiaries . . . . . . . . . . . . . . . . . 7464 311157 64552 Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75267 79741 69101 Amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3190 3188 3017 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2704 269 Changes in assets and liabilities Increase decrease in prepaid expenses and other . . . . . . . . . 34 89 149 Increase decrease due tofrom related party . . . . . . . . . . . . . 1224 3915 4134 Increase in accounts payable and accrued liabilities . . . . . . . . . 2721 10593 794 Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . 22700 58178 50405 Investing activities Investment in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 293545 208879 133066 Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . 293545 208879 133066 Financing activities Net proceeds from issuance of senior secured notes . . . . . . . . . . . 206774 294000 Purchase of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18110 11096 13101 Deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9030 1401 1720 Net cash provided by used in financing activities . . . . . . . . . . . . . 179634 281503 14821 Net increase decrease in cash and cash equivalents . . . . . . . . . . . 91211 130802 97482 Cash and cash equivalents at beginning of period . . . . . . . . . . . . . 165894 35092 132574 Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . 74683 165894 35092 158 Schedule II Kosmos Energy Ltd. Valuation and Qualifying Accounts For the Years Ended December 31 2015 2014 and 2013 Additions Charged to Charged Deductions Balance Costs and To Other From Balance Description January 1 Expenses Accounts Reserves December 31 2015 Allowance for doubtful receivables . . . . . . . Allowance for deferred tax asset . . . . . . . . 75941 40600 116541 2014 Allowance for doubtful receivables . . . . . . . Allowance for deferred tax asset . . . . . . . . 59540 16401 75941 2013 Allowance for doubtful receivables . . . . . . . Allowance for deferred tax asset . . . . . . . . 63605 28040 32105 59540 Schedules other than Schedule I and Schedule II have been omitted because they are not applicable or the required information is presented in the consolidated financial statements or the notes to consolidated financial statements. 3 Exhibits See Index to Exhibits on page 147 for a description of the exhibits filed as part of this report. 159 SIGNATURES Pursuant to the requirements of Section 13 or 15d of the Securities Act of 1934 the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. KOSMOS ENERGY LTD. Date February 22 2016 By s THOMAS P. CHAMBERS Thomas P. Chambers Senior Vice President and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934 this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Signature Title Date Chairman of the Board of Directorss ANDREW G. INGLIS and Chief Executive Officer Principal February 22 2016 Andrew G. Inglis Executive Officer s BRIAN F. MAXTED Director and Chief Exploration Officer February 22 2016 Brian F. Maxted Senior Vice President and Chiefs THOMAS P. CHAMBERS Financial Officer Principal Financial February 22 2016 Thomas P. Chambers Officer Senior Vice President and Chiefs PAUL M. NOBEL Accounting Officer Principal February 22 2016 Paul M. Nobel Accounting Officer s SIR RICHARD B. DEARLOVE Director February 22 2016 Sir Richard B. Dearlove s DAVID I. FOLEY Director February 22 2016 David I. Foley s YVES-LOUIS DARRICARRERE Director February 22 2016 Yves-Louis Darricarrere 160 Signature Title Date s DAVID B. KRIEGER Director February 22 2016 David B. Krieger s JOSEPH P. LANDY Director February 22 2016 Joseph P. Landy s PRAKASH A. MELWANI Director February 22 2016 Prakash A. Melwani s ADEBAYO O. OGUNLESI Director February 22 2016 Adebayo O. Ogunlesi s CHRIS TONG Director February 22 2016 Chris Tong s CHRISTOPHER A. WRIGHT Director February 22 2016 Christopher A. Wright 161 INDEX OF EXHIBITS Exhibit Number Description of Document Governing Documents 3.1 Certificate of Incorporation of the Company filed as Exhibit 3.1 to the Companys Registration Statement on Form S-1A filed March 23 2011 File No. 333-171700 and incorporated herein by reference. 3.2 Memorandum of Association of the Company filed as Exhibit 3.2 to the Companys Registration Statement on Form S-1A filed March 23 2011 File No. 333-171700 and incorporated herein by reference. 3.3 Bye-laws of the Company filed as Exhibit 4 to the Companys Registration Statement on Form 8-A filed May 6 2011 File No. 001-35167 and incorporated herein by reference. 4.1 Specimen share certificate filed as Exhibit 4.1 to the Companys Registration Statement on Form S-1A filed April 25 2011 File No. 333-171700 and incorporated herein by reference. Operating Agreements Ghana 10.1 Petroleum Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 22 2004 among the GNPC Kosmos Ghana and the E.O. Group filed as Exhibit 10.1 to the Companys Registration Statement on Form S-1A filed March 3 2011 File No. 333-171700 and incorporated herein by reference. 10.2 Operating Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 27 2004 between Kosmos Ghana and E.O. Group filed as Exhibit 10.2 to the Companys Registration Statement on Form S-1A filed March 3 2011 File No. 333-171700 and incorporated herein by reference. 10.3 Petroleum Agreement in respect of the Deepwater Tano Contract Area dated March 10 2006 among GNPC Tullow Ghana Sabre and Kosmos Ghana filed as Exhibit 10.3 to the Companys Registration Statement on Form S-1A filed March 3 2011 File No. 333-171700 and incorporated herein by reference. 10.4 Joint Operating Agreement in respect of the Deepwater Tano Contract Area Offshore Ghana dated August 14 2006 among Tullow Ghana Sabre Oil and Gas Limited and Kosmos Ghana filed as Exhibit 10.4 to the Companys Registration Statement on Form S-1A filed March 3 2011 File No. 333-171700 and incorporated herein by reference. 10.5 Assignment Agreement in respect of the Deepwater Tano Block dated September 1 2006 among Anadarko WCTP and Kosmos Ghana filed as Exhibit 10.5 to the Companys Registration Statement on Form S-1A filed March 3 2011 File No. 333-171700 and incorporated herein by reference. 10.6 Unitization and Unit Operating Agreement covering the Jubilee Field Unit located offshore the Republic of Ghana dated July 13 2009 among GNPC Tullow Kosmos Ghana Anadarko WCTP Sabre and E.O. Group filed as Exhibit 10.6 to the Companys Registration Statement on Form S-1A filed March 3 2011 File No. 333-171700 and incorporated herein by reference. 162 Exhibit Number Description of Document 10.7 Settlement Agreement dated December 18 2010 among Kosmos Ghana Ghana National Petroleum Corporation and the Government of the Republic of Ghana filed as Exhibit 10.32 to the Companys Registration Statement on Form S-1A filed April 14 2011 File No. 333-171700 and incorporated herein by reference. Morocco 10.8 Petroleum Agreement regarding the exploration for and exploitation of hydrocarbons in the area of interest named Boujdour Offshore dated May 3 2006 between ONHYM and Kosmos Morocco filed as Exhibit 10.14 to the Companys Registration Statement on Form S-1A filed March 3 2011 File No. 333-171700 and incorporated herein by reference. 10.9 Association Contract regarding the exploration for and exploitation of hydrocarbons in the Boujdour Offshore Block dated May 3 2006 between ONHYM and Kosmos Morocco filed as Exhibit 10.15 to the Companys Registration Statement on Form S-1A filed March 3 2011 File No. 333-171700 and incorporated herein by reference. 10.10 Memorandum of Understanding regarding a new petroleum agreement covering certain areas of the Boujdour Offshore Block dated September 27 2010 between ONHYM and Kosmos Morocco filed as Exhibit 10.16 to the Companys Registration Statement on Form S-1A filed March 3 2011 File No. 333-171700 and incorporated herein by reference. 10.11 Petroleum Agreement Regarding the Exploration for Exploitation of Hydrocarbons among Office National Des Hydrocarbures Et Des Mines acting on behalf of the Kingdom of Morocco Kosmos Energy Deepwater Morocco and Canamens Energy Morocco SARL in the area of interest named Essaouira Offshore dated September 9 2011 filed as Exhibit 10.12 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 10.12 Deed of Assignment in Petroleum Agreement for the Exploration for and Exploitation of Hydrocarbons in the zone of interest named Essaouira Offshore between Canamens Energy Morocco SARL and Kosmos Energy Deepwater Morocco dated December 19 2012 filed as Exhibit 10.13 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 10.13 Petroleum Agreement Regarding the Exploration for Exploitation of Hydrocarbons among Office National Des Hydrocarbures Et Des Mines acting on behalf of the Kingdom of Morocco Kosmos Energy Deepwater Morocco and Pathfinder Hydrocarbon Ventures Limited in the area of interest named Foum Assaka Offshore dated May 4 2011 filed as Exhibit 10.14 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 10.14 Deed of Assignment in Petroleum Agreement for the Exploration for and Exploitation of Hydrocarbons in the zone of interest named Foum Assaka Offshore between Pathfinder Hydrocarbon Ventures Limited and Kosmos Energy Deepwater Morocco dated June 11 2012 filed as Exhibit 10.15 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 163 Exhibit Number Description of Document 10.15 Petroleum Agreement Regarding the Exploration for Exploitation of Hydrocarbons among Office National Des Hydrocarbures Et Des Mines acting on behalf of the Kingdom of Morocco and Kosmos Energy Deepwater Morocco in the area of interest named Tarhazoute Offshore dated October 10 2013 filed as Exhibit 10.16 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 10.16 Petroleum Agreement Regarding the Exploration for Exploitation of Hydrocarbons between Office National Des Hydrocarbures Et Des Mines acting on behalf of the State and Kosmos Energy Offshore Morocco HC in the area of interest named Cap Boujdour Offshore dated July 7 2011 filed as Exhibit 10.27 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. Senegal 10.17 Hydrocarbon Exploration and Production Sharing Contract for the Cayar Offshore Profond between the Republic of Senegal and Petro-Tim Limited and Societe des Petroles du Senegal dated January 17 2012 filed as Exhibit 10.1 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2014 and incorporated herein by reference. 10.18 Hydrocarbon Exploration and Production Sharing Contract for the Saint Louis Offshore Profond between the Republic of Senegal and Petro-Tim Limited and Societe des Petroles du Senegal dated January 17 2012 filed as Exhibit 10.2 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2014 and incorporated herein by reference. 10.19 Deed of Transfer between La Societe Des Petroles Du Senegal Petrosen Timis Corporation Limited and Kosmos Energy Senegal concerning the Hydrocarbons Exploration and Production Sharing Contracts and Joint Operating Agreements covering the Cayar Offshore and Saint Louis Offshore Permits dated August 25 2014 filed as Exhibit 10.3 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2014 and incorporated herein by reference. Suriname 10.20 Production Sharing Contract for Petroleum Exploration Development and Production relating to Block 42 Offshore Suriname between Staatsolie Maatshappij Suriname N.V. and Kosmos Energy Suriname dated December 13 2011 filed as Exhibit 10.20 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 10.21 Production Sharing Contract for Petroleum Exploration Development and Production relating to Block 45 Offshore Suriname between Staatsolie Maatshappij Suriname N.V. and Kosmos Energy Suriname dated December 13 2011 filed as Exhibit 10.21 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 10.22 Deed of Assignment and Transfer relating to Blocks 42 and 45 Offshore Suriname between Kosmos Energy Suriname and Chevron Suriname Exploration Limited dated May 31 2012 filed as Exhibit 10.22 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 164 Exhibit Number Description of Document Mauritania 10.23 Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy Mauritania Block C8 dated April 5 2012 filed as Exhibit 10.17 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 10.24 Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy Mauritania Bloc C12 dated April 5 2012 filed as Exhibit 10.18 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 10.25 Exploration and Production Contract between The Islamic Republic of Mauritania and Kosmos Energy Mauritania Bloc C13 dated April 5 2012 filed as Exhibit 10.19 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 10.26 Deed of Novation and Assignment and Transfer dated March 25 2015 between Kosmos Energy Mauritania Chevron Mauritania Exploration Limited and SMHPM in relation to Block C8 filed as Exhibit 10.1 to the Companys Current Report on Form 8-K dated March 25 2015 and incorporated herein by reference. 10.27 Deed of Novation and Assignment and Transfer dated March 25 2015 between Kosmos Energy Mauritania Chevron Mauritania Exploration Limited and SMHPM in relation to Block C12 filed as Exhibit 10.1 to the Companys Current Report on Form 8-K dated March 25 2015 and incorporated herein by reference. 10.28 Deed of Novation and Assignment and Transfer dated March 25 2015 between Kosmos Energy Mauritania Chevron Mauritania Exploration Limited and SMHPM in relation to Block C13 filed as Exhibit 10.1 to the Companys Current Report on Form 8-K dated March 25 2015 and incorporated herein by reference. Ireland 10.29 Irish Continental ShelfPetroleum Exploration License No. 113 Frontier between the Minister for Communications Energy and Natural Resources Ireland and Kosmos Energy Ireland and Antrim Exploration Ireland Ltd dated August 28 2013 filed as Exhibit 10.23 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 10.30 Irish Continental ShelfPetroleum Exploration License No. 213 Frontier between the Minister for Communications Energy and Natural Resources Ireland and Kosmos Energy Ireland and Europa Oil and Gas Holdings Plc. dated August 23 2013 filed as Exhibit 10.24 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 10.31 Irish Continental ShelfPetroleum Exploration License No. 313 Frontier between the Minister for Communications Energy and Natural Resources Ireland and Kosmos Energy Ireland and Europa Oil and Gas Holdings Plc. dated August 23 2013 filed as Exhibit 10.25 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. 165 Exhibit Number Description of Document 10.32 Licensing Terms for Offshore Oil and Gas Exploration Development and Production 2007 relating to the Petroleum Exploration Licenses No. 113 No. 213 and No. 313 offshore Ireland filed as Exhibit 10.26 to the Companys Quarterly Report on Form 10-Q for the quarter ended September 30 2013 and incorporated herein by reference. Drilling Rigs 10.33 Deepwater Drilling Unit Contract Agreement dated as of June 9 2013 between Kosmos Energy Ventures and Alpha Offshore Drilling Services Company filed as Exhibit 10.3 to the Companys Quarterly Report on Form 10-Q for the quarter ended June 30 2013 and incorporated herein by reference. 10.34 Amendment No. 6 to Deepwater Drilling Unit Contract Agreement dated September 29 2015 between Kosmos Energy Ventures and Alpha Offshore Drilling Services Company filed as Exhibit 1.1 to the Companys Current Report on Form 8-K dated October 1 2015 and incorporated herein by reference. Financing Agreements 10.35 Intercreditor Agreement dated March 28 2011 among BNP Paribas Kosmos Finance International Kosmos Operating Kosmos International Kosmos Development Kosmos Ghana and the various financial institutions and others party thereto filed as Exhibit 10.20 to the Companys Registration Statement on Form S-1A filed April 25 2011 File No. 333-171700 and incorporated herein by reference. 10.36 Facility Agreement dated February 17 2012 among Kosmos Energy Finance International Kosmos Energy Operating Kosmos Energy International Kosmos Energy Development Kosmos Energy Ghana HC and International Finance Corporation filed as Exhibit 10.2 to the Companys Quarterly Report on Form 10-Q for the quarter ended March 31 2012 and incorporated herein by reference. 10.37 Deed of Transfer and Amendment dated February 17 2012 among Kosmos Energy Finance International Kosmos Energy Operating Kosmos Energy International Kosmos Energy Development Kosmos Energy Ghana HC BNP Paribas Citibank N.A. Credit Suisse International Societe Generale London Branch and International Finance Corporation filed as Exhibit 10.1 to the Companys Quarterly Report on Form 10-Q for the quarter ended March 31 2012 and incorporated herein by reference. 10.38 Deed of Guarantee and Indemnity dated as of November 23 2012 among Kosmos Energy Ltd. and Kosmos Energy Operating Kosmos Energy International Kosmos Energy Development Kosmos Energy Ghana HC and Kosmos Energy Finance International as Original Guarantors and BNP Paribas as Security and Intercreditor Agent filed as Exhibit 10.29 to the Companys Annual Report on Form 10-K for the year ended December 31 2012 and incorporated herein by reference. 10.39 Intercreditor Agreement dated as of November 23 2012 among Kosmos Energy Ltd. as HY Note Issuer and RCF Borrower Kosmos Energy Finance International as Original Senior Borrower BNP Paribas as Security Agent Security and Intercreditor Agent and Proceeds Agent and Standard Chartered Bank as RCF Agent filed as Exhibit 10.31 to the Companys Annual Report on Form 10-K for the year ended December 31 2012 and incorporated herein by reference. 166 Exhibit Number Description of Document 10.40 Multi-Currency Revolving Letter of Credit Facility Agreement dated as of July 3 2013 and amended and restated on July 29 2013 among Kosmos Energy Credit International as the Original Borrower Kosmos Energy Ltd. as the Original Guarantor and Societe Generale London Branch as the Original Lender Facility Agent Security Agent and Account Bank filed as Exhibit 10.1 to the Companys Quarterly Report on Form 10-Q for the quarter ended June 30 2013 and incorporated herein by reference. 10.41 Charge on Cash Deposits and Account Bank Agreement dated as of July 3 2013 among Kosmos Energy Credit International and Societe Generale London Branch as Security Agent and Account Bank filed as Exhibit 10.2 to the Companys Quarterly Report on Form 10-Q for the quarter ended June 30 2013 and incorporated herein by reference. 10.42 Deed of Amendment and Restatement relating to the Revolving Credit Facility Agreement dated March 14 2014 among Kosmos Energy Ltd. as Original Borrower certain of its subsidiaries listed therein as Original Guarantors Standard Chartered Bank as Facility Agent BNP Paribas as Security and Intercreditor Agent and the financial institutions listed therein as Original Lenders filed as Exhibit 10.1 to the Companys Quarterly Report on Form 10-Q for the quarter ended March 31 2014 and incorporated herein by reference. 10.43 Amendment Letter dated June 8 2015 supplemental to and amending the Revolving Credit Facility Agreement dated March 14 2014 among Kosmos Energy Ltd. as Original Borrower certain of its subsidiaries listed therein as Original Guarantors Standard Chartered Bank as Facility Agent BNP Paribas as Security and Intercreditor Agent and the financial institutions listed therein as Original Lenders filed as Exhibit 1.1 to the Companys Current Report on Form 8-K dated June 8 2015 and incorporated herein by reference. 10.44 Deed of Amendment and Restatement relating to the Facility Agreement and a Charge over Shares in Kosmos Energy Operating dated March 14 2014 among Kosmos Energy Finance International as Original Borrower Kosmos Energy Operating Kosmos Energy International Kosmos Energy Development and Kosmos Energy Ghana HC as Original Guarantors Kosmos Energy Holdings as Chargor and BNP Paribas as Facility Agent and Security Agent filed as Exhibit 10.2 to the Companys Quarterly Report on Form 10-Q for the quarter ended March 31 2014 and incorporated herein by reference. 10.45 Indenture dated as of August 1 2014 among the Company Kosmos Energy Operating Kosmos Energy International Kosmos Energy Development Kosmos Energy Ghana HC and Kosmos Energy Finance International Wilmington Trust National Association as trustee transfer agent registrar and paying agent and Banque Internationale a Luxembourg S.A. as Luxembourg listing agent transfer agent and paying agent including the Form of Notes filed as Exhibit 4.1 to the Companys Current Report on Form 8-K filed August 4 2014 File No. 001-35167 and incorporated herein by reference. 10.46 KEL Intercreditor and Security Sharing Agreement dated as of August 1 2014 among the Company BNP Paribas as security and intercreditor agent Standard Chartered Bank as RCF Agent and Wilmington Trust National Association as trustee transfer agent registrar and paying agent filed as Exhibit 4.2 to the Companys Current Report on Form 8-K filed August 4 2014 File No. 001-35167 and incorporated herein by reference. 167 Exhibit Number Description of Document Agreements with Shareholders and Directors 10.47 Form of Director Indemnification Agreement filed as Exhibit 10.27 to the Companys Registration Statement on Form S-1A filed April 14 2011 File No. 333-171700 and incorporated herein by reference. 10.48 Shareholders Agreement dated as of May 10 2011 among Kosmos Energy Ltd. and the other parties signatory thereto filed as Exhibit 9.1 to the Companys Annual Report on Form 10-K for the year ended December 31 2012 and incorporated herein by reference. 10.49 Registration Rights Agreement dated as of October 7 2009 among Kosmos Energy Holdings and the other parties signatory thereto filed as Exhibit 10.32 to the Companys Annual Report on Form 10-K for the year ended December 31 2012 and incorporated herein by reference. 10.50 Joinder Agreement to the Registration Rights Agreement dated as of May 10 2011 among Kosmos Energy Ltd. and the other parties signatory thereto filed as Exhibit 10.33 to the Companys Annual Report on Form 10-K for the year ended December 31 2012 and incorporated herein by reference. 10.51 Amendment No. 1 to the Registration Rights Agreement dated as of February 8 2013 among Kosmos Energy Ltd. and the other parties signatory thereto filed as Exhibit 10.34 to the Companys Annual Report on Form 10-K for the year ended December 31 2012 and incorporated herein by reference. Management ContractsCompensatory Plans or Arrangements 10.52 Long Term Incentive Plan filed as Exhibit 99.1 to the Companys Registration Statement on Form S-8 filed May 16 2011 File No. 333-174234 and incorporated herein by reference. 10.53 Long Term Incentive Plan amended and restated as of January 23 2015 filed as Exhibit 99 to the Companys Registration Statement on Form S-8 filed October 2 2015 File No. 333-207259 and incorporated herein by reference. 10.54 Annual Incentive Plan filed as Exhibit 10.22 to the Companys Registration Statement on Form S-1A filed March 30 2011 File No. 333-171700 and incorporated herein by reference. 10.55 Form of Restricted Stock Award Agreement Service-Vesting filed as Exhibit 10.50 to the Companys Annual Report on Form 10-K for the year ended December 31 2014 and incorporated herein by reference. 10.56 Form of Restricted Stock Award Agreement Performance-Vesting filed as Exhibit 10.51 to the Companys Annual Report on Form 10-K for the year ended December 31 2014 and incorporated herein by reference. 10.57 Form of RSU Award Agreement Service-Vesting filed as Exhibit 10.52 to the Companys Annual Report on Form 10-K for the year ended December 31 2014 and incorporated herein by reference. 10.58 Form of RSU Award Agreement Performance-Vesting filed as Exhibit 10.13 to the Companys Quarterly Report on Form 10-Q for the quarter ended March 31 2015 and incorporated herein by reference. 168 Exhibit Number Description of Document 10.59 Form of Directors RSU Award Agreement Service-Vesting filed as Exhibit 10.54 to the Companys Annual Report on Form 10-K for the year ended December 31 2014 and incorporated herein by reference. 10.60 Separation and Release Agreement dated May 12 2014 between Kosmos Energy LLC and Darrell McKenna filed as Exhibit 10.4 to the Companys Quarterly Report on Form 10-Q for the quarter ended June 30 2014 and incorporated herein by reference. 10.61 Offer Letter dated September 1 2011 between Kosmos Energy LLC and Jason Doughty filed as Exhibit 10.1 to the Companys Quarterly Report on Form 10-Q for the quarter ended June 30 2014 and incorporated herein by reference. 10.62 Offer Letter dated May 22 2013 between Kosmos Energy LLC and Christopher Ball filed as Exhibit 10.2 to the Companys Quarterly Report on Form 10-Q for the quarter ended June 30 2014 and incorporated herein by reference. 10.63 Offer Letter dated January 10 2014 between Kosmos Energy LLC and Andrew Inglis filed as Exhibit 10.58 to the Companys Annual Report on Form 10-K for the year ended December 31 2013 and incorporated herein by reference. 10.64 Assignment Agreement dated April 16 2014 between Kosmos Energy LLC and Brian F. Maxted filed as Exhibit 10.3 to the Companys Quarterly Report on Form 10-Q for the quarter ended June 30 2014 and incorporated herein by reference. 10.65 Offer Letter dated October 16 2014 between Kosmos Energy LLC and Thomas P. Chambers filed as Exhibit 10.60 to the Companys Annual Report on Form 10-K for the year ended December 31 2014 and incorporated herein by reference. 10.66 Offer Letter dated February 11 2008 between Kosmos Energy LLC and Eric Haas filed as Exhibit 10.1 to the Companys Quarterly Report on Form 10-Q for the quarter ended June 30 2015 and incorporated herein by reference. 10.67 Kosmos Energy Ltd. Change in Control Severance Policy for U.S. Employees dated December 19 2013 filed as Exhibit 10.66 to the Companys Annual Report on Form 10-K for the year ended December 31 2013 and incorporated herein by reference. Other Exhibits 14.1 Code of Business Conduct and Ethics filed as Exhibit 14.1 to the Companys Annual Report on Form 10-K for the year ended December 31 2011 and incorporated herein by reference. 21.1 List of Subsidiaries. 23.1 Consent of Ernst Young LLP. 23.2 Consent of Ryder Scott Company L.P. 23.3 Consent of Netherland Sewell Associates Inc. 31.1 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 169 Exhibit Number Description of Document 32.2 Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.1 Report of Ryder Scott Company L.P. 101.INS XBRL Instance Document. 101.SCH XBRL Taxonomy Extension Schema Document. 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document. 101.LAB XBRL Taxonomy Extension Label Linkbase Document. 101.PRE XBRL Taxonomy Extension Presentation Linkbase Document. 101.DEF XBRL Taxonomy Extension Definition Linkbase Document. Filed herewith. Furnished herewith. Management contract or compensatory plan or arrangement. 170 CORPORATE INFORMATION CORPORATE OFFICE Clarendon House 2 Church Street Hamilton HM 11 Bermuda U.S. OFFICE Kosmos Energy Ltd. co Kosmos Energy LLC 8176 Park Lane Suite 500 Dallas TX 75231 WEBSITE www.kosmosenergy.com STOCK EXCHANGE LISTING New York Stock Exchange Symbol KOS ANNUAL MEETING June 16 2016 800 a.m. Atlantic Daylight Time Rosewood Tuckers Point 60 Tuckers Point Drive Hamilton Parish HS 02 Bermuda FORM 10-K Copies of the corporations 10-K are available on our website at www.kosmosenergy.com AUDITORS Ernst Young Dallas TX SHAREHOLDER SERVICES Computershare 250 Royall Street Canton MA 02021 1-800-962-4284 Toll-Free 1-781-575-3120 International INVESTOR RELATIONS Additional corporate information is available on our website at www.kosmosenergy.com FORWARD-LOOKING STATEMENTS This Annual Report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts included in this document that address activities events or developments that Kosmos expects believes or anticipates will or may occur in the future are forward-looking statements. Kosmos estimates and forward-looking statements are mainly based on its current expectations and estimates of future events and trends which affect or may affect its businesses and operations. Although Kosmos believes 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 Kosmos. When used in this document the words anticipate believe intend expect plan will or other similar words are intended to identify forward-looking statements. Such statements are subject to a number of assumptions risks and uncertainties many of which are beyond the control of Kosmos which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on such assumptions risks and uncertainties is available in Kosmos Securities and Exchange Commission SEC filings. Kosmos undertakes no obligation and does not intend to update or correct these forward-looking statements to reflect events or circumstances occurring after the date of this document except as required by applicable law. You are cautioned not to place undue reliance on these forward-looking statements which speak only as of the date of this document. All forward-looking statements are qualified in their entirety by this cautionary statement. Andrew G. Inglis Chairman of the Board of Directors Chief Executive Officer Brian F. Maxted Chief Exploration Officer Sir Richard B. Dearlove Retired Master of Pembroke College University of Cambridge Retired Head of the British Secret Intelligence Service MI6 David I. Foley Senior Managing Director Blackstone Group L.P. Chief Executive Officer Blackstone Energy Partners David B. Krieger Managing Director Warburg Pincus LLC Joseph P. Landy Co-President Warburg Pincus Company Prakash A. Melwani Senior Managing Director Blackstone Group L.P. Adebayo O. Ogunlesi Chairman and Managing Partner Global Infrastructure Partners Yves-Louis Darricarrre Retired Chief Executive Officer Total Upstream Senior Advisor Lazard Chris Tong Director Targa Resources Corp. Retired Chief Financial Officer Noble Energy Christopher A. Wright Retired Executive Chairman and Chief Executive Officer Fairfield Energy Limited BOARD OF DIRECTORS Andrew G. Inglis Chairman of the Board of Directors and Chief Executive Officer Brian F. Maxted Chief Exploration Officer Director Thomas P. Chambers Senior Vice President and Chief Financial Officer Michael Anderson Senior Vice President External Affairs Government Relations and Security Christopher J. Ball Senior Vice President Planning and Business Development Jason E. Doughty Senior Vice President General Counsel and Corporate Secretary Marvin M. Garrett Senior Vice President Drilling Eric J. Haas Senior Vice President Production and Development Paul M. Nobel Senior Vice President and Chief Accounting Officer SENIOR LEADERSHIP 8176 Park Lane Suite 500 Dallas TX 75231